File No. 70-______
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM U-1
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APPLICATION OR DECLARATION
UNDER
THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
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New England Electric System Eastern Utilities Associates
25 Research Drive One Liberty Square, P.O. Box 2333
Westborough, MA 01582 Boston, MA 02109
(Name of companies and top registered holding company parents filing
this statement and addresses of principal executive offices)
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Michael E. Jesanis Donald G. Pardus
Kirk L. Ramsauer Clifford J. Hebert, Jr.
New England Electric System Eastern Utilities Associates
25 Research Drive One Liberty Square, P.O. Box 2333
Westborough, MA 01582 Boston, MA 02109
(Name and addresses of agents for service)
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The Commission also is requested to send copies of any communications
in connection with this matter to:
Clifford M. Naeve, Esq. Arthur I. Anderson, P.C.
Judith A. Center, Esq. David A. Fazzone, P.C.
Kathleen A. Foudy, Esq. Amy J. Gould, Esq.
William C. Weeden McDermott, Will & Emery
Skadden, Arps, Slate, Meagher & Flom LLP 28 State Street
1440 New York Avenue, N.W. Boston, MA 02109-1775
Washington, D.C. 20005
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TABLE OF CONTENTS
Page
ITEM I: DESCRIPTION OF PROPOSED TRANSACTION....................................1
A. Description of the Parties to the Transaction........................1
1. General Request.................................................2
2. Overview of the Transaction.....................................5
B. Description of the Parties to the Transaction........................6
1. General Description.............................................6
a. NEES.......................................................6
b. EUA........................................................9
2. Description of Facilities......................................11
a. NEES......................................................11
i. General..............................................11
ii. Electric Generating Facilities and Resources.........11
iii. Electric Transmission Facilities.....................12
b. EUA.......................................................13
i. General..............................................13
ii. Electric Generating Facilities and Resources.........13
iii. Electric Transmission Facilities.....................14
3. Non-Utility Businesses.........................................14
a. NEES......................................................14
i. New England Hydro Finance Company, Inc...............14
ii. NEES Communications, Inc.............................14
iii. NEES Global..........................................15
iv. NEES Energy, Inc.....................................15
v. AllEnergy Marketing Company, L.L.C...................15
vi. Granite State Energy, Inc............................15
vii. Service Company..................................16
viii. New England Energy Incorporated..................16
ix. Metrowest Realty, LLC................................16
b. EUA.......................................................16
i. EUA Cogenex..........................................17
ii. EUA Energy...........................................18
iii. EUA Ocean State......................................19
iv. EUA Energy Services..................................19
v. EUA Telecommunications...............................19
vi. EUA Service..........................................19
vii. Eastern Edison Electric Company..................19
C. Description of Transaction..........................................19
1. Background.....................................................19
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2. Merger Agreement...............................................20
D. Management and Operations Following the Transaction.................21
ITEM II. FEES, COMMISSIONS AND EXPENSES......................................21
ITEM III. APPLICABLE STATUTORY PROVISIONS....................................22
A. Section 10(b).......................................................24
1. Section 10(b)(1)...............................................24
a. Interlocking Relations....................................25
b. Concentration of Control..................................25
i. Size ...............................25
ii. Competition and Antitrust Considerations.............27
2. Section 10(b)(2)...............................................28
a. Fairness of Consideration.................................28
b. Fairness of Fees..........................................30
3. Section 10(b)(3)...............................................30
a. Capital Structure.........................................31
b. Public Interest, Interest of Investors and Consumers,
and Proper Functioning of Holding Company System..........33
B. Section 10(c).......................................................33
1. Section 10(c)(1)...............................................33
a. Section 11(a) and Section 11(b)(2)........................34
b. Section 11(b)(1) (single integrated public utility
system)...................................................34
i. Interconnection......................................35
ii. Single Interconnected and Coordinated System.........35
iii. Single Area or Region ...............................37
iv. Localized Management, Efficient Operation and
Effective Regulation.................................37
c. Section 11(b)(1) (Acquisition of Non-Utility Interests)...37
2. Section 10(c)(2)...............................................38
C. Section 10(f).......................................................39
D. Service Agreement...................................................39
E. Organization of LLC; Acquisition of Merger LLC Interests............40
F. Financing and Other Commission Authorizations.......................40
1. Payment of Dividends Out of Capital or Unearned Surplus........40
2. Financing Arrangements.........................................44
a. Borrowings from Banks - Credit Agreement..................45
b. Cost of Funds.............................................45
c. Borrowings from Banks - Short-term........................45
d. Sale of Commercial Paper to Dealers.......................46
e. Filing of Certificates of Notification....................47
3. Rule 53 ...........................................................47
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ITEM IV. REGULATORY APPROVAL.................................................47
ITEM V. PROCEDURE............................................................48
ITEM VI. EXHIBITS AND FINANCIAL STATEMENTS...................................48
A. Exhibits............................................................48
B. Financial Statements................................................49
ITEM VII. INFORMATION AS TO ENVIRONMENTAL EFFECTS............................50
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ITEM I: DESCRIPTION OF PROPOSED TRANSACTION
A. Description of the Parties to the Transaction
This Form U-1 Application/Declaration ("Application/Declaration")
seeks approvals relating to the proposed combination of New England Electric
System ("NEES"), Eastern Utilities Associates ("EUA"), and Research Drive LLC
("LLC"), a Massachusetts limited liability company1 (the "Merger"). Pursuant to
the merger, LLC will merge with and into EUA, with EUA as the surviving entity,
and, therefore, a wholly-owned subsidiary of NEES. EUA subsequently will be
merged with and into NEES, with NEES as the surviving entity (together with the
Merger, the "Transaction"). Subsequent to the Transaction, NEES will remain a
registered holding company pursuant to the Public Utility Holding Company Act of
1935 (the "Act").
The Transaction will yield substantial benefits to investors,
consumers and the general public. It will create a merged company that will be
strong financially and well-equipped to meet increasing competition in wholesale
and retail power markets. In addition, NEES and EUA (collectively, the
"Applicants") consistently have been the two lowest-cost, major electric
companies in New England. The Transaction will generate efficiencies and cost
savings which will maintain low rates for customers of the merged companies. The
benefits of the Transaction are discussed in detail in Item III.B.2 below.
Pursuant to an Agreement and Plan of Merger, dated as of December 11,
1998, by and among The National Grid Group plc ("NGG"), NGG Holdings LLC, a
Massachusetts limited liability company and a wholly-owned subsidiary of NGG,
and NEES (the "NEES/NGG Merger Agreement"), NGG Holdings LLC will be merged with
and into NEES with NEES as the surviving entity (the "NEES/NGG Merger"). NGG, a
public limited company incorporated under the laws of England and Wales, owns
and operates the England and Wales high-voltage transmission network, including
interconnections with Scotland and France.
Under the terms of the NEES/NGG Merger Agreement (attached as Exhibit
B-1), NEES will become an indirect, wholly-owned subsidiary of NGG, which will
become a registered holding company under the Act. On March 25, 1999, as amended
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1 NEES owns ninety-nine percent of the voting securities of LLC and NEES
Global, Inc. ("NEES Global") owns the remaining one percent. NEES Global is
wholly-owned by NEES.
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on July 12, 1999, NEES and NGG filed an application/declaration with the
Commission requesting authority to undertake their merger.2 On May 3, 1999, NEES
shareholders approved the NEES/NGG Merger with 94 percent of the stock cast in
favor of the NEES/NGG Merger.
The Transaction which is the subject of this Application/Declaration
is not contingent upon consummation of the NEES/NGG Merger. However, the instant
Transaction has the full support of NGG. It is expected that the joint effect of
this Transaction and the NEES/NGG Merger will be the creation of a new
registered holding company, NGG, which will own a stronger, more efficient U.S.
electric utility business formed through the consolidation of NEES and EUA.3
1. General Request
In connection with the Transaction, Applicants, pursuant to Sections
6, 7, 9(a)(1), 10, 11, 12, and 13 of the Act and the rules thereunder, hereby
request authorizations and approvals from the Commission with respect to the
following:
o The acquisition by LLC of all of the issued and outstanding EUA
common shares, and the indirect acquisition of EUA common shares
by NEES through its wholly-owned subsidiary, LLC;
o The merger of NEES and EUA, with NEES being the surviving entity;
o The acquisition of common shares related to the mergers of
Eastern Edison Company ("Eastern Edison") and Massachusetts
Electric Company ("Mass. Electric"), with Mass. Electric being
the surviving entity; New England Power Company ("NEP") and
Montaup Electric Company ("Montaup")4, with NEP being the
surviving entity; and Blackstone Valley Electric Company
("Blackstone"), Newport Electric Corporation ("Newport"), and The
Narragansett Electric Company ("Narragansett"), with Narragansett
being the surviving entity;
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2 See Holding Co. Act Release No. 26994 (Mar. 31, 1999).
3 The effects of the merger of NEES and NGG in conjunction with the Trans
action are addressed at various points in this Application/Declaration.
4 See note 9, infra.
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o The indirect acquisition by NEES of EUA's non-utility businesses
through NEES' ownership of common shares or equity in those
non-utility businesses;
o The merger of EUA Service Corporation ("EUA Service") into New
England Power Service Company ("Service Company"), with Service
Company being the surviving service company, and the former EUA
companies entering into service agreements with Service Company
in the authorized form;
o The issuance of securities related to the mergers of Mass.
Electric and Eastern Edison; NEP and Montaup; and Narragansett,
Blackstone and Newport. The assumption by Mass. Electric of
Eastern Edison's pollution control revenue bonds and preferred
stock;
o If the NEES/NGG Merger has not been consummated prior to the
consummation of the Merger, approval of NEES' financing
arrangements with a syndicate of banks, and authority for NEES to
issue commercial paper or to engage in short term borrowing,
pursuant to which NEES may borrow up to $650.0 million aggregate
amount of debt outstanding at any one time, in addition to debt
borrowings currently authorized, for the purpose of consummating
the Transaction;
o The assumption by NEES of certain guarantees under various debt
instruments of EUA and its subsidiary companies (the "EUA
System"), including EUA's guaranty of the long-term debt of EUA
Cogenex Corporation ("EUA Cogenex"), EUA Cogenex's equity
maintenance agreement and EUA Cogenex's short-term debt under the
EUA System revolving credit line, and including EUA's guaranty of
the debt of EUA Ocean State Corporation ("EUA Ocean State");
o Following the merger of EUA into NEES, there will be a time
period before merger of EUA subsidiaries into NEES subsidiaries,
and during such time period, the participation of EUA
subsidiaries in the NEES money pool; and
o Payment of dividends out of capital surplus.
Applicants further request that the Commission grant such other authority as may
be necessary in connection with the Transaction.
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The Merger is subject to certain customary closing conditions,
including the receipt of the approval of EUA's shareholders by an affirmative
vote of two-thirds of the outstanding EUA shares. At a meeting of EUA's
shareholders on May 17, 1999, the Merger was approved by 76.2 percent of the
outstanding EUA shares authorized to vote, and by a total of 97 percent of the
votes cast at the meeting.
The Merger also requires receipt of the approval of: (i) the
Commission under the Act; (ii) the Federal Energy Regulatory Commission
("FERC"); (iii) the Nuclear Regulatory Commission ("NRC"); (iv) the Federal
Communications Commission ("FCC"); (v) the Vermont Public Service Board (the
"VPSB"); (vi) the Connecticut Department of Public Utility Control (the
"CDPUC"); and (vii) possibly the New Hampshire Public Utilities Commission
("NHPUC").5 Additionally, pursuant to Chapter 247 of the Acts of 1999 of the
General Assembly of State of Rhode Island and the Providence Plantations (99-H
6374 am), enacted July 1, 1999, the Rhode Island Division of Public Utilities
and Carriers ("RIDIV") must approve a merger of public utilities. Therefore, the
RIDIV has jurisdiction to approve the merger of Blackstone and Newport into
Narragansett.
Although the approval of the Massachusetts Department of
Telecommunications and Energy ("MDTE") is not required for the Transaction, the
MDTE has jurisdiction over the consolidation of the Massachusetts operating
companies and the rate plan for the combined operating companies. Although the
merger of the parent companies is not subject to the jurisdiction of the Rhode
Island Public Utilities Commission ("RIPUC"), the RIPUC has jurisdiction over
the retail rate plan associated with the combination of Blackstone and Newport
into Narragansett.6
Applicants also filed the requisite notification with the Federal
Trade Commission ("FTC") and the Department of Justice ("DOJ") under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the "HSR
Act"), and received clearance under the HSR Act on April 30, 1999.
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5 Montaup is a joint owner of the Seabrook Nuclear Plant in New Hampshire,
but has a contract to sell such ownership interest. Upon completion of that
sale, Montaup no longer would be regulated by the NHPUC, and, therefore,
NHPUC approval of the Transaction would not be required.
6 Copies of applications for the above-mentioned FERC, NRC and state
approvals are attached as Exhibits D-1 to D-7.
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2. Overview of the Transaction
Pursuant to an Agreement and Plan of Merger, dated as of February 1,
1999 (the "Merger Agreement"), LLC will be merged with and into EUA in
accordance with Section 2 of Chapter 182 and Sections 59 and 62 of Chapter 156C
of the Massachusetts General Laws. Upon the execution and filing of a
certificate of merger with the Secretary of the Commonwealth of Massachusetts by
EUA and LLC, or any later date specified by such certificate (the "Effective
Date"), the separate existence of LLC shall cease and EUA will be the surviving
entity.
Each one percent of the issued and outstanding membership interests in
LLC will be converted into one transferable certificate of participation or
share in EUA. All EUA shares that are owned by EUA as treasury shares and any
EUA shares owned by NEES or any other wholly-owned subsidiary of NEES will be
cancelled and retired and shall cease to exist, and no cash or other
consideration shall be delivered in exchange therefor. The remaining EUA shares
issued and outstanding immediately prior to the Effective Date will be cancelled
and converted into the right to receive cash in the amount of $31.00 per share
(the "Per Share Amount"), as such amount may be adjusted. If the closing of the
Merger and the transactions contemplated by the Merger Agreement (the "Closing")
have not taken place on or prior to November 17, 1999, the six month anniversary
of May 17, 1999, the date on which EUA shareholders' approval was obtained, (the
"Adjustment Date"), the Per Share Amount will be increased, for each day after
the Adjustment Date up to and including the day which is one day prior to the
earlier of the Closing and April 30, 2000, by an amount equal to $0.003.
If the NEES/NGG Merger has not been consummated prior to the
consummation of the Transaction, NEES intends to use available cash and funds
from borrowings as described hereinafter to consummate the Transaction. If the
NEES/NGG Merger has been consummated, NEES intends to use available cash and
funds received from capital contributions from, or issuance of equity to, NGG to
consummate the Transaction.
As soon as practicable after the Merger, NEES and EUA plan to merge
the NEES and EUA holding companies (with NEES becoming the surviving holding
company). In order to consolidate the underlying operating companies in each
state and the two service companies, Narragansett will merge with Blackstone and
Newport, with Narragansett the surviving company. Mass. Electric will merge with
Eastern Edison, with Mass. Electric the surviving company. NEP will merge with
Montaup, with NEP the surviving company. EUA Service and Service Company also
will be merged, with Service Company the surviving company.
<PAGE>
B. Description of the Parties to the Transaction
1. General Description
a. NEES
NEES was organized and exists as a voluntary association created under
the laws of the Commonwealth of Massachusetts on January 2, 1926. A copy of
NEES' Agreement and Declaration of Trust is incorporated by reference as Exhibit
A-1. NEES' principal executive office is located at 25 Research Drive,
Westborough, Massachusetts 01582.
NEES is a registered public utility holding company, and NEES and its
subsidiaries are subject to the broad regulatory provisions of the Act
administered by the Commission. Various NEES subsidiaries also are subject to
regulation by (i) the FERC under the Federal Power Act (the "FPA"), with respect
to wholesale sales and transmission of electric power, construction and
operation of hydroelectric projects, and accounting and other matters, and (ii)
various state regulatory commissions (as discussed below). In addition, the
activities of nuclear facilities in which NEES and its subsidiaries have
ownership interests are regulated by the NRC.
The common stock, par value of $1.00 per share, of NEES is listed on
the New York Stock Exchange and the Boston Stock Exchange. As of June 30, 1999,
there were 59,120,059 shares of NEES common stock outstanding. On a consolidated
basis at the end of 1998, NEES had total assets of $5.07 billion, net utility
assets of $2.5 billion, total operating revenues of $2.42 billion, utility
operating revenues of $2.24 billion, and net income of $190.0 million.
NEES owns all of the voting securities of the following four
distribution subsidiaries: Mass. Electric, Narragansett, Granite State Electric
Company ("Granite State"), and Nantucket Electric Company ("Nantucket")
(collectively, the "Electricity Delivery Companies"). NEES also owns 99.97
percent of the outstanding voting securities of its principal transmission
subsidiary, NEP. Together, the Electricity Delivery Companies and NEP constitute
a single integrated electric utility system (the "NEES System") that is directly
interconnected with other utilities in New England and New York State, including
EUA, and indirectly interconnected with utilities in Canada. The NEES System
covers more than 4,500 square miles with a population of approximately
3,000,000. At December 31, 1998, NEES and its subsidiaries had approximately
3,540 employees. A map marking the entire NEES service area is attached as
Exhibit E-4.
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Mass. Electric is a public utility company engaged in the delivery of
electricity to approximately 980,000 customers in an area comprising
approximately 43 percent of Massachusetts. The Mass. Electric service area
consists of 146 cities and towns, including the highly diversified commercial
and industrial cities of Worcester, Lowell and Quincy. The population of the
service area is approximately 2,160,000, or 36 percent of the total population
of the state. During 1998, 39 percent of Mass. Electric's revenues from the sale
of electricity was derived from residential customers, 39 percent from
commercial customers, 21 percent from industrial customers, and 1 percent from
others. In 1998, the utility's 20 largest customers accounted for approximately
7 percent of its electric revenues. At the end of 1998, Mass. Electric had total
assets of $1.45 billion, operating revenues of $1.5 billion and net income of
$49.4 million. Mass. Electric is subject to regulation by the FERC and the MDTE.
Narragansett is a public utility company engaged in the delivery of
electricity to approximately 335,000 customers in Rhode Island. Narragansett's
service territory, which includes urban, suburban and rural areas, covers
approximately 839 square miles, or 80 percent of the area of the state, and
encompasses 27 cities and towns, including Providence, East Providence,
Cranston, and Warwick. The population of the service area is approximately
725,000, which represents approximately 72 percent of the total population of
the state. During 1998, 44 percent of Narragansett's revenues from the sale of
electricity was derived from residential customers, 40 percent from commercial
customers, 14 percent from industrial customers, and 2 percent from others. In
1998, the 20 largest customers of Narragansett accounted for approximately 10
percent of its electric revenues. At the end of 1998, Narragansett had total
assets of $664.1 million, operating revenues of $475.7 million, and net income
of $30.5 million. Narragansett is subject to the regulation of the FERC, the
RIPUC and the RIDIV.
Granite State is a public utility company engaged in the delivery of
electricity to approximately 37,000 customers in 21 New Hampshire communities.
The Granite State service territory has a population of approximately 73,000 and
includes the Salem area of southern New Hampshire and several communities along
the Connecticut River. During 1998, 49 percent of Granite State's revenues from
the sale of electricity was derived from commercial customers, 36 percent from
residential customers, 14 percent from industrial customers, and 1 percent from
others. In 1998, the 10 largest customers of Granite State accounted for
approximately 18 percent of its electric revenues. At the end of 1998, Granite
State had total assets of $61.8 million, operating revenues of $65.7 million,
and net income of $3.2 million. Granite State is subject to the regulation of
the FERC and the NHPUC.
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Nantucket provides electric delivery service to approximately 10,000
customers on Nantucket Island, which has a year-round population of
approximately 6,000 and a seasonal tourist population that peaks at
approximately 40,000 during the summer. Nantucket's service area covers the
entire island. During 1998, 62 percent of Nantucket's revenues from the sale of
electricity was derived from residential customers, 37 percent from commercial
customers and 1 percent from others. At the end of 1998, Nantucket had total
assets of $44.0 million, operating revenues of $15.1 million, and net income of
$500,000. Nantucket is subject to the regulation of the FERC and the MDTE.
NEP is engaged in purchasing, transmitting and selling electric energy
at wholesale. In 1998, 98 percent of NEP's revenues from the sale of electricity
was derived from sales for resale to affiliated companies and 2 percent from
sales for resale to municipal and other utilities. NEP recently has completed
the sale of substantially all of its non-nuclear generating business and
currently is attempting to sell its minority interests in three operating
nuclear power plants and one fossil-fueled generating station in Maine.7 With
the sale of its non-nuclear generating business, NEP is principally an electric
transmission company. At the end of 1998, NEP had total assets of $2.41 billion,
operating revenues of $1.2 billion and net income of $121.5 million. NEP is
subject, for certain purposes, to regulation by the Commission, the FERC, the
NRC, the MDTE, the NHPUC, the VPSB, the CDPUC, and the Maine Public Utilities
Commission (the "MPUC").
New England Electric Transmission Corporation ("NEET") is a
wholly-owned subsidiary of NEES. NEET owns and operates a direct
current/alternating current converter terminal facility for the first phase of
the Hydro-Quebec and New England interconnection (the "Interconnection") and six
miles of high voltage direct current transmission line in New Hampshire. NEET,
Mass. Hydro (described below) and N.H. Hydro (described below) together own and
operate, on behalf of New England Power Pool ("NEPOOL") participants in the
second phase of the Interconnection, a 450 kV direct current transmission line
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7 NEP also is a holding company because it owns more than 10 percent of the
outstanding voting securities of Vermont Yankee Nuclear Power Corporation
("Vermont Yankee"), the licensed operator of the Vermont Yankee nuclear
facility. NEP also has minority interests in Yankee Atomic Electric Com
pany ("Yankee Atomic"), Maine Yankee Atomic Power Company ("Maine Yankee")
and Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), all of
which permanently have ceased operations. NEP is an exempt holding company
under the Act. Yankee Atomic Electric Company, Holding Co. Act Release No.
13048 (Nov. 25, 1955).
<PAGE>
and related terminals. As of December 31, 1998, NEET had total assets of $35.2
million, operating revenues of $9.6 million and net income of $813,000.
New England Hydro-Transmission Corporation ("N.H. Hydro"), in which
NEES holds 53.97 percent of the common stock, operates 121 miles of high-voltage
direct current transmission lines in New Hampshire for the second phase of the
Interconnection, extending to the Massachusetts border. At the end of 1998, N.H.
Hydro had total assets of $131.0 million, operating revenues of $31.7 million
and net income of $4.8 million.
New England Hydro-Transmission Electric Company, Inc. ("Mass. Hydro"),
53.97 percent of the voting stock of which is held by NEES, operates a direct
current/alternating current terminal and related facilities for the second phase
of the Interconnection and 12 miles of high-voltage direct current transmission
lines in Massachusetts. At the end of 1998, Mass. Hydro had total assets of
$160.0 million, operating revenues of $37.0 million and net income of $7.9
million.
LLC, a Massachusetts limited liability company, exists solely for the
purpose of effecting this Transaction by merging with and into EUA.
Narragansett, Mass. Electric , Granite State, and NEP (and a NEES
non-utility subsidiary, AllEnergy (described below)) are members of NEPOOL. The
FERC recently has approved a restructuring of NEPOOL involving (i) the formation
of an Independent System Operator ("ISO") that will control the transmission
facilities owned by the NEPOOL public utility members and administer the NEPOOL
open-access transmission tariff and (ii) the operation of a power exchange that
will embody a competitive power wholesale market. New England Power Pool, 85
FERC P. 61,379 (December 17, 1998).
b. EUA
EUA was organized and exists under a Declaration of Trust dated April
2, 1928, as amended, in the Commonwealth of Massachusetts. A copy of the EUA
Declaration of Trust, as amended, is incorporated by reference as Exhibit A-2.
EUA's principal executive office is located at One Liberty Square, P.O. Box
2333, Boston, Massachusetts 02109.
EUA operates as a registered holding company pursuant to the Act. At
the end of 1998, the EUA System served approximately 305,000 retail customers in
Massachusetts and Rhode Island. As a registered public utility holding company,
EUA and its subsidiaries are subject to the broad regulatory provisions of the
Act administered by the Commission. Various EUA subsidiaries also are subject to
<PAGE>
regulation by (i) the FERC under the FPA with respect to wholesale sales and
transmission of electric power, accounting and other matters and (ii) various
state regulatory commissions (as discussed below). In addition, the activities
of nuclear facilities in which EUA has ownership interests are regulated by the
NRC.
The common shares, par value of $5 per share, of EUA are listed on the
New York and Pacific Exchanges. As of July 31, 1999, there were 20,435,997 EUA
common shares outstanding. On a consolidated basis at the end of 1998, EUA had
total assets of $1.3 billion, net utility assets of $651.6 million, operating
revenues of $538.8 million, utility operating revenues of $480.1 million, net
income of $37.0 million, and utility net income of $37.4 million
EUA directly owns all of the common stock of the following electric
public utility companies: Blackstone, Eastern Edison and Newport. Eastern Edison
owns all of the outstanding securities of Montaup.8 As of December 31, 1998,
Blackstone, Eastern Edison, Newport, and Montaup together had 399 employees; EUA
Service had an additional 551 employees. A map marking the entire EUA service
area is attached as Exhibit E-4.
Blackstone was organized in 1912 under the laws of the State of Rhode
Island. Blackstone serves a territory of approximately 150 square miles in
portions of northern Rhode Island with a population of approximately 207,000. As
of December 31, 1998, Blackstone furnished retail electric service to
approximately 86,000 customers. At the end of 1998, Blackstone had total assets
of $134.1 million, operating revenues of $130.2 and net income of $4.9 million.
Blackstone is subject to the regulation of the FERC, the RIDIV and the RIPUC.
Eastern Edison was organized in 1883 under the laws of the
Commonwealth of Massachusetts. Eastern Edison supplies electric service in 22
cities and towns in southeastern Massachusetts. Eastern Edison's retail electric
service territory covers approximately 392 square miles and has an estimated
population of approximately 463,000. As of December 31, 1998, Eastern Edison
served approximately 186,000 retail customers. On a consolidated basis at the
end of 1998, Eastern Edison had total assets of $831.6 million, operating
revenues of $408.2 million and net income of $29.7 million. Eastern Edison is
subject to the regulation of the FERC and the MDTE.
Newport serves a territory of approximately 55 square miles and an
estimated population of approximately 70,000 in south coastal Rhode Island.
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8 See note 9, infra.
<PAGE>
Newport supplies retail electric service to approximately 33,000 customers. At
the end of 1998, Newport had total assets of $71.9 million, operating revenues
of $59.5 million and net income of $2.9 million. Newport is subject to the
regulation of the FERC, the RIDIV and the RIPUC.
Montaup, a subsidiary of Eastern Edison9, is a generation and
transmission company that supplies electricity at wholesale to Eastern Edison,
Blackstone, Newport, and two unaffiliated utilities. Consistent with the
electric utility industry restructuring legislation passed in Massachusetts and
Rhode Island and settlement agreements approved by regulators in those states
and at the FERC, Montaup has agreed to sell all of its generating assets and
transfer its non-nuclear power purchase contracts. Montaup has minority
ownership interests in Vermont Yankee, Connecticut Yankee, Maine Yankee, and
Yankee Atomic. Montaup also owns minority interests in Millstone 3 and Seabrook.
As noted above, Yankee Atomic, Connecticut Yankee and Maine Yankee permanently
have shut down operations. In addition, Montaup has agreed to sell its interests
in Seabrook and continues to attempt to sell its interests in Vermont Yankee and
Millstone 3. At the end of 1998 Montaup had total assets of $641.0 million,
operating revenues of $324.7 million and net income of $15.5 million. Montaup is
subject to the regulation of the FERC, and the NRC, and to limited regulation by
the MPUC, the CDPUC, the VPSB, the NHPUC and the MDTE.
2. Description of Facilities
a. NEES
i. General
For the year ending December 31, 1998, NEES and its utility
subsidiaries sold 25,413 million kWh of electric energy (at retail or
wholesale).
ii. Electric Generating Facilities and Resources
Pursuant to a settlement agreement with the RIPUC and a settlement
agreement approved by the MDTE in connection with the electric utility
- --------
9 Montaup currently is a subsidiary of Eastern Edison. However, on July 14
1999, EUA filed an application (File No. 70-9527) with the Commission
seeking authority for Eastern Edison to transfer to EUA, and for EUA to
acquire from Eastern Edison, all of Eastern Edison's investment in
Montaup's capitalization, so that EUA will become the direct parent of
Montaup.
<PAGE>
restructuring undertaken in their respective states, NEP and Narragansett
entered into an agreement to sell all their generating assets. On September 1,
1998, NEP and Narragansett completed the sale of substantially all of their
non-nuclear generating business to USGen New England, Inc. ("USGen"), an
indirect wholly-owned subsidiary of PG&E Corporation. The non-nuclear generating
business included three fossil-fueled and 15 hydroelectric generating stations,
totaling approximately 4,000 megawatts ("MW") of capacity, as well as NEES' 100
percent interest in Narragansett Energy Resources Company, a 20 percent general
partner in the Ocean State Power project, all of which had a book value of $1.1
billion at the time of sale. USGen also purchased NEP's entitlement to
approximately 1,100 MW of power procured under long-term contracts.
NEP currently owns interests in six nuclear generating facilities. As
noted above, the nuclear plants owned by Yankee Atomic, Maine Yankee and
Connecticut Yankee have been shut down permanently. NEP currently is attempting
to sell its minority ownership interests in three other nuclear power plants,
Vermont Yankee, Millstone 3 and Seabrook 1, and a 60 MW interest in a
fossil-fueled generating station in Maine. In February 1999, Vermont Yankee
entered into a letter of intent to sell its assets. Although the term of this
letter of intent has expired, Vermont Yankee is holding negotiations with two
parties regarding possible sale.
iii. Electric Transmission Facilities
As of December 31, 1998, NEP's integrated transmission system
consisted of 2,233 circuit miles of transmission lines, 110 substations with an
aggregate capacity of 12,535,789 kVA and 7 pole or conduit miles of distribution
lines.
As of December 31, 1998, Narragansett owned 327 circuit miles of
transmission lines, 224 substations with an aggregate capacity of 4,003,695 kVA,
49,475 line transformers with the capacity of 2,133,156 kVA, and 4,644 pole or
conduit miles of distribution lines.
As of December 31, 1998, Mass. Electric owned 83 circuit miles of
transmission lines, 247 substations with an aggregate capacity of 2,951,270 kVA,
147,571 line transformers with the capacity of 8,318,059 kVA, and 17,204 pole or
conduit miles of distribution lines.
<PAGE>
b. EUA
i. General
For the year ending December 31, 1998, EUA and its utility
subsidiaries sold 5,974 million kWh of electric energy (at retail or wholesale).
ii. Electric Generating Facilities and Resources
By the end of 1998, pursuant to settlement agreements approved by
federal and state regulators, EUA's utility affiliates signed agreements to sell
all of their non-nuclear power generation assets and power purchase agreements
to various non-affiliated parties in connection with electric utility
restructuring undertaken in Massachusetts and Rhode Island. At the end of 1998,
Montaup sold several diesel-powered generating units (totaling approximately 16
MW) owned by Newport to Illinois-based Wabash Power Equipment Company and its 50
percent share (approximately 280 MW) of Unit 2 of the Canal generating station
in Sandwich, Massachusetts to Southern Energy Canal, LLC, an indirect subsidiary
of The Southern Company. On April 7, 1998, Montaup entered into an agreement to
transfer power purchase contracts for approximately 170 MW of output from Ocean
State Power I and Ocean State Power II to TransCanada Power Marketing Ltd., an
indirect subsidiary of TransCanada Pipelines Limited; the transfer was effective
June 1, 1999. On December 21, 1998, Montaup entered into an agreement to
transfer purchase power contracts totaling approximately 177 MW to Constellation
Power Source, Inc., a wholly owned affiliate of the Baltimore Gas and Electric
Company; the transfer will become effective on September 1, 1999. On April 26,
1999, Montaup completed the sale of its 170 MW Somerset Generating Station,
located in Somerset, Massachusetts, to Somerset Power, LLC, an indirect
subsidiary of Northern States Power Company. In June of 1999, Montaup completed
the sale of its and Newport's combined 2.6 percent (approximately 16 MW) share
of the W.F. Wyman Unit 4 in Yarmouth, Maine to FPL Energy Wyman IV LLC, an
indirect subsidiary of the Florida-based FPL Group, Inc. Also in June of 1999,
Blackstone sold its hydroelectric facility in Pawtucket, Rhode Island
(approximately 1 MW) to Pawtucket Hydropower LLC, an affiliate of Putnam
Hydropower Inc.
In July 1999, in connection with Entergy Nuclear Generation Company's
acquisition of Pilgrim Station from Boston Edison, the power purchase agreement
(approximately 73 MW) between Montaup and Boston Edison was terminated. As a
condition of the termination, Montaup entered into a reduced term power purchase
contract for Pilgrim Station power with Entergy Nuclear Generation Company.
<PAGE>
Montaup also has agreed to sell its ownership interest in the Seabrook
Station nuclear power plant to Little Bay Power Corporation, a subsidiary of
BayCorp Holdings, Ltd., with an expected closing later in 1999. EUA's remaining
generating capacity comprises 58 MW from its ownership shares of the Millstone 3
and Vermont Yankee nuclear facilities. EUA actively is attempting to sell and/or
transfer its interests in the Vermont Yankee facility, and ultimately intends to
sell and/or transfer its interests in Millstone 3 as well. All of the sale and
contract transfer agreements are subject to federal and/or state regulatory
approvals, including that of the NRC with respect to the Seabrook sale.
iii. Electric Transmission Facilities
The EUA transmission system consists of approximately 7,100 miles of
transmission and distribution lines and 84 substations located in the cities and
towns served. Blackstone owns approximately 1,700 miles of transmission and
distribution lines and 26 substations. Eastern Edison and Montaup own
approximately 4,600 miles of transmission and distribution lines and 44
substations. Newport owns approximately 800 miles of transmission and
distribution lines and 14 substations.
3. Non-Utility Businesses
a. NEES
The following provides a summary of each of the non-utility companies
in which NEES has an ownership interest:
i. New England Hydro Finance Company, Inc.
New England Hydro Finance Company, Inc. ("N.E. Hydro Finance"), owned
in equal shares by Mass. Hydro and N.H. Hydro, provides the debt financing
required by Mass. Hydro and N.H. Hydro to fund the capital costs of their
participation in the Interconnection.
ii. NEES Communications, Inc.
NEES Communications, Inc. ("NEESCom") is a wholly-owned subsidiary of
NEES that provides telecommunications and information-related products and
services. NEESCom was established to allow NEES to participate in the growing
telecommunications industry. NEESCom, an exempt telecommunications company, is
not regulated under the Act and has a license issued by and is subject to
regulation by the FCC. NEESCom plans to focus on the fiber optics cable and
<PAGE>
infrastructure sectors of the telecommunications industry. At the end of 1998,
NEESCom had total assets of $12.6 million, operating revenues of $100,000 and a
net loss of $1.2 million.
iii. NEES Global
NEES Global is a wholly-owned non-utility subsidiary of NEES which
provides consulting services and product licenses to unaffiliated utilities in
the areas of electric utility restructuring and customer choice. NEES Global
also sells and leases water heaters through its wholly-owned subsidiary, New
England Water Heater Co., Inc. At the end of 1998, NEES Global had total assets
of $23.3 million, operating revenues of $5.0 million and a net loss of $1.1
million.
iv. NEES Energy, Inc.
NEES Energy, Inc. ("NEES Energy") is a wholly-owned marketing
subsidiary of NEES. At December 31, 1998, NEES Energy had total assets of $86.5
million, operating revenues of $171.4 million and a net loss of $13.0 million.
v. AllEnergy Marketing Company, L.L.C.
AllEnergy Marketing Company, L.L.C. ("AllEnergy") is an indirect,
wholly-owned subsidiary of NEES. NEES Energy owns 100 percent of the voting
securities of AllEnergy. AllEnergy, a member of NEPOOL, markets energy
commodities (natural gas, propane, and oil) and provides a wide range of
energy-related services, including but not limited to, marketing, brokering and
sales of energy, audits, fuel supply, repair, maintenance, construction,
operation, design, engineering, and consulting to customers in the competitive
power markets of New England and New York. AllEnergy also owns Texas Liquids
LLC, which is principally a propane and natural gas marketer with its home
office in New Jersey. On February 12, 1999, NEES and AllEnergy acquired Griffith
Consumers Company, a full service distributor of residential and commercial
heating oil in Washington, D.C., and in parts of Maryland, Delaware, Virginia,
and West Virginia. On June 14, 1999, AllEnergy agreed to buy Texas-Ohio Gas,
Inc., a unit of Denver-based New Century Energies that sells gas to about 3,000
commercial and industrial customers in the Northeast of the United States.
vi. Granite State Energy, Inc.
Granite State Energy, Inc. ("Granite State Energy") is a wholly-owned,
non-utility marketing subsidiary of NEES. Granite State Energy provides a range
of energy and energy-related services, including: sales of electric energy,
<PAGE>
audits, power quality, fuel supply, repair, maintenance, construction, design,
engineering, and consulting. At the end of 1998, Granite State Energy had total
assets of $300,000, operating revenues of $700,000, and no net income.
vii. Service Company
Service Company, wholly-owned by NEES, is a service company pursuant
to Section 13 of the Act. Service Company has contracted with NEES and its
subsidiaries to provide, at cost, such administrative, engineering,
construction, legal, and financial services as NEES and its subsidiaries request
pursuant to a service agreement approved by the Commission in accordance with
the requirements of Rule 90. At the end of 1998, Service Company had total
assets of $123.2 million and net income of $1.8 million.
viii. New England Energy Incorporated
As part of NEES' plan to divest its generating business, New England
Energy Incorporated ("NEEI"), wholly-owned by NEES, sold its oil and gas
properties in February 1998. NEEI primarily participated (principally through a
partnership with a non-affiliated oil company) in domestic oil and gas
exploration, development and production. NEEI also sold fuel purchased in the
open market to NEP. At the end of 1998, NEEI had total assets of $7.6 million
and a net loss of $100,000.
ix. Metrowest Realty, LLC
Metrowest Realty, LLC, wholly-owned by NEES, owns the headquarters
complex of NEES and its subsidiaries. The complex is located in Westborough,
Massachusetts. Metrowest Realty, LLC also owns the North Andover, Massachusetts
service center occupied by Mass. Electric.
b. EUA
EUA directly owns all of the common stock of the following non-utility
companies: EUA Cogenex, EUA Energy Investment Corporation ("EUA Energy"), EUA
Ocean State, EUA Energy Services, Inc. ("EUA Energy Services"), EUA
Telecommunications Corporation ("EUA Telecommunications"), and Eastern Edison
Electric Company. In addition, EUA directly owns all of the common stock of EUA
Service, a service company pursuant to Section 13 of the Act.
<PAGE>
i. EUA Cogenex
EUA Cogenex is an energy services company that employs energy
efficient technology and equipment intended to reduce the energy consumption and
costs of its customers. Such technology and equipment include: building
automation systems, lighting modifications, boiler and chiller replacements, and
other mechanical measures such as motors and drives. EUA Cogenex also serves
public and private multi-family housing through its subsidiary, EUA Citizens
Conservation Services, Inc., of which EUA Cogenex holds all voting control. In
addition, EUA Cogenex owns 100 percent of the voting stock of EUA Cogenex West
(formerly EUA Highland Corporation), an energy services company that provides
energy conservation services in Colorado, Texas, Ohio, North Carolina, and
certain mid-western states. EUA Cogenex also holds all voting control of
Northeast Energy Management, Inc., a demand side management company, and EUA
Cogenex-Canada, Inc. (which holds 100 percent voting control of EUA
Cogenex-Canada Energy Services, Inc., a company formed to participate in a
marketing and development joint venture with Monenco Agra, an Ontario-based
engineering firm). As of December 31, 1998, EUA Cogenex held 50 percent of the
voting control and acted as managing general partner of the following
partnerships which operate and monitor existing demand side management and/or
energy management services contractual obligations, but do not develop new
business: EUA WestCoast L.P., EUA Energy Capital and Services I, EUA Energy
Capital and Services II, EUA FRC II Energy Associates, and Micro Utility
Partners of America. As of December 31, 1998, EUA Cogenex also held 50 percent
of the voting power in APS Cogenex L.L.C., a limited liability company formed to
develop, engineer and construct projects at the National Cancer Institute in
Army Garrison at Fort Detrick, Maryland.
As of December 31, 1998, EUA Cogenex employed 187 persons in its
operations and had total consolidated assets of $157.2 million, operating
revenues of $54.8 million, and a net loss of $1.3 million. As of June 28, 1999,
the management of EUA Cogenex decided to divest certain of the non-core
businesses and activities of EUA Cogenex including EUA Citizens Conservation
Services, Inc. and the EUA/DAY and DAYMetrix divisions of EUA Cogenex. EUA
Cogenex has received an offer from the management of the EUA/DAY division to
purchase the business and assets of such division from EUA Cogenex. As a result
of this pending sale and the corresponding cessation of continued development of
DAYMetrix, its energy control software application and related technologies
division, EUA Cogenex recorded an after tax charge of $2.9 million in the second
quarter of 1999.
<PAGE>
ii. EUA Energy
EUA Energy invests in energy-related projects. EUA Energy wholly owns
Renova LLC ("Renova"), which was transferred from EUA Cogenex in May 1998.
Renova manufactures energy efficient fluorescent lighting products that maximize
lighting output and reduce energy consumption. EUA Energy also retains 100
percent voting power in: EUA BIOTEN, Inc. ("EUA BIOTEN"), which was formed to
develop biomass-fueled generating units and which owns 100 percent of the common
stock of BIOTEN Operations, Inc., a Tennessee corporation that owns a
demonstration facility in Red Boiling Springs, Tennessee; Eastern Unicord
Corporation, which was formed to invest in the construction of a wood burning
energy plant in Pembroke, New Hampshire; EUA Compression Services, Inc., which
was formed to provide compression stations along transmission lines; and EUA
TransCapacity, Inc., which was formed to develop and market services and
computer software enabling natural gas industry clients to connect, communicate
and coordinate with their trading partners via electronic data interchange. EUA
Energy also holds 9.9 percent of the voting power of Separation Technologies,
Inc., which markets and installs its own proprietary equipment for separating
unburned carbon from coal fly-ash.
At the end of 1998, EUA Energy had total assets of $30.4 million,
operating revenues of $3.9 million and a net loss of $5.3 million. EUA Energy is
attempting to negotiate strategic alliances with, or the sale of, its
energy-related investments, including EUA BIOTEN, Renova, and TransCapacity,
L.P., prior to the Merger. EUA BIOTEN has reached an agreement with the
management of BIOTEN Corp., a newly formed Delaware corporation that is not
affiliated with EUA BIOTEN, pursuant to which BIOTEN Corp.'s management will
have the option, through December 31, 1999, to purchase all the assets of EUA
BIOTEN. EUA BIOTEN recently received a letter of intent from a third party
which, among other things, would finance the purchase of EUA BIOTEN's assets by
BIOTEN Corp.'s management. As a result, EUA Energy recorded an after tax charge
to its earnings of approximately $9.4 million in the second quarter of 1999.
Similarly, EUA Energy recently received a letter of intent from the management
of Renova to purchase certain of its assets. As a result of this pending sale,
EUA Energy recorded an after tax charge to its earnings of approximately $3.5
million in the second quarter of 1999. EUA Energy plans to dissolve Eastern
Unicord Corporation and EUA Compression Services, Inc. prior to the Merger.
TransCapacity, L.P. ceased normal operations effective July 31, 1999.
<PAGE>
iii. EUA Ocean State
EUA Ocean State owns a 29.9 percent partnership interest in the
northern Rhode Island-based Ocean State generating station's two gas-fired
generating units, Ocean State Power I and Ocean State Power II. At the end of
1998, EUA Ocean State had total assets of $49.2 million and net income of $4.1
million.
iv. EUA Energy Services
EUA Energy Services markets energy and energy-related services. At the
end of 1998, EUA Energy Services had total assets of $500,000 and a net loss of
$200,000. EUA plans to dissolve EUA Energy Services prior to the Merger.
v. EUA Telecommunications
EUA Telecommunications was formed to provide telecommunications and
information services. At the end of 1998, EUA Telecommunications had total
assets of $70,000 and a net loss of $100,000. EUA plans to dissolve EUA
Telecommunications prior to the Merger.
vi. EUA Service
EUA Service is a service company pursuant to Section 13 of the Act.
EUA Service provides various accounting, financial, engineering, planning, data
processing, and other services to all EUA System companies in accordance with
the requirements of Rule 90. At the end of 1998, EUA Service had total assets of
$35.3 million and net income of $260,000.
vii. Eastern Edison Electric Company
Eastern Edison Electric Company was originally formed as part of EUA's
efforts to consolidate its subsidiaries. Eastern Edison Electric Company,
however, has been inactive for over six years and EUA plans to dissolve the
company prior to the Merger.
C. Description of Transaction
1. Background
In late May, 1998, the EUA board of trustees (the "EUA Board") met to
review EUA's strategic options for future operations. The EUA Board decided to
<PAGE>
open communications with selected electric utilities in the region in an attempt
to determine their interest in discussing some type of business combination. In
December 1998, EUA contacted NEES to explore NEES' interest in discussing a
possible business combination. After intensive negotiations between NEES and
EUA, the EUA Board held special meetings on January 31, 1999 and February 1,
1999, to review and consider the proposals received from NEES. After
presentations by the EUA Board's legal and financial advisors, and a full
discussion and analysis by the EUA Board, the EUA Board (1) determined that it
was in the best interests of EUA's shareholders, employees and customers for EUA
to enter into a business combination with NEES; (2) determined that the terms of
the Merger were fair to, and in the best interests of, EUA shareholders; and (3)
authorized, approved and adopted the proposed agreement and plan of merger and
the transaction contemplated by the Merger Agreement, and the execution and
delivery of the Merger Agreement. EUA was advised that NEES obtained the consent
of NGG to enter into the Merger Agreement, and on the morning of February 1,
1999, at the conclusion of the EUA Board meeting and prior to the opening of
markets, EUA and NEES executed and delivered the Merger Agreement.
2. Merger Agreement
The Merger Agreement provides for the merger of LLC with and into EUA,
with EUA as the surviving entity. The Merger Agreement is incorporated by
reference as Exhibit B-4.
Under the terms of the Merger Agreement, each outstanding common share
of EUA (and collectively, the "EUA Common Shares"), other than shares, if any,
owned by EUA as treasury shares, or by NEES, LLC or any other wholly-owned
subsidiary of NEES, will be converted into the right to receive cash in the
amount of $31.00 per share. If the Closing does not occur on or prior to the
Adjustment Date, then the per share amount will be increased by an amount equal
to $0.003 for each day after the Adjustment Date, up to and including the day
which is one day prior to the earlier of the Closing and April 30, 2000. The
Merger Agreement may be terminated under certain circumstances, some of which
provide for the payment of termination fees.
The Transaction is subject to customary closing conditions, including
the approval of the holders of two-thirds of the outstanding EUA Common Shares
and all necessary governmental approvals, including that of the Commission. The
Transaction has been approved by the NEES Board of Directors, the EUA Board and
the Members of LLC. On May 17, 1999, EUA shareholders approved the Merger, with
97 percent of the shareholders that voted casting ballots in favor of the
Merger.
<PAGE>
Because the acquisition of EUA is for cash, the conditions for pooling
of interest accounting are not met with regard to the Transaction. The
Transaction will be accounted for as a purchase in accordance with generally
accepted accounting principles. The conversion of EUA Common Shares into the
right to receive the Merger consideration pursuant to the Merger Agreement will
be treated as a taxable sale of such shares for United States federal income tax
purposes (and also may be a taxable transaction under applicable state, local,
foreign, and other tax laws).
D. Management and Operations Following the Transaction
As noted above, as soon as practicable after the Merger, NEES and EUA
plan to merge the NEES and EUA holding companies, with NEES as the surviving
holding company. Subject to the receipt of state regulatory approvals, as
necessary, Narragansett will merge with Blackstone and Newport, with
Narragansett the surviving company; Eastern Edison will merge with Mass.
Electric, with Mass. Electric the surviving company; and Montaup will merge with
NEP, with NEP the surviving company. Finally, to lower administrative costs, EUA
Service and Service Company will be consolidated, with Service Company the
surviving company. After the Merger, the surviving companies will be managed and
operated in a manner similar to the current operations.
ITEM II. FEES, COMMISSIONS AND EXPENSES
The fees, commissions and expenses that shall be paid or incurred,
directly or indirectly, in connection with the Transaction are estimated as
follows:
Thousands
Accountants' fees................................................. *
Legal fees and expenses........................................... *
Shareholder communication and proxy solicitation expenses......... *
NYSE listing fee.................................................. *
Pacific Stock Exchange listing fee................................ *
Exchanging, printing and engraving stock certificates expenses.... *
Investment bankers' fees and expenses............................. *
Consulting fees................................................... *
Miscellaneous .................................................... *
Total........................................................ *
(*) To be filed by amendment
The total fees, commissions and expenses expected to be incurred for
transaction and regulatory processing costs will be filed by amendment.
<PAGE>
ITEM III. APPLICABLE STATUTORY PROVISIONS
The following Sections of the Act and Commission rules relate to the
Transaction:
Section or Rule
Under the Act Action to Which Section or Rule Relates
6, 7 and rules thereunder Issuance of securities related to the
mergers of Eastern Edison with Mass.
Electric, Montaup with NEP, and Blackstone
and Newport with Narragansett. Assumption by
Mass. Electric of Eastern Edison's pollution
control revenue bonds, and preferred stock.
Borrowing by NEES of up to $650.0 million
under certain circumstances. NEES assumption
of guarantees under various debt instruments
of EUA System companies. Participation of EUA
subsidiaries in NEES money pool.
9, 10, 11, 12 and rules Acquisition by NEES of LLC and of EUA
thereunder Common Shares; indirect acquisition by NEES
of securities and interests in the business
of EUA's subsidiary companies, including the
non-utility subsidiaries; payments of
dividends out of capital surplus.
13 and rules thereunder Merger of EUA Service into Service Company
with Service Company as the surviving
service company.
Section 9(a)(1) of the Act provides that unless the acquisition has
been approved by the Commission under Section 10, it shall be unlawful for any
registered holding company or any subsidiary company thereof "to acquire,
directly or indirectly, any securities or utility assets or any other interest
in any business." Section 9(a)(1) is applicable to the proposed Transaction
because it involves the acquisition by NEES of EUA Common Shares, the indirect
acquisition by NEES of the securities of and interests in the businesses of
EUA's subsidiary companies, and the merger of EUA's utility subsidiaries into
NEES' utility subsidiaries.
<PAGE>
For the reasons set forth in detail below, the Transaction fully
complies with Section 10 of the Act:
o The Transaction will not create detrimental interlocking
relations or a detrimental concentration of control;
o The consideration and fees to be paid in connection with the
Transaction are fair and reasonable;
o The Transaction will not result in an unduly complicated capital
structure for the merged company;
o The Transaction is in the interests of the public, investors and
consumers;
o The merged company will be a single integrated public utility
system;
o The Transaction will result in an equitable distribution of
voting power among NEES' investors and does not unduly complicate
the structure of the holding company system;
o The Transaction tends toward the economical and efficient
development of an integrated electric utility system; and
o The Transaction will comply with all applicable state laws.
Pursuant to Sections 9 and 10, Congress entrusted the Commission with
the responsibility for "supervision over the future development of
utility-holding company systems." The Southern Co., Holding Co. Act Release No.
25639 (Sept. 23, 1992) ("Southern"). In Section 1(c), the Act directs the
Commission to interpret all provisions of the Act to address certain enumerated
problems and evils in order to protect the interests of the general public,
investors and consumers. As a result, the Commission's mandate under the Act is
"to prevent acquisitions which would be 'attended by the evils which have
featured the past growth of holding companies.'" American Elec. Power Co.,
Holding Co. Act Release No. 20633 (July 21, 1978) (quoting H.R. Rep. No. 1318,
74th Cong., 1st Sess. 16 (1935)). Such evils include the "growth and extension
of holding companies [that] bears no relation to economy of management and
operation or the integration and coordination of related operating properties."
Section 1(b)(4) of the Act.
The Transaction fully complies with the Act and does not prompt any of
the concerns that the Act was intended to address. In fact, the Transaction
<PAGE>
clearly promotes the goals of the Act by creating an integrated merged entity
that will benefit the interests of the general public, investors and consumers.
Both state and federal regulation will ensure that the interests of the public,
investors and consumers continue to be protected.
Set forth below are discussions of each of the subsections of Section
10 of the Act as they relate to the Transaction.
A. Section 10(b)
Section 10(b) of the Act provides that if the requirements of Section
10(f) are satisfied, the Commission must approve an acquisition under Section
9(a) unless the Commission finds that:
(1) such acquisition will tend towards interlocking relations or the
concentration of control of public-utility companies, of a kind
or to an extent detrimental to the public interest or the
interest of investors or consumers;
(2) in case of the acquisition of securities or utility assets, the
consideration, including all fees, commissions, and other
remuneration, to whomsoever paid, to be given, directly or
indirectly, in connection with such acquisition is not reasonable
or does not bear a fair relation to the sums invested in or the
earning capacity of the utility assets to be acquired or the
utility assets underlying the securities to be acquired; or
(3) such acquisition will unduly complicate the capital structure of
the holding-company system of the applicant or will be
detrimental to the public interest or the interest of investors
or consumers or the proper functioning of such holding-company
system.
1. Section 10(b)(1)
Under Section 10(b)(1) of the Act, the Commission shall approve a
proposed acquisition unless it finds that the proposed acquisition shall "tend
towards interlocking relations or the concentration of control of public utility
companies of a kind or to an extent detrimental to the public interest or the
interest of investors or consumers." Thus, Section 10(b)(1) does not prohibit a
merger merely because it causes interlocking relations or increases
concentration of control to some degree. Rather, a merger fails the balancing
test set forth in Section 10 only when any detrimental effects from any
<PAGE>
interlocking relations or concentration of control caused by the merger outweigh
the merger benefits.
a. Interlocking Relations
Any merger creates interlocking relations between previously unrelated
companies. As previously noted by the Commission: "[W]ith any addition of a new
subsidiary to a holding company system, the Acquisition will result in certain
interlocking relationships between [the two merging entities]." Northeast
Utilities, Holding Co. Act Release No. 25221 (Dec. 21, 1990), modified on other
grounds, Holding Co. Act Release No. 25273 (Mar. 15, 1991), aff'd sub nom. City
of Holyoke Gas & Elec. Dep't v. SEC, 972 F.2d 358 (D.C. Cir. 1992) ("Northeast
I"). Such "interlocking relationships are necessary to integrate [the two
merging entities.]" Id.
As noted above, immediately or shortly after consummation of the
Transaction, EUA will cease its corporate existence and its utility subsidiaries
will be merged into NEES' utility subsidiaries. Because EUA thus will be
completely merged into NEES and will end its independent existence, no concern
about interlocking relations is presented by the Transaction.
b. Concentration of Control
When considering the issue of concentration of control pursuant to
Section 10(b)(1), the Commission "considers various factors, including the size
of the resulting system and the competitive effects of the acquisition." Entergy
Corp., Holding Co. Act Release No. 25952 (Dec. 17, 1993), request for
reconsideration denied, Holding Co. Act Release No. 26037 (Apr. 28, 1994),
remanded sub nom. Cajun Elec. Power Coop. Inc. v. SEC, 1994 WL 704047 (D.C. Cir.
Nov. 16, 1994) ("Entergy").
i. Size
The NEES system following the acquisition of EUA's assets and
operations will serve approximately 1.67 million retail electric customers in
New England. Based on year-end 1998 figures, the system's annual operating
revenues will be approximately $2.96 billion (operating utility revenues of
approximately $2.72 billion); and its total assets will be approximately $6.37
billion (utility assets of approximately $3.14 billion).
The Commission has approved a number of mergers and acquisitions
involving utilities with combined assets and operations exceeding or
<PAGE>
approximately those of the NEES/EUA merged company. See, e.g., New Century
Energies, Inc., Holding Co. Act Release No. 26748 (Aug. 1, 1997) (merged company
assets of approximately $7 billion); Ameren Corp., Holding Co. Act Release No.
26809 (Dec. 30, 1997) (assets of $8.8 billion, utility assets of approximately
$6.6 billion); CINergy Corp., Holding Co. Act Release No. 26146 (Oct. 21, 1994)
(assets of approximately $8 billion, utility assets of approximately $6 billion)
("Cinergy").
Following the Transaction, NEES will be smaller than Northeast
Utilities, another registered holding company operating in New England, and, as
illustrated by the following table, will be among the smaller of the registered
holding companies.
Registered Holding Company Statistics
(as of December 31, 1998)
($MM)
<TABLE>
<CAPTION>
12 Months'
Consolidated Consolidated
Holding Company System Assets Rank Operating Earnings Rank
- ---------------------- ------ ---- ------------------ ----
<S> <C> <C> <C> <C>
Southern Co. (E) 36,192.0 1 11,403.0 2
Entergy Corp. (E) 22,848.0 2 11,494.8 1
American Electric Power Co. (E) 19,483.2 3 6,345.9 3
GPU Corp. (E) 16,288.1 4 4,248.8 7
Central and South West Corp. (E) 13,744.0 5 5,482.0 6
Northeast Utilities (E) 10,387.4 6 3,767.7 8
Cinergy Corp. (E)(G) 10,298.8 7 5,876.3 4
Ameren (E)(G) 8,847.4 8 3,318.2 10
New Century Energies (E)(G) 7,672.0 9 3,610.9 9
Columbia Energy Group (G) 6,968.7 10 5,731.8 5
Allegheny Energy, Inc. (E) 6,747.8 11 2,576.4 14
NEES/EUA (E) 6,373.2 12 2,959.3 12
Consolidated Natural Gas Co. (G) 6,361.9 13 2,760.4 13
Conectiv (E)(G) 6,100.0 14 3,100.0 11
Alliant Energy Corp. (E)(G) 4,959.0 15 2,131.0 15
National Fuel Gas Co. (G) 2,684.5 16 1,248.0 16
Unitil Co. (E)(G) 376.9 17 149.6 17
PECO Energy Power Co. (E) 118.0 18 18.5 18
Source:
Holding Companies Registered Under the Public Utility Holding Company Act of 1935 As of
July 1, 1999, Report of the Division of Investment Management, United States Securities
and Exchange Commission.
Legend
(E): Electric Utility
(G): Gas Utility
</TABLE>
<PAGE>
ii. Competition and Antitrust Considerations
The Commission's Section 10(b)(1) analysis also must include
consideration of federal antitrust policies.10 Were the Commission to determine
that an acquisition tends toward the concentration of control of public utility
companies, the Commission balances this effect against the benefits of the
acquisition to determine whether the acquisition meets the Section 10(b)(1)
standards. In the past, the Commission "has approved acquisitions that decrease
competition when it concludes that the acquisitions would result in benefits
such as possible economies of scale, elimination of the duplication of
facilities and activities, sharing of production capacity and reserves, and
generally more efficient operations." Northeast I, supra. The Commission also
has stated that the "antitrust ramifications of an acquisition must be
considered in light of the fact that public utilities are regulated monopolies
and that federal and state administrative agencies regulate the rates charged
consumers." Id.
The Commission has concurrent jurisdiction in assessing the
competitive impacts of the Transaction with the DOJ, the FTC, and the FERC.
Additionally, the MDTE may inquire into the effects of competition. Applicants
filed Notification and Report Forms with the DOJ and the FTC, which contain a
description of the Transaction's effects on competition, as required by the HSR
Act, and received clearance under the HSR Act on April 30, 1999. In addition, on
May 5, 1999, as amended on July 1, 1999, Applicants filed with the FERC a
request for approval of the Transaction pursuant to Section 203 of the Federal
Power Act. The FERC will evaluate the Transaction's competitive effects and will
approve the Transaction only upon finding that it is in the public interest and
will not adversely affect competition. Attached as Exhibit D-1 is Applicants'
FERC Application, which contains detailed discussions and testimony explaining
that the Transaction will not have any adverse effect on competition.
Specifically, in the FERC Application, and the testimony of Dr. Henry J. Kahwaty
attached hereto, Applicants explained that the Transaction does not create any
issues with respect to generation or transmission market power, or vertical
effects. In accordance with state electric restructuring legislation and
settlement agreements approved by the FERC and state regulators, both NEES and
EUA have divested nearly all of their generation assets and power purchase
contracts, and, therefore, neither NEES nor EUA has operational control over any
generation resources or the ability to increase generation prices. Because
transmission is provided under FERC regulated open-access tariffs, the
Transaction will not create any limitations on access to NEES or EUA
transmission facilities. In addition, no vertical issues are presented because
- --------
10 See, e.g., Conectiv, Inc., Holding Co. Act Release No. 26832 (Feb. 25,
1998) ("Conectiv").
<PAGE>
both NEES and EUA provide retail access to power suppliers under open delivery
tariffs.
The benefits accompanying the Transaction are outlined below in Item
III.B.2 and are benefits which the Commission has in other transactions weighed
against any concerns about concentration of control. See American Electric Power
Co., 46 S.E.C. Docket 1299 (1978). For all of these reasons, Applicants believe
that the Transaction will not result in a concentration of control which will be
detrimental to the public interest, but instead will offer the potential to
facilitate an actual increase in competition in regional electricity markets.
2. Section 10(b)(2)
Pursuant to Section 10(b)(2) of the Act, the Commission will approve
the Transaction unless it finds that "the consideration, including all fees,
commissions and other remuneration, ... is not reasonable or does not bear a
fair relation to the sums invested in or the earning capacity of the utility
assets to be acquired or the utility assets underlying the securities to be
acquired."
a. Fairness of Consideration
When determining whether consideration for an acquisition meets the
fair and reasonable test of Section 10(b)(2), the Commission considers various
factors. The Commission has considered: (i) the market price at which securities
have traded; (ii) whether the purchase price was decided as the result of
arm's-length negotiations; and (iii) whether each party's board of directors has
approved the purchase price. Finally, the Commission considers the opinions of
investment bankers, and the earnings, dividends and book and market value of the
shares of the company to be acquired. See American National Gas Co., 43 S.E.C.
203 (1966), Consolidated Natural Gas Co., Holding Co. Act Release No. 25040
(Feb. 14, 1990).
Under the standards applied by the Commission in previous utility
mergers, the consideration to be paid by NEES in the Transaction is reasonable
and bears a fair relation to the earnings capacity of the utility assets
underlying the EUA Common Shares to be acquired, in compliance with Section
10(b)(2).
Each of the EUA Common Shares will be converted into the right to
receive $31.00 per share in cash, plus the possible application of an upward
adjustment factor more fully discussed in the Merger Agreement. As shown in the
table below, the quarterly data, high and low, for EUA Common Shares provide
support for the consideration for each EUA Common Share.
<PAGE>
<TABLE>
<CAPTION>
Dividends
Paid Per
EUA High Low Common Share
1996
<S> <C> <C> <C>
First Quarter 24 1/4 20 5/8 $ 0.400
Second Quarter 21 7/8 18 1/2 0.415
Third Quarter 191/2 14 3/4 0.415
Fourth Quarter 171/2 16 0.415
1997
First Quarter 19 5/8 17 1/4 $ 0.415
Second Quarter 181/2 16 3/8 0.415
Third Quarter 19 15/16 18 7/16 0.415
Fourth Quarter 26 5/8 20 1/8 0.415
1998
First Quarter 27 11/16 23 11/16 $ 0.415
Second Quarter 27 3/8 24 7/16 0.415
Third Quarter 26 15/16 24 5/16 0.415
Fourth Quarter 28 1/4 24 5/8 0.415
</TABLE>
The $31.00 purchase price represents a 5 percent premium above EUA's closing
share price of $29.56 on January 29, 1999, the last trading day before the
Transaction was announced. The purchase price also represents a 23 percent
premium above the price of EUA's closing share price on December 4, 1998, the
last trading day before other regional merger announcements affected EUA's share
price.
Furthermore, Applicants' belief that the consideration is fair and
reasonable is based on the following additional considerations:
o The consideration is the product of extensive and vigorous arm's
length negotiations between NEES and EUA conducted in a
competitive context (see discussion of negotiations in Exhibit
K-1);
o The Merger has been approved by (i) the NEES Board of Directors,
the EUA Board, and the Members of LLC and (ii) 97 percent of the
EUA shareholders casting votes regarding the Merger.
o Internationally-recognized financial advisers for both NEES and
EUA have reviewed extensive information concerning the companies
<PAGE>
and analyzed a variety of valuation methodologies. An opinion
from NEES' financial adviser, Merrill Lynch & Co. (see Exhibit
F-1), states that the consideration to be paid by NEES with
respect to the Merger is fair, from a financial point of view, to
NEES. An opinion from EUA's financial adviser, Salomon Smith
Barney (see Exhibit F-2), states that the consideration to be
received by EUA's shareholders with respect to the Merger is
fair, from a financial point of view, to EUA's shareholders;
o The inclusion of required closing conditions in the Merger
Agreement serves to assure that the Merger will be consummated on
terms that are fair to Applicants and their shareholders.
b. Fairness of Fees
The various categories of fees, commissions and expenses in connection
with the transaction and regulatory processing costs for the Transaction are set
forth in Item II of this Application/Declaration. Applicants will file by
amendment the total amount of transaction and regulatory processing costs they
together expect to incur, and also will file by amendment the amount of
financial advisory fees they expect to incur.
Applicants believe that the estimated fees and expenses they will
incur will bear fair relation to EUA's value and the Transaction savings, and
will be fair and reasonable. See Northeast Utilities, Holding Co. Act Release
No. 25548 (June 3, 1992), modified on other grounds, Holding Co. Act Release No.
25550 (June 4, 1992) ("Northeast II") (Commission considers whether fees and
expenses bear a fair relation to the value of the company to be acquired and the
savings to be achieved by the acquisition). As discussed below at Item III.B.2,
the expected savings that will be achieved by the Transaction substantially will
outweigh the estimated fees. Furthermore, the estimated overall fees will be
reasonable as compared to the fees approved by the Commission in other merger
transactions.
For all of the above reasons, the consideration and fees to be paid
will be fair and reasonable in compliance with Section 10(b)(2).
3. Section 10(b)(3)
Section 10(b)(3) of the Act requires that the Commission approve an
acquisition unless "such acquisition will unduly complicate the capital
structure of the holding-company system ... or will be detrimental to the public
interest or the interest of investors or consumers or the proper functioning of
such holding-company system."
<PAGE>
a. Capital Structure
Acquisitions do not unduly complicate the capital structure of the
holding company system where the purchaser's capital structure negligibly is
affected and the debt-to-equity ratio of the merged holding company following
the acquisition falls within the seventy-to-thirty percent of debt-to-common
equity generally prescribed by the Commission. Entergy, supra (citing Northeast
I); Georgia Power Company, 45 S.E.C. 610, 615 (1974). Furthermore, the
Commission has approved common equity to total capitalization ratios as low as
27.6 percent. See Northeast I, supra.
The proposed combination of NEES and EUA will not unduly complicate
the capital structure of the merged company. NEES will finance the Transaction
with cash and funds received from capital contributions from, or issuance of
equity to, NGG, in the event the NEES/NGG Merger is consummated prior to the
Transaction, or cash received from the issuance of up to $650.0 million of debt
in the event the Transaction is consummated prior to the NEES/NGG Merger.
The historical capital structures of NEES and EUA, as well as of NGG,
as of March 31, 1999 are set forth below:
NEES, EUA and NGG Historical Capital Structures
(In Millions)
<TABLE>
<CAPTION>
NEES EUA NGG (c)
$ % $ % (pound) $ %
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term Debt (a) $1,089.1 40.0% $330.3 44.9% (pound)2,029.9 $3,247.8 53.8%
Preferred 19.5 0.7% 35.0 4.7% 0.0 0.0 0.0%
Common Equity 1,616.2 59.3% 371.1 50.4% 1,744.0 2,790.4 46.2%
------- ----- ----- ----- ------- ------- -----
Total Capitalization (b) $2,724.8 100.0% $736.4 100.0% (pound)3,773.9 $6,038.2 100.0%
======== ====== ====== ====== ======== ======== ======
</TABLE>
<PAGE>
The pro forma consolidated capital structures of (i) NEES and EUA and
(ii) NEES, EUA and NGG following the two acquisitions as of March 31, 1999 would
have been as follows:
<TABLE>
<CAPTION>
NEES/EUA Pro Forma Consolidated Capital Structure
(in Millions)
$ %
<S> <C> <C>
Long-term Debt (a) 1419.42 41.0%
Preferred 54.5 1.6%
Common Equity 1,987.3 57.4%
------- -----
Total Capitalization (b) 3,461.2 100.0%
======= ======
</TABLE>
<TABLE>
<CAPTION>
NGG/NEES/EUA Pro Forma Consolidated Capital Structure
(in Millions)
$ %
<S> <C> <C>
Long-term Debt (a) 4,667.2 49.1%
Preferred and
preference equity 54.5 0.6%
Common Equity 4,777.7 50.3%
------- -----
Total Capitalization (b) 9,499.4 100.0%
======= ======
</TABLE>
(a) NEES: Long-term debt includes long-term debt of $1,046.8 million and
long-term debt due within one year of $42.3 million for a total of $1,089.1
million. EUA: Long-term debt includes long-term debt of $308.4 million and
long-term debt due within one year of $21.9 million for a total of $330.3
million. NGG: Long-term debt includes long-term debt of (pound)1,637.3
million ($2,619.7 million) and long-term debt due within one year of
(pound)392.6 million ($628.2 million) for a total of (pound)2,029.9 million
($3,247.8 million).
(b) NEES: Capitalization includes capitalization per B.S. of $2,682.5 million
and long-term debt due within one year of $42.3 million for a total of
$2,724.8 million. EUA: Capitalization includes capitalization per B.S. of
$714.5 million and long-term debt due within one year of $21.9 million for
a total of $736.4 million.
(c) Exchange rate of (pound)/$1.60.
<PAGE>
As the above tables reveal, NEES' debt-to-equity ratio is not affected
by any material degree by the Transaction. The merged company's common equity to
total capitalization ratio significantly exceeds the Commission's traditionally
acceptable 30 to 35 percent level.
Since EUA will cease to exist shortly after consummation of the
Transaction and EUA's assets and operations will be merged into those of NEES,
there is no issue regarding minority ownership of common shares.
b. Public Interest, Interest of Investors and Consumers,
and Proper Functioning of Holding Company System
Section 10(b)(3) also requires the Commission to determine whether the
proposed Transaction will be detrimental to the interests of the general public,
investors or consumers, or the proper functioning of the combined system.
As set forth more fully below, the Transaction is expected to result
in substantial cost savings and synergies, and will integrate and improve the
efficiency of the combined utility systems. The Transaction, therefore, will be
in the public interest and the interests of investors and consumers, and will
not be detrimental to the proper functioning of the resulting holding company
system.
B. Section 10(c)
Section 10(c) of the Act establishes additional standards for approval
of the Transaction. Under Section 10(c), "the Commission shall not approve:
(1) an acquisition of securities or utility assets, or of any other
interest, which is unlawful under the provisions of Section 8 or
is detrimental to the carrying out of the provisions of Section
11; or
(2) the acquisition of securities or utility assets of a
public-utility or holding company unless the Commission finds
that such acquisition will serve the public interest by tending
towards the economical and efficient development of an integrated
public utility system."
1. Section 10(c)(1)
Section 10(c)(1) requires that an acquisition be lawful under the
provisions of Section 8 of the Act. Section 8 prohibits an acquisition by a
registered holding company of an interest in an electric and gas utility serving
substantially the same area without the express approval of the state commission
when that state's law prohibits or requires approval of the acquisition. As
<PAGE>
neither NEES nor EUA owns any interest in a gas utility, the provisions of
Section 8 are not applicable to the Transaction.
Section 10(c)(1) also requires that the Transaction not be detrimental
to the carrying out of the provisions of Section 11, specifically those
prohibiting unduly complex corporate structures and mandating integrated public
utility systems. The following analysis demonstrates that the Transaction fully
meets the standards of Section 11.
a. Section 11(a) and Section 11(b)(2)
Section 11(a) requires the Commission to examine the corporate
structure of registered holding companies to ensure that unnecessary
complexities are eliminated and voting powers are fairly and equitably
distributed. Similarly, Section 11(b)(2) of the Act requires that the Commission
"ensure that the corporate structure or continued existence of any company in
the holding-company system does not unduly or unnecessarily complicate the
structure, or unfairly or inequitably distribute voting power among security
holders, of such holding-company system." The Transaction fulfills the standard
imposed by Section 11(b)(2). The resulting capital structure will not be unduly
complicated, as discussed above. See, e.g., Sierra Pacific Resources, Holding
Co. Act Release No. 24566 (Jan. 28, 1988), aff'd, Environmental Action, Inc.,
895 F.2d 1255 (D.C. Cir. 1990) (Commission incorporates its Section 10(b)(3)
capital structure analysis into its Section 11(b)(2) corporate structure
analysis).
b. Section 11(b)(1) (single integrated public utility system)
An integrated public utility system, as applied to electric utility
companies, is defined in Section 2(a)(29)(A) of the Act as:
"a system consisting of one or more units of generating plants and/or
transmission lines and/or distributing facilities, whose utility assets,
whether owned by one or more electric utility companies, are physically
interconnected or capable of physical interconnection and which under
normal conditions may be economically operated as a single interconnected
and coordinated system confined in its operations to a single area or
region, in one or more States, not so large as to impair (considering the
state of the art and the area or region affected) the advantages of
localized management, efficient operation, and the effectiveness of
regulation;"
<PAGE>
Pursuant to the above definition, the Commission has established four
criteria that must be satisfied before the Commission finds that an integrated
electric public utility system will result from a proposed merger of two
separate systems:
(i) the utility assets of the systems are physically interconnected
or capable of physical interconnection;
(ii) the utility assets, under normal conditions, must be economically
operated as a single interconnected and coordinated system;
(iii) the system must be confined in its operations to a single area
or region; and
(iv) the system must not be so large as to impair (considering the
state of the art and the area or region affected) the advantages
of localized management, efficient operation, and the
effectiveness of regulation.
See, e.g., Environmental Action, Inc. v. SEC, supra (citing In re Electric
Energy Inc., 38 S.E.C. 658, 668 (1958)). As demonstrated below, the Transaction
meets each of these standards.
i. Interconnection
The NEES and EUA systems are adjacent to each other and their
transmission lines are directly physically interconnected; power is exchanged
presently between EUA and NEES. See Exhibit E-4. In addition, NEES and EUA are
interconnected via the NEPOOL transmission network, which is administered by an
ISO that assures open-access transmission services for the New England
marketplace at a uniform flat rate. The Commission has recognized that power
pools and ISOs can provide a mechanism for satisfying the physical
interconnection requirement of the Act. See, e.g., Conectiv; Unitil Corp.,
Holding Co. Act Release No. 25524 (Apr. 24, 1992).
ii. Single Interconnected and Coordinated System
The merged company will operate as a single interconnected and
coordinated system, pursuant to the requirements of Section 2(a)(29)(A). The
Commission has "interpreted this language to refer to the physical operation of
utility assets as a system in which, among other things, the generation and/or
flow of current within the system may be centrally controlled and allocated as
need or economy directs." Conectiv, supra (citing North American Co., 11 S.E.C.
194, 242 (1942), aff'd, SEC v. North American Co., 133 F.2d 148 (2d Cir. 1943),
aff'd on constitutional issues, 327 U.S. 686 (1946)). In enacting this standard,
Congress "intended that the utility properties be so connected and operated that
<PAGE>
there is coordination among all parts, and that those parts bear an integral
operating relationship to one another." Id. (citing Cities Services Co., 14
S.E.C. 28, 55 (1943)).
NEES' and EUA's utility operations will be consolidated fully into
existing NEES utility subsidiaries, which will continue to operate on a fully
integrated basis. In addition, NEES' operations will be coordinated via NEPOOL
and the new ISO-managed bulk power system, which will administer a market-driven
dispatch framework that matches loads with resources bid into the system by
generators and suppliers.
The NEES system will continue to be coordinated in a variety of other
ways, e.g. by way of centralized accounting and financial systems, information
system networks, strategic planning, etc. The Commission, in applying the
integration standard, looks beyond simply the coordination of day-to-day utility
operations to a broader range of corporate functions and activities. See, e.g.,
General Public Utilities Corp., Holding Co. Act Release No. 13116 (Mar. 2, 1956)
(integration is accomplished through power dispatching by a central load
dispatcher as well as through coordination of maintenance and construction
requirements); Middle South Utilities, Holding Co. Act Release No. 11782 (March
20, 1953), petition to reopen denied, Holding Co. Act Release No. 12978 (Sept.
13, 1955), rev'd sub nom. Louisiana Public Service Comm'n v. SEC, 235 F.2d 167
(5th Cir. 1956), rev'd, 353 U.S. 368 (1957), reh'g denied, 354 U.S. 928 (1957)
(integration is accomplished through an operating committee which coordinates
not only the scheduling of generation and system dispatch, but also makes and
keeps records and necessary reports, coordinates construction programs and
provides for all other interrelated operations involved in the coordination of
generation and transmission); The North American Co., Holding Co. Act Release
No. 10320 (Dec. 28, 1950) (economic integration is demonstrated by the exchange
of power, the coordination of future power demand, the sharing of extensive
experience with regard to engineering and other operating problems, and the
furnishing of financial aid to the company being acquired).
As required under Section 2(a)(29)(A), the coordinated system must be
"economically operated." Thus, the Commission analyzes whether the coordinated
system achieves economies and efficiencies. See, e.g., City of New Orleans v.
SEC, 969 F.2d 1163, 1168 (D.C. Cir. 1992) (the term "economically" means "that
facilities, in addition to their physical interconnection, be consolidated so as
to take advantage of efficiencies"). Applicants expect to realize significant
economies and efficiencies as a result of the Transaction. As described in Item
III.B.2 below, Applicants estimate the present value of the net savings from the
Transaction, after reflecting recovery rates of the acquisition premium and
transaction costs, to be approximately $356.0 million following the Transaction.
<PAGE>
iii. Single Area or Region
The merged company's operations will be confined to a "single area or
region in one or more States." Following the Transaction, NEES will continue to
operate in the same New England states in which it currently conducts public
utility operations.
iv. Localized Management, Efficient Operation and
Effective Regulation
Section 2(a)(29)(A) also provides for the Commission's consideration
of the size of the combined system, requiring that the combined system not be so
large as to impair the advantages of localized management, efficient operation,
and the effectiveness of regulation.
Following the Transaction, NEES and its subsidiaries will maintain
their current management and local operating headquarters. EUA's utility assets
and operations will be combined fully into NEES' existing utility subsidiaries.
This structure will preserve all the benefits of localized management which NEES
and its subsidiaries currently enjoy, while promoting maximum efficiencies and
economies.
The Transaction will not impair the effectiveness of state regulation.
Following the Transaction, NEES and its subsidiaries will continue to be
regulated by the same state commissions which currently regulate them, including
those of Massachusetts and Rhode Island, which now regulate EUA's utility
activities. The Transaction is subject to the approval of the VPSB, the CDPUC,
the RIDIV and possibly the NHPUC. In addition, Applicants are seeking rate plan
approval from the MDTE and the RIPUC.
c. Section 11(b)(1) (Acquisition of Non-Utility Interests)
Section 11(b)(1) of the Act also requires that a registered holding
company limit its operations to a single integrated public utility system and
"such other businesses as are reasonably incidental, or economically necessary
or appropriate to the operations of such integrated public-utility system." Each
of EUA's non-utility business interests conforms to the "other business"
standards of the Act as previously determined by the Commission. The indirect
acquisition by NEES of EUA's non-utility businesses in no way affects the
functional relationship of those businesses to NEES' core electric business
following the Transaction. See Item I.B.3(b) above for a detailed description of
EUA's non-utility businesses.
Based on the foregoing, the Transaction is not detrimental to the
carrying out of the provisions of Section 11.
<PAGE>
2. Section 10(c)(2)
Section 10(c)(2) requires that the Commission approve a transaction
that serves the public interest through economical and efficient development of
an integrated public utility system. As described above, the NEES System will be
fully integrated following the Transaction. Further, the Transaction will
promote the economic and efficient development of the NEES utility system.
Economic efficiency is the driving force behind the Transaction; its
purpose is to create an entity well situated to compete effectively in an
increasingly active market. The Transaction will allow NEES to realize the
"opportunities for economies of scale, the elimination of duplicate facilities
and activities, the sharing of production capacity and reserves and generally
more efficient operations" described by the Commission in American Electric
Power, supra. Applicants expect to achieve at least $356.0 million in present
value net savings (after amortization of the EUA acquisition premium and
transaction costs) following consummation of the Transaction. (See, e.g.,
Testimony of Michael E. Jesanis, The Narragansett Electric Company, Blackstone
Valley Electric Company, and Newport Electric Corporation: Rate Plan Filing in
Support of Merger, Vol. 1, Rhode Island Public Utilities Commission (May,
1999)). The merger of NEES and EUA will result in cost savings in a number of
areas. Approximately 70 percent of the projected savings will arise from
personnel reductions in administrative areas such as accounting and finance. In
addition, NEES and EUA customer service operations will be integrated to handle
increased volumes with greater efficiency. Other operating savings will result
from the disposition of duplicate facilities, realization of greater purchasing
power, and elimination of redundant administrative costs such as corporate
governance expense.
NEES' and EUA's utility customers will receive substantial benefits
from the Transaction and its resulting cost savings. NEES has filed rate
consolidation plans with the MDTE and the RIPUC that extend an agreed-upon
distribution rate freeze from December 31, 2000 to December 31, 2002. On the
later of April 1, 2000 or 120 days after the Merger is completed, the rates of
Blackstone and Newport will be partially consolidated with Narragansett's lower
rates, thereby saving Blackstone and Newport customers $2.1 million and $3.4
million annually. In addition, all of Eastern Edison's customers will be moved
to Mass. Electric's lower rates on January 1, 2001. The movement to Mass.
Electric's rates will save Eastern Edison's customers approximately $23.0
million in the first year of rate consolidation. NEES also has proposed a
further two year freeze in distribution rates related to the NEES/NGG Merger
through December 31, 2004 (contingent upon consummation of the NEES/NGG Merger).
The rate plans will save Rhode Island and Massachusetts customers $79.0 million
and $105.0 million, respectively, over a four year period. Because EUA has no
<PAGE>
retail operations in New Hampshire, no rate plan for New Hampshire customers has
been proposed.
As the Commission has observed with reference to Section 10(c)(2),
"specific dollar forecasts of future savings are not necessarily required; a
demonstrated potential for economies will suffice even when these are not
precisely quantifiable." Centerior Energy Corp., Holding Co. Act Release No.
24073 (Apr. 29, 1986). In this regard, the Transaction will result in additional
benefits which, although not precisely quantifiable, are nonetheless
significant. For example, the merged company will be better situated to provide
more reliable electric service than is possible for NEES and EUA on a
stand-alone basis. It also will be better equipped and positioned to provide the
transmission and distribution infrastructure that is essential to the creation
of a robust power supply competitive market in restructured wholesale and retail
electric markets.
C. Section 10(f)
Section 10(f) provides that:
"The Commission shall not approve any acquisition as to which an
application is made under this section unless it appears to the
satisfaction of the Commission that such State laws as may apply in
respect of such acquisition have been complied with, except where the
Commission finds that compliance with such State laws would be
detrimental to the carrying out of the provisions of section 11."
As described above, and as evidenced by the various applications
seeking authorization of the Transaction and rate plan approvals and orders
approving such, NEES and EUA will comply with all applicable state laws related
to the Transaction.
D. Service Agreement
As described in Item I.B.3(a) above, Service Company is a service
company that, pursuant to service agreements with each of the subsidiary
companies of NEES, provides various technical, engineering, accounting,
administrative, financial, purchasing, computing, managerial, operational, and
legal services to each of the NEES subsidiary companies. Pursuant to the service
agreements, these services are provided at cost. The Commission previously has
determined that Service Company is so organized and its business is so conducted
as to meet the requirements of Section 13(b) of the Act and Rule 88 thereunder.
New England Power Service Co., 1 SEC 615 (1936), continued by, 10 SEC 562
(1941), modified by, Holding Co. Act Release No. 14128 (Dec. 30, 1959).
<PAGE>
Similarly, EUA Service is a service company which, pursuant to service
agreements signed with each of the subsidiary companies of EUA, provides various
technical, engineering, accounting, administrative, financial, purchasing,
computing, managerial, and operational services to each of the EUA subsidiary
companies. Pursuant to the service agreements, these services are provided at
cost. The Commission also previously has determined that EUA Service is so
organized and its business is so conducted as to meet the requirements of
Section 13(b) of the Act and Rule 88 thereunder. Eastern Utilities Associates,
Holding Co. Act Release No. 17029 (Mar. 5, 1971).
Upon consummation of the Transaction, EUA Service will be merged with
Service Company, and Service Company will be the surviving service company for
the NEES system.
E. Organization of LLC; Acquisition of Merger LLC Interests
LLC was organized solely for the purpose of effecting the Transaction
and has not conducted any activities other than in connection with the
Transaction. LLC has no subsidiaries. Each membership certificate of LLC to be
issued to LLC and outstanding immediately before the consummation of the Merger
will be converted into one share of the surviving entity upon consummation of
the Transaction. Thus, the sole purpose for LLC is to serve as an acquisition
subsidiary of NEES for purposes of effecting the Transaction. Approval of this
Application/Declaration will constitute approval of the acquisition by NEES of
the membership certificates of LLC.
F. Financing and Other Commission Authorizations
1. Payment of Dividends Out of Capital or Unearned Surplus.
As a result of the application of the purchase method of accounting to
the Transaction, the current retained earnings of EUA and its subsidiary
companies (the "EUA Subsidiary Companies") will be recharacterized as additional
paid-in-capital. In addition, the Transaction will give rise to a substantial
level of goodwill, the difference between the aggregate fair values of all
identifiable tangible and intangible (non-goodwill) assets on the one hand, and
the total consideration to be paid for EUA and the fair value of the liabilities
assumed, on the other. In accordance with the Commission's Staff Accounting
Bulletin No. 54, Topic 5J ("Staff Accounting Bulletin"), the goodwill will be
"pushed down" to the EUA Subsidiary Companies and reflected as additional
paid-in-capital in their financial statements. The effect of these accounting
conventions would be to leave the EUA Subsidiary Companies with no retained
earnings, the traditional source of dividend payment, but, nevertheless, strong
balance sheets showing significant equity levels. Applicants request
authorization to pay dividends out of the additional paid-in-capital account up
<PAGE>
to the amount of the EUA Subsidiary Companies' aggregate retained earnings just
prior to the Transaction and out of earnings before the amortization of the
goodwill thereafter.
As indicated in the Staff Accounting Bulletin, registrants that have
substantially all (generally defined as in excess of 95 percent) of their common
stock acquired by a third party, in a business combination accounted for under
the purchase method, should reflect the push-down of goodwill in the
registrant's post-acquisition financial statements. For any post-acquisition
reporting of the consolidated NEES financial statements, push down accounting
will be reflected in those statements and the full amount of goodwill associated
with the EUA acquisition will be reflected. Push down accounting also will be
applied to the EUA Subsidiary Companies.
NEES currently intends to amortize the goodwill resulting from the
acquisition of EUA over a 20-year period. Generally accepted accounting
principles ("GAAP") at present allow a goodwill life of up to 40 years. The
Commission, however, has been challenging registrants that adopt the maximum
period. Additionally, the FASB draft proposal relating to accounting for
business combinations would limit the maximum goodwill life to 20 years.
Applicants, therefore currently intend to adopt a 20-year goodwill amortization
period.
The application of "push down" accounting represents the termination
of the old accounting entity and the creation of a new one. For FERC and state
commission reporting purposes, goodwill will be recorded in the "Acquisition
adjustments" account. The original historical basis of the plant accounts will
not be disturbed.
As a result of the push down of the goodwill, the common equity
balances of EUA and the EUA Subsidiary Companies effectively are reset as if
they were new companies, because a new basis of accounting has been pushed down
to the entities. As a result, retained earnings are eliminated. Immediately
following this accounting treatment, the only components with a recorded value
would be:
o Common shares - which would continue to reflect the par value of the common
shares issued.
o Additional paid in capital - which would reflect a value consistent with
total common stockholders equity minus the par value recorded in the common
stock line.
In other words, the resulting common stockholders' equity will equal the total
consideration paid for the entity.
<PAGE>
Based on 1998 financial information, the application of these
accounting principles to the NEES/EUA merger will result in following
adjustments to EUA's accounts:
<TABLE>
<CAPTION>
$'000 1998 Adjustments 1 Adjustments 2 Restated
<S> <C> <C>
Common Shares $102,180 -- -- $102,180
Paid in capital $218,959 $52,535 $259,842 $531,336
Retained earnings $56,466 ($56,466) -- 0
Common Share ($3,931) $3,931 -- 0
Expense
Total equity $373,674 $0 $259,842 $633,516
</TABLE>
Adjustments 1 - capital accounts are restated as Paid in Capital.
Adjustments 2 - goodwill is added to Paid in Capital.
The push down of the goodwill also has an impact on the net income of
EUA. Since the goodwill will be amortized over 20 years, EUA's net income will
be reduced by the amount of the amortization.
The premium to be paid to acquire EUA will result in goodwill and the
elimination of EUA's retained earnings. EUA's consolidation with NEES will
further increase NEES' additional paid in capital account. The amortization of
the EUA goodwill also will reduce net income. The required accounting
adjustments put EUA in the anomalous position of having greater stockholders'
equity following the Transaction, but projected net income below EUA's current
dividend payment levels and no retained earnings from which to pay dividends. As
discussed further below, these merger-related accounting adjustments do not
affect the cash flow associated with the utility subsidiaries.
Section 12 of the 1935 Act, and Rule 46 thereunder, generally prohibit
the payment of dividends out of "capital or unearned surplus" except pursuant to
an order of the Commission. The legislative history explains that this provision
was intended to "prevent the milking of operating companies in the interest of
the controlling holding company groups." S. Rep. No. 621, 74th Cong., 1st Sess.
34 (1935).11 In determining whether to permit a registered holding company to
pay dividends out of capital surplus, the Commission considers various factors,
including: (i) the asset value of the company in relation to its capitalization,
(ii) the company's prior earnings, (iii) the company's current earnings in
- --------
11 Compare Section 305(a) of the Federal Power Act.
<PAGE>
relation to the proposed dividend, and (iv) the company's projected cash
position after payment of a dividend. See Eastern Utilities Associates, Holding
Co. Act Release No. 25330 (June 13, 1991), and cases cited therein. Further, the
payment of the dividend must be "appropriate in the public interest." Id.,
citing Commonwealth & Southern Corporation, 13 S.E.C. 489, 492 (1943).
NEES and its subsidiaries request authority to pay dividends out of
additional paid-in-capital up to the amount of EUA's consolidated retained
earnings and EUA's subsidiaries' retained earnings, just prior to the
Transaction and out of earnings before the amortization of goodwill thereafter.
In no case would dividends be paid if it would result in the consolidated equity
of NEES dropping below 30 percent on a consolidated basis. This restriction is
intended to protect both investors and consumers.
In support of their request, Applicants assert that each of the
standards of Section 12(c) of the 1935 Act enunciated in Eastern Utilities
Associates are satisfied:
(i) After the Transaction, and giving effect to the pushdown of goodwill,
NEES' equity as a percentage of total capitalization will be 60.4%
percent, substantially in excess of the traditional levels of equity
capitalization that the Commission has authorized for other registered
holding company systems. Applicants' commitment to maintain the
capitalization of NEES at or above 30 percent equity on a consolidated
basis should result in a capital structure consistent with industry
norms.
(ii) NEES has a favorable history of prior earnings and it has a long
record of consistent dividend payments.12
- --------
12 In recent years, NEES' net income and dividends have been:
Year Net Income ($ millions) Dividends Paid ($ millions)
1994 199 149
1995 205 152
1996 209 153
1997 220 152
1998 190 146
<PAGE>
(iii) Applicants anticipate that NEES' cash flow after the Transaction will
not differ significantly from its pre-Transaction cash flow and that
earnings before the amortization of goodwill ("Gross Earnings"),
therefore, should remain stable post-Transaction. Applicants intend
that dividends paid out of future earnings will continue to reflect a
dividend payout ratio of between 60 percent and 100 percent of Gross
Earnings, based on a rolling 5-year average.
(iv) The projected cash position of NEES and its utility subsidiaries after
the Transaction will be adequate to meet the obligations of each
company. As of March 31, 1999, NEES had cash balances of $62.9 million
and marketable securities of $93.9 million on a consolidated basis.
The amortization of goodwill is a non-cash expense that will not
affect the cash flow of NEES or its subsidiaries. Each of NEES and its
subsidiary companies is forecast to have sufficient cash to pay
dividends in the amounts contemplated.
(v) The proposed dividend payments are in the public interest. NEES and
its subsidiary companies are in sound financial condition as indicated
by their credit ratings. NEES' commercial paper is rated A-1 by
Standard & Poor's ("S&P") and Prime-1 by Moody's Investor Service
("Moody's"). The long-term debt of Mass. Electric, Narragansett, and
NEP is rated AA-, A1; AA-, A1; and A+, A1 by S&P and Moody's,
respectively. Indeed, S&P has placed the credit ratings of NEES, Mass.
Electric, Narragansett, and NEP on "creditwatch with positive
implications."13 The expectations of continued strong credit ratings
by NEES' utility subsidiaries should allow them to continue to access
the capital markets to finance their operations and growth.
In addition, the dividend payments are consistent with investor interests
because they allow the capital structure of NEES and its subsidiaries to be
adjusted to more appropriate levels of debt and equity.
2. Financing Arrangements
By this Application/Declaration, NEES seeks Commission authorization
to enter into financing arrangements pursuant to which NEES may borrow up to
$650.0 million in the event the Transaction is consummated prior to the NEES/NGG
Merger. NEES also seeks authority to issue commercial paper or otherwise to
engage in short-term borrowing up to $650.0 million. The maximum aggregate
- --------
13 S&P's Credit Wire (Dec. 14, 1998).
<PAGE>
amount of debt outstanding hereunder, whether commercial paper or bank debt
would not exceed $650.0 million at any one time. NEES requests that the
authority requested herein be granted through December 31, 2005.14
a. Borrowings from Banks - Credit Agreement
NEES proposes to enter into a Credit Agreement. A draft of the Credit
Agreement, Exhibit B-3 to this filing, will be filed by amendment.
The Credit Agreement will provide for a revolving facility of up to
$650.0 million. The term would not be in excess of five years. NEES will propose
having interest rate options to permit LIBOR borrowings, Base Rate borrowings,
and Competitive Bid borrowings. The Credit Agreement also will include
provisions for various fees which may include a facility fee, an arrangement and
syndication fee, and an annual administration fee. The Credit Agreement will be
unsecured. NEES intends to have the option of reducing the commitments under the
Credit Agreement, or making prepayments at any time without penalty.
b. Cost of Funds
Pricing for the Credit Agreement has not yet been negotiated. Final
pricing will be supplied by amendment.
c. Borrowings from Banks - Short-term
NEES also may make arrangements with certain banks for short-term
lines of credit, for various purposes, including support of commercial paper.
The proposed borrowings will be evidenced by notes payable, maturing in less
than one year from the date of issuance. NEES will negotiate with the banks the
interest costs of such borrowings, and will pay fees to the banks in lieu of
compensating balance arrangements. The effective interest cost of borrowings, on
a daily basis, from a bank will not exceed the greater of the bank's base or
prime lending rate, or the rate published daily in the Wall Street Journal as
the high federal funds rate, plus, in either case, one percent. Certain of such
borrowings may be without prepayment privileges. Based on the current base
lending rate of 8 percent and an equivalent or lower high federal funds rate,
the effective interest costs of such borrowing would not exceed 12 percent per
annum.
- ----------
14 This request is in addition to NEES' existing authority, through December
31, 2002, to issue short-term notes to banks and/or commercial paper to
dealers up to an aggregate amount of $500.0 million outstanding at any one
time.
<PAGE>
Payment of any short-term promissory notes prior to maturity will be
made on the basis most favorable to NEES, taking into account fixed maturities,
interest rates, and any other relevant financial consideration.
d. Sale of Commercial Paper to Dealers
NEES also proposes to issue and sell commercial paper directly to one
or more nationally recognized commercial paper dealers ("CP Dealer"). Initially
the CP Dealer will be CS First Boston Corporation and/or Merrill Lynch Money
Markets Incorporated, but this may change as warranted.
The commercial paper so issued and sold will satisfy the requirements
of Section 3(a)(3) of the Securities Act of 1933 and be in the form of unsecured
promissory notes having varying maturities of not in excess of 270 days. Actual
maturities will be determined by market conditions, the effective interest cost
to NEES, and NEES' cash requirements at the time of issuance. The commercial
paper will be in denominations of not less than $50,000. The terms of the
commercial paper will not provide for prepayment prior to maturity. The
commercial paper will be purchased by the CP Dealer from the issuer at a
discount which will not be in excess of the discount then prevailing for
commercial paper of comparable quality and maturity which is sold to commercial
paper dealers. The CP Dealer initially will reoffer the commercial paper at a
discount rate not more than 1/8 of one percent per annum less than the
prevailing discount rate to NEES.
The effective interest cost to NEES of commercial paper generally will
not exceed the effective interest cost of the base lending rate at BankBoston
(formerly the First National Bank of Boston). However, the effective interest
cost of such paper is based on the supply of, and demand for, that and similar
paper at the time of sale. Specifically, on several previous occasions,
short-term money markets have become very volatile during brief periods of
extraordinary demand, and the interest costs of commercial paper have exceeded
bank base rates. Because such volatile market conditions usually exist for brief
periods, it is not anticipated that any sale of commercial paper with interest
costs in excess of bank base rates would have a significant marginal impact on
the annual interest cost of NEES. Therefore, while it is not anticipated that
the effective annual cost of borrowing through commercial paper will exceed the
annual base rate borrowing from BankBoston, in order to obtain maximum
flexibility during the periods described above, commercial paper may be issued
with a maturity of not more than 90 days with an effective cost in excess of the
then-existing lending rate.
The decision to borrow from banks or issue commercial paper will be
based on the cost of such funds and their availability for the anticipated
borrowing period.
<PAGE>
e. Filing of Certificates of Notification
Within 45 days after the end of each calendar quarter, NEES will file
a certificate of notification covering the transactions effected pursuant to the
authority requested herein during such quarter. Such certificate will show the
dates and amounts of all new money borrowings, whether by issuance of notes to
banks or by sale of commercial paper, the names of the lenders, the maximum
concurrent amount of notes outstanding to banks and CP Dealers, the aggregate
total outstanding at any one time, and the aggregate total outstanding at the
end of such quarter. Each certificate will include, with respect to the issue
and sale of commercial paper, the effective interest cost for such promissory
note issued as commercial paper. The final certificate of notification will be
accompanied by the required past tense opinion of counsel.
3. Rule 53
Neither NEES nor EUA has an ownership interest in an exempt wholesale
generator ("EWG") or a foreign utility company ("FUCO") as defined in Sections
32 and 33 of the Act. Additionally, neither NEES nor EUA is a party to, nor does
NEES or EUA have any rights under, a service, sales, or construction agreement
with an EWG or a FUCO. NEES shall comply with the requirements of Rule 53 of the
Act in connection with any future EWG and FUCO acquisitions and financings. To
the extent that any monies from the borrowings hereunder are used to invest in,
or otherwise acquire an interest in the business of, any EWGs or FUCOs, NEES
will comply with the Commission's orders in File No. 70-8783 (Release No.
35-26504 dated April 15, 1996, as supplemented by Release No. 35-26729 dated
June 10, 1997).
ITEM IV. REGULATORY APPROVAL
In addition to required Commission approvals, the following have
jurisdiction over various aspects of the Transaction (and related subsidiary
company consolidations): the FERC, the NRC, the FCC, the VPSB, the CDPUC,
possibly the NHPUC, the MDTE, and the RIDIV. In addition, Applicants are seeking
approval from the MDTE and the RIPUC for a rate plan that allows recovery of the
costs of the acquisition and the acquisition premium. In addition, Applicants
filed notification and report forms under the HSR Act with the DOJ and the FTC
with respect to the Merger. On April 30, 1999, Applicants received clearance for
the Merger under the HSR Act.
<PAGE>
ITEM V. PROCEDURE
The Commission is respectfully requested to issue and publish not
later than August 20, 1999, the requisite notice under Rule 23 with respect to
the filing of this Application/Declaration, such notice to specify a date not
later than 25 days, by which comments may be entered and a date not later than
October 15, 1999, as the date after which an order of the Commission granting
and permitting this Application/Declaration to become effective may be entered
by the Commission.
It is submitted that a recommended decision by a hearing or other
responsible officer of the Commission is not needed for approval of the
Transaction. The Division may assist in the preparation of the Commission's
decision. There should be no waiting period between the issuance of the
Commission's order and the date on which it is to become effective.
ITEM VI. EXHIBITS AND FINANCIAL STATEMENTS
A. Exhibits
A-1 Agreement and Declaration of Trust dated January 2, 1926, as amended
through April 28, 1992 (Exhibit 3 to 1994 NEES Form 10-K, File No.
1-3446, and incorporated herein by reference)
A-2 Declaration of Trust, dated April 2, 1928, as amended (Exhibit A-3,
File No. 70- 3188; Exhibit 1 to 8-K Reports for April in each of the
years 1957, 1962, 1966, 1968, 1972 and 1973, File No. 1-5366; Exhibit
A-1(a), Amendment No. 2 to Form U-1, File No. 70-5997; Exhibit 4-3,
Registration No. 2-72589; Exhibit 1 to Certificate of Notification;
File No. 70-6713; Exhibit 1 to Certificate of Notification; File No.
70-7084; Exhibit 3-2, Form 10-K for 1987, File No. 1- 5366, and
incorporated herein by reference)
A-3 Amended and Restated Certificate of Organization of LLC
B-1 NEES/NGG Merger Agreement (Exhibit 10(mm) to NEES Form 8-K, File No.
1-3446, dated December 16, 1998, and incorporated herein by reference)
B-2 Term Sheet to Credit Agreement (to be filed by amendment)
B-3 Draft Credit Agreement (to be filed by amendment) B-4 Merger Agreement
D-1 Application to the FERC, filed on May 5, 1999, as supplemented on July
1, 1999, together with testimony and exhibits (pursuant to Exhibit G,
state filings provided separately)
D-2 Application to the MDTE, together with testimony and exhibits
D-3 Application to the RIPUC, together with testimony and exhibits
<PAGE>
D-4 Application to the VPSB, together with testimony and exhibits
D-5 Application to the CDPUC, together with testimony and exhibits (to be
filed by amendment)
D-6 Application to the NHPUC, together with testimony and exhibits (to be
filed by amendment)
D-7 Application to the NRC (to be filed by amendment)
E-1 NEES organization chart (to be filed by amendment)
E-2 EUA organization chart (to be filed by amendment)
E-3 Combined company organization chart after the Transaction (to be filed
by amendment)
E-4 Map of NEES and EUA service areas and transmission systems (Exhibit I
to Exhibit D-1 hereto)
F-1 Opinion of Merrill Lynch & Co. (to be filed by amendment)
F-2 Opinion of Salomon Smith Barney (to be filed by amendment)
F-3 Opinion of Counsel (to be filed by amendment)
F-4 Past Tense Opinion of Counsel (to be filed by amendment with Rule 24
certificate
G-1 NEES' Annual Report on Form 10-K for the fiscal year ended December
31, 1998 (File No. 1-3446, filed March 31, 1999, and incorporated
herein by reference)
G-2 NEES' Quarterly Report on Form 10-Q for the quarter ended March 31,
1999 (File No. 1-3446, filed May 17, 1999, and incorporated herein by
reference)
G-3 EUA's Annual Report on Form 10-K for the fiscal year ended December
31, 1998 (File No. 1-5366, filed March 31, 1999, and incorporated
herein by reference)
G-4 EUA's Quarterly Report on Form 10-Q for the quarter ended March 31,
1999 (File No. 1-5366, filed May 14, 1999, and incorporated herein by
reference)
H-1 Proposed Form of Notice
K-1 Discussion of negotiations between NEES and EUA
B. Financial Statements
FS-1 NEES' Consolidated Balance Sheet as of December 31, 1998 (previously
filed with the Commission in NEES' Annual Report on Form 10-K for the
year ended December 31, 1998 (Exhibit G-1 hereto), filed March 31,
1999, File No. 1-3446, and incorporated herein by reference)
<PAGE>
FS-2 NEES' Consolidated Statement of Income for the 12 months ended
December 31, 1998 (previously filed with the Commission in NEES'
Annual Report on Form 10-K for the year ended December 31, 1998
(Exhibit G-1 hereto), filed March 31, 1999, File No. 1-3446, and
incorporated herein by reference)
FS-3 EUA's Consolidated Balance Sheet as of December 31, 1998 (previously
filed with the Commission in NEES' Annual Report on Form 10-K for the
year ended December 31, 1998 (Exhibit G-3 hereto), filed March 31,
1999, File No. 1-5366, and incorporated herein by reference)
FS-4 EUA's Consolidated Statement of Income for the 12 months ended
December 31, 1998 (previously filed with the Commission in NEES'
Annual Report on Form 10-K for the year ended December 31, 1998
(Exhibit G-3 hereto), filed March 31, 1999, File No. 1-5366, and
incorporated herein by reference)
ITEM VII. INFORMATION AS TO ENVIRONMENTAL EFFECTS
The Transaction neither involves "major federal actions" nor
"significantly [affects] the quality of the human environment" as those terms
are used in Section 102(2)(C) of the National Environmental Policy Act, 42
U.S.C. Sec. 4332. The only federal actions related to the Transaction pertain to
the required approvals and actions summarized in Item IV, and Commission
approval of this Application/Declaration. Consummation of the Transaction will
not result in significant changes in the operations of the public utilities
involved in the Transaction that would have any impact on the environment. No
federal agency is preparing an environmental impact statement with respect to
this matter.
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]
<PAGE>
SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act
of 1935, the undersigned companies have duly caused this statement to be signed
on their behalf by the undersigned thereunto duly authorized.
NEW ENGLAND ELECTRIC SYSTEM*
By: /s/ Kirk L. Ramsauer
----------------------
Name: Kirk L. Ramsauer
Title: Deputy General Counsel
* The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability therefor.
EASTERN UTILITIES ASSOCIATES**
By: /s/ Donald G. Pardus
---------------------
Name: Donald G. Pardus
Title: Chairman/CEO
** The name "Eastern Utilities Associates" is the designation of the Trustees of
EUA for the time being in their collective capacity but not personally, under a
Declaration of Trust dated April 2, 1928, as amended, a copy of which amended
Declaration of Trust has been filed in the office of the Secretary of The
Commonwealth of Massachusetts and elsewhere as required by law; and all persons
dealing with EUA must look solely to the trust property for the enforcement of
any claim against EUA, as neither the Trustees nor the officers or shareholders
of EUA assume any personal liability for obligations entered into on behalf of
EUA.
Dated:
<PAGE>
Exhibit A-3
RESEARCH DRIVE LLC
AMENDED AND RESTATED CERTIFICATE OF ORGANIZATION
Pursuant to the provisions of the Massachusetts Limited Liability Company
Act, M.G.L. c. 156C (the "Act"), the undersigned hereby certifies as follows:
1. Tax Identification Number. The federal employer identification number of
the limited liability company (the "LLC") has been applied for.
2. Name of the Limited Liability Company. The name of the LLC is Research
Drive LLC.
3. Original Filing Date. The LLC's original Certificate of Organization was
filed on January 29, 1999.
4. Office of the LLC. The address of the office of the LLC for purposes of
Section 5 of the Act is 25 Research Drive, Westborough, MA 01582.
5. Business of the LLC. The general character of the business of the LLC is to
engage in any manufacturing, management, service or other business,
operation or activity related to energy generation, transmission or
distribution, utilization, conservation or transportation, construction or
telecommunications, directly or indirectly through joint ventures,
partnership or other entities; to engage in any activities directly or
indirectly related or incidental thereto, and to engage in any other
activity in which limited liability companies organized under the laws of
the Commonwealth of Massachusetts may lawfully engage.
6. Date of Dissolution. The LLC has no specified date of dissolution.
7. Agent for Service of Process. The name and business address of the resident
agent for service of process required to be maintained by Section 5 of the
Act is CT Corporation System, 2 Oliver Street, Boston, MA 02109.
<PAGE>
8. Managers. The following persons are managers of the LLC:
Name Address
Richard P. Sergel 25 Research Drive, Westborough, MA 01582
John G. Cochrane 25 Research Drive, Westborough, MA 01582
9. Amendments. The LLC's Certificate of Organization is hereby amended by
indicating that a federal employer identification number has been applied
for, changing the address of the office of the LLC, deleting Louis A.
Goodman as an authorized person and adding Richard P. Sergel and John G.
Cochrane as Managers.
IN WITNESS WHEREOF, the undersigned hereby affirms under the penalties
of perjury that the facts stated herein are true, as of February 25, 1999.
RESEARCH DRIVE LLC
/s/ John G. Cochrane
----------------------------------------
John G. Cochrane, Manager
<PAGE>
Tab 1
AGREEMENT AND PLAN OF MERGER
dated as of February 1, 1999
by and among
NEW ENGLAND ELECTRIC SYSTEM,
RESEARCH DRIVE LLC
and
EASTERN UTILITIES ASSOCIATES
<PAGE>
TABLE OF CONTENTS
Page
No.
ARTICLE I
THE MERGER......................................................... 1
1.01 The Merger......................................................... 1
1.02 Effective Time..................................................... 1
1.03 Effects of the Merger.............................................. 2
ARTICLE II
CONVERSION OF SHARES............................................... 2
2.01 Conversion of Capital Stock........................................ 2
2.02 Surrender of Shares................................................ 3
2.03 Withholding Rights................................................. 4
ARTICLE III
THE CLOSING........................................................ 4
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5
4.01 Organization and Qualification..................................... 5
4.02 Capital Stock...................................................... 6
4.03 Authority.......................................................... 7
4.04 Non-Contravention; Approvals and Consents.......................... 7
4.05 SEC Reports, Financial Statements and Utility Reports.............. 8
4.06 Absence of Certain Changes or Events............................... 9
4.07 Legal Proceedings.................................................. 9
4.08 Information Supplied............................................... 9
4.09 Compliance......................................................... 10
4.10 Taxes.............................................................. 10
4.11 Employee Benefit Plans; ERISA...................................... 12
4.12 Labor Matters...................................................... 14
4.13 Environmental Matters.............................................. 15
4.14 Regulation as a Utility............................................ 17
4.15 Insurance.......................................................... 17
4.16 Nuclear Facilities................................................. 18
4.17 Vote Required...................................................... 18
4.18 Opinion of Financial Advisor....................................... 18
-i-
<PAGE>
Page
No.
4.19 Ownership of NEES Common Shares.................................... 18
4.20 State Anti-Takeover Statutes....................................... 18
4.21 Year 2000.......................................................... 19
4.22 EUA Associates..................................................... 19
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES............................. 19
5.01 Organization and Qualification..................................... 19
5.02 Authority.......................................................... 20
5.03 Capital Stock...................................................... 20
5.04 Non-Contravention; Approvals and Consents.......................... 20
5.05 Information Supplied............................................... 21
5.06 Compliance......................................................... 21
5.07 Financing.......................................................... 22
5.08 No Vote Required................................................... 22
5.09 Ownership of EUA Shares............................................ 22
5.10 Merger with The National Grid Group plc............................ 22
ARTICLE VI
COVENANTS................................................ 22
6.01 Covenants of EUA................................................... 22
6.02 Covenants of NEES.................................................. 28
6.03 Additional Covenants by NEES and EUA............................... 29
ARTICLE VII
ADDITIONAL AGREEMENTS.................................... 30
7.01 Access to Information.............................................. 30
7.02 Proxy Statement.................................................... 31
7.03 Approval of Shareholders........................................... 31
7.04 Regulatory and Other Approvals..................................... 31
7.05 Employee Benefit Plans............................................. 32
7.06 Labor Agreements and Workforce Matters............................. 34
7.07 Post Merger Operations............................................. 34
7.08 No Solicitations................................................... 35
7.09 Directors' and Officers' Indemnification and Insurance............. 36
7.10 Expenses........................................................... 37
7.11 Brokers or Finders................................................. 37
7.12 Anti-Takeover Statutes............................................. 38
7.13 Public Announcements............................................... 38
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No.
7.14 Restructuring of the Merger........................................ 38
ARTICLE VIII
CONDITIONS......................................................... 39
8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39
8.03 Conditions to Obligation of EUA to Effect the Merger............... 40
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER.................................. 41
9.01 Termination........................................................ 41
9.02 Effect of Termination.............................................. 43
9.03 Termination Fees................................................... 43
9.04 Amendment.......................................................... 44
9.05 Waiver............................................................. 44
ARTICLE X
GENERAL PROVISIONS................................................. 44
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements......................................................... 44
10.02 Notices............................................................ 44
10.03 Entire Agreement; Incorporation of Exhibits........................ 46
10.04 No Third Party Beneficiary......................................... 46
10.05 No Assignment; Binding Effect...................................... 46
10.06 Headings........................................................... 47
10.07 Invalid Provisions................................................. 47
10.08 Governing Law...................................................... 47
10.09 Enforcement of Agreement........................................... 47
10.10 Certain Definitions................................................ 47
10.11 Counterparts....................................................... 48
10.12 WAIVER OF JURY TRIAL............................................... 48
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<PAGE>
GLOSSARY OF DEFINED TERMS
The following terms, when used in this Agreement, have the meanings
ascribed to them in the corresponding Sections of this Agreement listed below:
"1935 Act" -- Section 4.05(b)
"Adjustment Date" -- Section 2.01(c)
"Affected Employees" -- Section 7.05(a)
"affiliate" -- Section 10.11(a)
"Agreement" -- Preamble
"Alternative Proposal" -- Section 7.08
"beneficially" -- Section 10.10(b)
"business day" -- Section 10.10(c)
"Canceled Shares" -- Section 2.02(b)
"Certificates" -- Section 2.02(b)
"Closing" -- Article III
"Closing Agreement" -- Section 4.10(j)
"Closing Date" -- Article III
"Code" -- Section 2.03
"Confidentiality Agreement" -- Section 7.01
"Constituent Entities" -- Section 1.01
"Contracts" -- Section 4.04(a)
"control," "controlling,"
"controlled by" and
"under common control with" -- Section 10.10(a)
"DOE" -- Section 4.05(b)
"Effective Time" -- Section 1.02
"Environmental Claim" -- Section 4.13(f)(i)
"Environmental Laws" -- Section 4.13(f)(ii)
"Environmental Permits" -- Section 4.13(b)
"ERISA" -- Section 4.11(a)
"ERISA Affiliate" -- Section 4.11(c)
"EUA" -- Preamble
"EUA Associates" -- Section 4.01(b)
"EUA Employee Agreements" -- Section 7.05(d)(ii)
"EUA Executives" -- Section 7.05(d)(ii)
"EUA Shares" -- Preamble
"EUA Disclosure Letter" -- Section 4.01(a)
"EUA Employee Benefit Plans" -- Section 4.11(a)
"EUA Financial Statements" -- Section 4.05(a)
"EUA Nuclear Facilities" -- Section 4.16
"EUA Material Adverse Effect" -- Section 4.01(a)
"EUA Required Consents" -- Section 4.04(a)
"EUA Required Statutory Approvals" -- Section 4.04(b)
"EUA SEC Reports" -- Section 4.05(a)
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<PAGE>
"EUA Shareholders' Approval" -- Section 7.03
"EUA Shareholders' Meeting" -- Section 7.03
"EUA Significant Subsidiary" -- Section 7.08
"EUA Shares" -- Preamble
"EUA Trust Agreement" -- Section 1.03
"EUA Voting Debt -- Section 4.02(d)
"Evaluation Material" -- Section 7.01(a)
"Exchange Act" -- Section 4.05(a)
"Exchange Fund" -- Section 2.02(a)
"Extended Termination Date" -- Section 9.01(b)
"FCC" -- Section 4.05(b)
"FERC" -- Section 4.05(b)
"Final Order" -- Section 8.01(d)
"Governmental Authority" -- Section 4.04(a)
"Hazardous Materials" -- Section 4.13(f)(iii)
"HSR Act" -- Section 7.04(a)
"Indemnified Liabilities" -- Section 7.09(a)
"Indemnified Party" -- Section 7.09(a)
"Indemnified Parties" -- Section 7.09(a)
"Information Systems" -- Section 4.21
"Initial Termination Date" -- Section 9.01(b)
"IRS" -- Section 4.10(m)
"knowledge" -- Section 10.11(d)
"laws" -- Section 4.04(a)
"Lien" -- Section 4.02(b)
"LLC" -- Preamble
"Massachusetts Secretary" -- Section 1.02
"Merger" -- Preamble
"Merger Consideration" -- Section 2.01(b)(ii)
"MGL" -- Section 1.01
"National Grid Group" -- Section 5.10
"National Grid Merger Agreement" -- Section 5.10
"NEES" -- Preamble
"NEES Disclosure Letter" -- Section 5.03
"NEES Material Adverse Effect" -- Section 5.01
"NEES-EUA Regulatory Approvals" -- Section 7.04(b)
"NEES-EUA Regulatory Proceedings" -- Section 7.04(c)
"NEES Required Consents" -- Section 5.04(a)
"NEES Required Statutory Approvals" -- Section 5.04(b)
"NEES-NGG Regulatory Approvals" -- Section 7.04(c)
"NEES-NGG Regulatory Proceedings" -- Section 7.04(c)
"NEES-NGG Required Statutory Approvals"-- Section 7.04
"NEES-NGG Transactions" -- Section 7.04
"NEES Shares" -- Section 5.03
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"NEES Trust Agreement" -- Section 5.01
"NGG Circular" -- Section 7.02
"NRC" -- Section 4.05(b)
"Options" -- Section 4.02(a)
"orders" -- Section 4.04(a)
"Out-of-Pocket Expenses" -- Section 9.03(a)
"Paying Agent" -- Section 2.02(a)
"PBGC" -- Section 4.11(g)
"person" -- Section 10.11(e)
"Per Share Amount" -- Section 2.01(b)(ii)
"Post Closing Plans" -- Section 7.05(b)
"Proxy Statement" -- Section 4.08(a)
"Release" -- Section 4.13(f)(iv)
"Representatives" -- Section 10.11(f)
"SEC" -- Section 4.05(a)
"Securities Act" -- Section 4.05(a)
"Subsidiary" -- Section 10.11(g)
"Surviving Entity" -- Section 1.01
"Tax Ruling" -- Section 4.10(j)
"Taxes" -- Section 4.10
"Tax Return" -- Section 4.10
"US GAAP" -- Section 4.05(a)
"Yankee Companies" -- Section 4.16
"Y2K Consultant" -- Section 6.01(o)
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<PAGE>
This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this
"Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM,
a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a
Massachusetts limited liability company which is directly and indirectly wholly
owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust
("EUA").
WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA
and the members of LLC have each determined that it is advisable and in the best
interests of their respective shareholders and members to consummate, and have
approved, the business combination transaction provided for herein in which LLC
would merge with and into EUA, with EUA being the surviving entity (the
"Merger"), pursuant to the terms and conditions of this Agreement, as a result
of which NEES will own, directly or indirectly, all of the issued and
outstanding common shares of EUA (the "EUA Shares");
WHEREAS, NEES, LLC and EUA desire to make certain representations,
warranties and agreements in connection with the Merger and also to prescribe
various conditions to the Merger;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements set forth in this Agreement, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereto hereby agree as follows:
ARTICLE I
THE MERGER
1.01 The Merger. Upon the terms and subject to the conditions of this
Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be
merged with and into EUA in accordance with Section 2 of Chapter 182 and Section
59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective
Time, the separate existence of LLC shall cease and EUA shall continue as the
surviving entity in the Merger. EUA, after the Effective Time, is sometimes
referred to herein as the "Surviving Entity" and EUA and LLC are sometimes
referred to herein as the "Constituent Entities". The effect and consequences of
the Merger shall be as set forth in Article II.
1.02 Effective Time. Subject to the provisions of this Agreement, on
the Closing Date (as defined in Article III), a certificate of merger shall be
executed and filed by EUA and LLC with the Secretary of the Commonwealth of
Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective
at the time of the filing of the certificate of merger relating to the Merger
with the Massachusetts Secretary, or at such later time as is specified in the
certificate of merger (such date and time being referred to herein as the
"Effective Time").
<PAGE>
1.03 Effects of the Merger. At the Effective Time, the Agreement and
Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately
prior to the Effective Time shall be the agreement and declaration of trust of
the Surviving Entity, until thereafter amended as provided by law and such
agreement and declaration of trust. Subject to the foregoing, the additional
effects of the Merger shall be as provided in the applicable provisions of
Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability
Company Act of Massachusetts.
ARTICLE II
CONVERSION OF SHARES
2.01 Conversion of Capital Stock. At the Effective Time, by virtue of
the Merger and without any action on the part of the holder thereof:
(a) Membership Interests of LLC. Each one percent of the issued
and outstanding membership interests in LLC shall be converted into one
transferable certificate of participation or share of the Surviving Entity.
(b) Conversion of EUA Shares.
(i) Cancellation of Treasury Shares and Shares Owned by
NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares
and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as
defined in Section 10.11) of NEES shall be canceled and retired and shall cease
to exist and no cash or other consideration shall be delivered in exchange
therefor.
(ii) Conversion of EUA Shares. Each EUA Share issued and
outstanding immediately prior to the Effective Time (other than shares to be
canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted
in accordance with the provisions of this Section 2.01 into the right to receive
cash in the amount (the "Per Share Amount") of $31.00 as such amount may
hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger
Consideration"), payable, without interest, to the holder of such EUA Share,
upon surrender, in the manner provided in Section 2.02 hereof, of the
certificate formerly evidencing such share.
(c) Adjustment in Amount of Merger Consideration. In the event
that the Closing Date shall not have occurred on or prior to the date that is
the six (6) month anniversary of the date on which EUA Shareholders' Approval is
obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for
each day after the Adjustment Date up to and including the day which is one day
prior to the earlier of the Closing Date and the Extended Termination Date, by
an amount equal to $0.003.
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2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the
Effective Time, NEES shall designate a bank or trust company reasonably
acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the
holders of EUA Shares in connection with the Merger to receive the funds to
which holders of EUA Shares shall become entitled pursuant to Section
2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or
after the Effective Time, NEES or LLC shall make or cause to be made available
to the Paying Agent immediately available funds in amounts and at the times
necessary for the payment of the Merger Consideration upon surrender of
Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b),
it being understood that any and all interest or other income earned on funds
made available to the Paying Agent pursuant to this Section 2.02(a) shall belong
to and shall be paid (at the time provided for in Section 2.02(e)) as directed
by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be
invested by the Paying Agent as directed by NEES or LLC.
(b) Exchange Procedure. As soon as practicable after the
Effective Time, the Paying Agent shall mail to each holder of record of a
certificate or certificates (the "Certificates") which immediately prior to the
Effective Time represented outstanding EUA Shares (the "Canceled Shares") that
were canceled and became instead the right to receive the Merger Consideration
pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as
NEES and EUA may reasonably agree (which shall specify that delivery shall be
effected, and risk of loss and title to the Certificates shall pass, only upon
actual delivery of the Certificates to the Paying Agent) and (ii) instructions
for effecting the surrender of the Certificates in exchange for the Merger
Consideration. Upon surrender of a Certificate or Certificates to the Paying
Agent for cancellation (or to such other agent or agents as may be appointed by
NEES and are reasonably acceptable to EUA), together with a duly executed letter
of transmittal and such other documents as the Paying Agent shall require, the
holder of such Certificate shall be entitled to receive the Merger Consideration
in exchange for each EUA Share formerly evidenced by such Certificate which such
holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of
a transfer of ownership of Canceled Shares which is not registered in the
transfer records of EUA, the Merger Consideration in respect of such Canceled
Shares may be given to the transferee thereof if the Certificate or Certificates
representing such Canceled Shares is presented to the Paying Agent, accompanied
by all documents required to evidence and effect such transfer and by evidence
satisfactory to the Paying Agent that any applicable stock transfer taxes have
been paid. At any time after the Effective Time, each Certificate shall be
deemed to represent only the right to receive the Merger Consideration subject
to and upon the surrender of such Certificate as contemplated by this Section
2.02. No interest shall be paid or will accrue on the Merger Consideration
payable to holders of Certificates pursuant to Section 2.01(b)(ii).
(c) No Further Ownership Rights in EUA Shares. The Merger
Consideration paid upon the surrender of Certificates in accordance with the
terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective
Time in full satisfaction of all rights pertaining to EUA Shares represented
thereby. From and after the Effective Time, the share transfer books of EUA
shall be closed and there shall be no further registration of transfers thereon
of EUA Shares which were outstanding immediately prior to the Effective Time.
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<PAGE>
If, after the Effective Time, Certificates are presented to NEES for any reason,
they shall be canceled and exchanged as provided in this Section 2.02.
(d) Lost, Stolen or Destroyed Certificates. In the event any
owner of any Certificate shall claim that such Certificate shall have been lost,
stolen or destroyed, upon the making of an affidavit of that fact by the owner
of such Certificate and delivery of that affidavit to the Paying Agent and, if
required by NEES or LLC, the posting by such person of a bond in customary
amount as indemnity against any claim that may be made against NEES, EUA or the
Surviving Entity with respect to such Certificate, the Paying Agent will issue
in exchange for such lost, stolen or destroyed Certificate the Merger
Consideration payable upon due surrender of, and deliverable pursuant to this
Section 2.02 in respect of, EUA Shares to which such Certificate relates.
(e) Termination of Exchange Fund. Any portion of the Exchange
Fund which remains undistributed to the shareholders of EUA for one (1) year
after the Effective Time shall be delivered to the Surviving Entity, upon
demand, and any Shareholders of EUA who have not theretofore complied with this
Article II shall thereafter look only to the Surviving Entity (subject to
abandoned property, escheat and other similar laws) as general creditors for
payment of their claim for the Merger Consideration payable upon due surrender
of the Certificates held by them. None of NEES, LLC or the Surviving Entity
shall be liable to any former holder of EUA Shares for the Merger Consideration
delivered to a public official pursuant to any applicable abandoned property,
escheat or similar law.
2.03 Withholding Rights. Each of the Surviving Entity and NEES shall
be entitled to deduct and withhold from the consideration otherwise payable
pursuant to this Agreement to any holder of EUA Shares such amounts as it is
required to deduct and withhold with respect to the making of such payment under
the Internal Revenue Code of 1986, as amended (the "Code"), or any other
provision of state, local or foreign tax law. To the extent that amounts are so
withheld by the Surviving Entity or NEES, as the case may be, such withheld
amounts shall be treated for all purposes of this Agreement as having been paid
to the holder of EUA Shares in respect of which such deduction and withholding
was made by the Surviving Entity or NEES, as the case may be.
ARTICLE III
THE CLOSING
The closing of the Merger and other transactions contemplated hereby
(the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher
& Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local
time, on the second business day following satisfaction or waiver (where
applicable) of the conditions set forth in Article VIII (other than those
conditions that by their nature are to be fulfilled at the Closing, but subject
to the fulfillment or waiver of such conditions), unless another date, time or
place is agreed to in writing by the parties hereto (the "Closing Date").
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA
EUA represents and warrants to NEES and LLC as follows:
4.01 Organization and Qualification. (a) EUA is a voluntary
association duly organized, validly existing and in good standing under the laws
of the Commonwealth of Massachusetts and has full power, authority and legal
right to own its property and assets and to transact the business in which it is
engaged. Each of EUA's Subsidiaries is a corporation duly organized or
incorporated, validly existing and in good standing under the laws of its
jurisdiction of organization or incorporation and has full corporate power and
authority to conduct its business as and to the extent now conducted and to own,
use and lease its assets and properties, except where failure to be so organized
or incorporated, existing and in good standing or to have such power and
authority, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA
Material Adverse Effect" means a material adverse effect on the business,
assets, results of operations, condition (financial or otherwise) or prospects
of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries
is duly qualified, licensed or admitted to do business and is in good standing
in each jurisdiction in which the ownership, use or leasing of its assets and
properties, or the conduct or nature of its business, makes such qualification,
licensing or admission necessary, except where failure to be so qualified,
licensed or admitted and in good standing, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect. Section
4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA
concurrently with the execution and delivery of this Agreement (the "EUA
Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or
organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized
capital stock, (iii) the number of issued and outstanding shares of capital
stock of such Subsidiary and (iv) the number of shares of such Subsidiary held
of record by EUA. EUA has previously delivered to NEES correct and complete
copies of the EUA Trust Agreement and the certificate or articles of
organization or incorporation and bylaws (or other comparable charter documents)
of its Subsidiaries.
(b) Section 4.01 of the EUA Disclosure Letter sets forth a
description as of the date hereof, of all EUA Associates, including (i) the name
of each such entity and EUA's interest therein and (ii) a brief description of
the principal line or lines of business conducted by each such entity. For
purposes of this Agreement "EUA Associates" shall mean any corporation or other
entity (including partnerships and other business associations) that is not a
Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly
or indirectly, owns an equity interest (other than short-term investments in the
ordinary course of business) if such corporation or other entity (including
partnerships and other business associations) contributes five percent or more
of EUA's consolidated revenues, assets, income or costs.
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<PAGE>
4.02 Capital Stock. (a) The authorized equity securities of EUA
consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and
outstanding as of the close of business on January 29, 1999. As of the close of
business on January 29, 1999, no EUA Shares were held in the treasury of EUA.
Since such date there has been no change in the sum of the issued and
outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly
authorized, validly issued, fully paid and nonassessable. Except pursuant to
this Agreement and except as described in Section 4.02 of the EUA Disclosure
Letter, on the date hereof there are no outstanding subscriptions, options,
warrants, rights (including share appreciation rights), preemptive rights or
other contracts, commitments, understandings or arrangements, including any
right of conversion or exchange under any outstanding security, instrument or
agreement (together, "Options"), obligating EUA or any of its Subsidiaries to
issue or sell any shares of equity securities of EUA or to grant, extend or
enter into any Option with respect thereto. The EUA Disclosure Letter sets forth
all capital stock authorized, issued and outstanding at subsidiary levels as of
the close of business on January 29, 1999.
(b) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the
outstanding shares of capital stock of each Subsidiary of EUA are duly
authorized, validly issued, fully paid and nonassessable and are owned,
beneficially and of record, by EUA or a Subsidiary, which is wholly owned,
directly or indirectly, by EUA, free and clear of any liens, claims, mortgages,
encumbrances, pledges, security interests, equities and charges of any kind
(each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date
of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i)
outstanding Options obligating EUA or any of its Subsidiaries to issue or sell
any shares of capital stock of any Subsidiary of EUA or to grant, extend or
enter into any such Option or (ii) voting trusts, proxies or other commitments,
understandings, restrictions or arrangements in favor of any person other than
EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with
respect to the voting of, or the right to participate in, dividends or other
earnings on any capital stock of any Subsidiary of EUA.
(c) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are
no outstanding contractual obligations of EUA or any Subsidiary of EUA to
repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of
any Subsidiary of EUA or to provide funds to, or make any investment (in the
form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or
any other person.
(d) As of the date of this Agreement, no bonds, debentures,
notes or other indebtedness of EUA or any Subsidiary of EUA having the right to
vote (or which are convertible into or exercisable for securities having the
right to vote) (together "EUA Voting Debt") on any matters on which Shareholders
may vote are issued or outstanding nor are there any outstanding Options
obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt
or to grant, extend or enter into any Option with respect thereto.
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4.03 Authority. EUA has full power and authority to enter into this
Agreement, to perform its obligations hereunder and, subject to obtaining EUA
Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required
Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger
and other transactions contemplated hereby. The execution, delivery and
performance of this Agreement by EUA and the consummation by EUA of the Merger
and other transactions contemplated hereby have been duly authorized by all
necessary action on the part of EUA, subject to obtaining EUA Shareholders'
Approval with respect to the consummation of the Merger and the other
transactions contemplated hereby. This Agreement has been duly and validly
executed and delivered by EUA and constitutes a legal, valid and binding
obligation of EUA enforceable against EUA in accordance with its terms, except
as enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
4.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by EUA do not, and the performance by EUA of its
obligations hereunder and the consummation of the Merger and other transactions
contemplated hereby will not, conflict with, result in a violation or breach of,
constitute (with or without notice or lapse of time or both) a default under,
result in or give to any person any right of payment or reimbursement,
termination, cancellation, modification or acceleration of, or result in the
creation or imposition of any Lien upon any of the assets or properties of EUA
or any of its Subsidiaries or any of the terms, conditions or provisions of (i)
the EUA Trust Agreement or the certificates or articles of incorporation or
organization or bylaws (or other comparable charter documents) of EUA's
Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval,
EUA Required Consents, EUA Required Statutory Approvals and the taking of any
other actions described in this Section 4.04, (x) any statute, law, rule,
regulation or ordinance (together, "laws"), or any judgment, decree, order,
writ, permit or license (together, "orders"), of any court, tribunal,
arbitrator, authority, agency, commission, official or other instrumentality of
the United States, any foreign country or any domestic or foreign state, county,
city or other political subdivision (a "Governmental Authority") applicable to
EUA or any of its Subsidiaries or any of their respective assets or properties,
or (y) subject to obtaining the third-party consents set forth in Section 4.04
of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond,
mortgage, security agreement, indenture, license, franchise, permit, concession,
contract, lease or other instrument, obligation or agreement of any kind
(together, "Contracts") to which EUA or any of its Subsidiaries is a party or by
which EUA or any of its Subsidiaries or any of their respective assets or
properties is bound, excluding from the foregoing clauses (x) and (y) such
conflicts, violations, breaches, defaults, payments or reimbursements,
terminations, cancellations, modifications, accelerations and creations and
impositions of Liens which, individually or in the aggregate, could not
reasonably be expected to have an EUA Material Adverse Effect.
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(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by EUA or the consummation by
EUA of the Merger and other transactions contemplated hereby except as described
in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain
could not reasonably be expected to result in an EUA Material Adverse Effect
(the "EUA Required Statutory Approvals," it being understood that references in
this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean
making such declarations, filings or registrations; giving such notices;
obtaining such authorizations, consents or approvals; and having such waiting
periods expire as are necessary to avoid a violation of law).
4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA
delivered to NEES prior to the execution of this Agreement a true and complete
copy of each form, report, schedule, registration statement, registration
exemption, if applicable, definitive proxy statement and other document
(together with all amendments thereof and supplements thereto) filed by EUA or
any of its Subsidiaries with the Securities and Exchange Commission (the "SEC")
under the Securities Act of 1933, as amended, and the rules and regulations
thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as
amended, and the rules and regulations thereunder (the "Exchange Act") since
December 31, 1995 (as such documents have since the time of their filing been
amended or supplemented, the "EUA SEC Reports"), which are all the documents
(other than preliminary materials) that EUA and its Subsidiaries were required
to file with the SEC under the Securities Act and the Exchange Act since such
date. As of their respective dates, EUA SEC Reports (i) complied as to form in
all material respects with the requirements of the Securities Act or the
Exchange Act, as the case may be, and (ii) did not contain any untrue statement
of a material fact or omit to state a material fact required to be stated
therein or necessary in order to make the statements therein, in light of the
circumstances under which they were made, not misleading. Each of the audited
consolidated financial statements and unaudited interim consolidated financial
statements (including, in each case, the notes, if any, thereto) included in EUA
SEC Reports (the "EUA Financial Statements") complied as to form in all material
respects with the published rules and regulations of the SEC with respect
thereto, were prepared in accordance with U.S. generally accepted accounting
principles ("US GAAP") applied on a consistent basis during the periods involved
(except as may be indicated therein or in the notes thereto and except with
respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly
present (subject, in the case of the unaudited interim financial statements, to
normal, recurring year-end audit adjustments (which are not expected to be,
individually or in the aggregate, materially adverse to EUA and its Subsidiaries
taken as a whole)) the consolidated financial position of EUA and its
consolidated subsidiaries as at the respective dates thereof and the
consolidated results of their operations and cash flows for the respective
periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure
Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in
EUA Financial Statements for all periods covered thereby.
(b) All filings (other than immaterial filings) required to be
made by EUA or any of its Subsidiaries since December 31, 1995, under the Public
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Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the
Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state
laws and regulations, have been filed with the SEC, the Federal Energy
Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the
Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission
(the "FCC") or any appropriate state public utility commissions (including,
without limitation, to the extent required, the state public utility regulatory
agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and
Connecticut as the case may be, including all forms, statements, reports,
agreements (oral or written) and all documents, exhibits, amendments and
supplements appertaining thereto, including but not limited to all rates,
tariffs, franchises, service agreements and related documents and all such
filings complied, as of their respective dates, in all material respects with
all applicable requirements of the appropriate statutes and the rules and
regulations thereunder.
4.06 Absence of Certain Changes or Events. Except as set forth in
Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports
filed prior to the date of this Agreement since December 31, 1997, EUA and each
of EUA's Subsidiaries have conducted its business only in the ordinary course of
business consistent with past practice and there has not been, and no fact or
condition exists which, individually or in the aggregate, has or could
reasonably be expected to have an EUA Material Adverse Effect.
4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed
prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure
Letter and except for environmental matters which are governed by Section 4.13,
(i) there are no actions, claims, hearings, suits, arbitrations or proceedings
pending or, to the knowledge of EUA or any of its Subsidiaries, threatened
against, specifically relating to or affecting, and, to the knowledge of EUA or
any of its Subsidiaries, there are no Governmental Authority investigations or
audits pending or threatened against, specifically relating to or affecting, EUA
or any of its Subsidiaries or any of their respective assets and properties
which, individually or in the aggregate, could reasonably be expected to have an
EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is
subject to any order of any Governmental Authority which, individually or in the
aggregate, could reasonably be expected to have an EUA Material Adverse Effect.
4.08 Information Supplied. (a) The proxy statement relating to EUA
Shareholders' Meeting, as amended or supplemented from time to time (as so
amended and supplemented, the "Proxy Statement"), and any other documents to be
filed by EUA with the SEC (including, without limitation, under the 1935 Act) or
any other Governmental Authority in connection with the Merger and other
transactions contemplated hereby will comply as to form in all material respects
with the requirements of the Exchange Act, the Securities Act and the 1935 Act,
as applicable, and will not, on the date of their respective filings or, in the
case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and
at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain
any untrue statement of a material fact or omit to state any material fact
necessary in order to make the statements therein, in light of the circumstances
under which they are made, not misleading.
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(b) Notwithstanding the foregoing provisions of this Section
4.08, no representation or warranty is made by EUA with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by NEES or LLC for inclusion or incorporation by reference therein.
4.09 Compliance. Except as set forth in Section 4.09 of the EUA
Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date
hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the
knowledge of EUA, under investigation with respect to any violation of, or has
been given notice or been charged with any violation of, any law, statute,
order, rule, regulation, ordinance or judgment (including, without limitation,
any applicable environmental law, ordinance or regulation) of any Governmental
Authority, except for possible violations which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as
disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's
Subsidiaries have all permits, licenses, franchises and other governmental
authorizations, consents and approvals necessary to conduct their businesses as
presently conducted except for such failures which could not reasonably be
expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's
Subsidiaries is in breach or violation of, or in default in the performance or
observance of any term or provision of, (i) the EUA Trust Agreement, in the case
of EUA, or articles of incorporation or organization or by-laws, in the case of
EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture,
mortgage, loan agreement, note, lease, bond, license, approval or other
instrument to which it is a party or by which EUA or any Subsidiary of EUA is
bound or to which any of their respective property is subject, except for
possible violations, breaches or defaults which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure
Letter:
(a) Filing of Timely Tax Returns. EUA and each of its
Subsidiaries have timely filed all Tax Returns required to be filed by each of
them under applicable law. All Tax Returns were (and, as to Tax Returns not
filed as of the date hereof, will be) true, complete and correct;
(b) Payment of Taxes. EUA and each of its Subsidiaries have,
within the time and in the manner prescribed by law, paid (and until the Closing
Date will pay within the time and in the manner prescribed by law) all Taxes
that are currently due and payable except for those contested in good faith and
for which adequate reserves have been taken;
(c) Tax Reserves. EUA and its Subsidiaries have established (and
until the Closing Date will maintain) on their books and records adequate
reserves for all Taxes and for any liability for deferred income taxes in
accordance with GAAP;
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(d) Extensions of Time for Filing Tax Returns. Neither EUA nor
any of its Subsidiaries has requested any extension of time within which to file
any Tax Return, which Tax Return has not since been filed;
(e) Waivers of Statute of Limitations. Neither EUA nor any of
its Subsidiaries has in effect any extension, outstanding waivers or comparable
consents regarding the application of the statute of limitations with respect to
any Taxes or Tax Returns;
(f) Expiration of Statute of Limitations. The Tax Returns of
EUA, each of its Subsidiaries and any affiliated, consolidated, combined or
unitary group that includes EUA or any of its Subsidiaries either have been
examined and settled with the appropriate Tax authority or closed by virtue of
the expiration of the applicable statute of limitations for all years through
and including 1993;
(g) Audit, Administrative and Court Proceedings. No audits or
other administrative proceedings or court proceedings are presently pending or
threatened with regard to any Taxes or Tax Returns of EUA or any of its
Subsidiaries (other than those being contested in good faith and for which
adequate reserves have been established) and no issues have been raised in
writing by any Tax authority in connection with any Tax or Tax Return;
(h) Tax Liens. There are no Tax liens upon any asset of EUA or
any of its Subsidiaries except liens for Taxes not yet due.
(i) Powers of Attorney. No power of attorney currently in force
has been granted by EUA or any of its Subsidiaries concerning any Tax matter;
(j) Tax Rulings. Neither EUA nor any of its Subsidiaries has,
during the five year period prior to the date of this Agreement, received a Tax
Ruling (as defined below) or entered into a Closing Agreement (as defined below)
with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a
written ruling of a taxing authority relating to Taxes. "Closing Agreement", as
used in this Agreement, shall mean a written and legally binding agreement with
a taxing authority relating to Taxes;
(k) Availability of Tax Returns. EUA and its Subsidiaries have
made available to NEES complete and accurate copies, covering all years ending
on or after December 31, 1993, of (i) all Tax Returns, and any amendments
thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports
received from any taxing authority relating to any Tax Return filed by EUA or
any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or
any of its Subsidiaries with any taxing authority.
(l) Tax Sharing Agreements. No agreements relating to the
allocation or sharing of Taxes exist between or among EUA and any of its
Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member
of an affiliated group filing a consolidated federal income tax return (other
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than a group the common parent of which was EUA) or (ii) has any liability for
Taxes of any Person (other than EUA or its Subsidiaries) under United States
Treasury Regulation Section 1.1502-6 (or any provision of state, local), or
foreign law, as a transferee or successor, by contract or otherwise;
(m) Code Section 481 Adjustments. Neither EUA nor any of its
Subsidiaries is required to include in income any adjustment pursuant to Code
Section 481(a) by reason of a voluntary change in accounting method initiated by
EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has
not proposed any such adjustment or change in accounting method;
(n) Code Sections 6661 and 6662. All transactions that could
give rise to an understatement of federal income tax, and within the meaning of
Code Section 6662 have been adequately disclosed (or, with respect to Tax
Returns filed following the Closing, will be adequately disclosed) on the Tax
Returns of EUA and its Subsidiaries in accordance with Code Section
6662(d)(2)(B);
(o) Intercompany Transactions. Neither EUA nor any of its
Subsidiaries has engaged in any intercompany transactions within the meaning of
Treasury Regulations ss. 1.1502-13 for which any income or gain will remain
unrecognized as of the close of the last taxable year prior to the Closing Date;
and
(p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries
is required to file a foreign tax return.
"Taxes" as used in this Agreement, shall mean any federal, state,
county, local or foreign taxes, charges, fees, levies, or other assessments,
including all net income, gross income, premiums, sales and use, ad valorem,
transfer, gains, profits, windfall profits, excise, franchise, real and personal
property, gross receipts, capital stock, production, business and occupation,
employment, disability, payroll, license, estimated, stamp, custom duties,
severance or withholding taxes, other taxes or similar charges of any kind
whatsoever imposed by any governmental entity, whether imposed directly on a
Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar
provision of state, local or foreign law), as a transferee or successor, by
contract or otherwise and includes any interest and penalties on or additions to
any such taxes or in respect of a failure to comply with any requirement
relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a
report, return or other information required to be supplied to a governmental
entity with respect to Taxes including, where permitted or required, combined,
unitary or consolidated returns for any group of entities.
4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan"
(as defined in Section 3(3) of the Employee Retirement Income Security Act of
1974, as amended ("ERISA")), bonus, deferred compensation, share option or other
written agreement relating to employment or fringe benefits for employees,
former employees, officers, trustees or directors of EUA or any of its
Subsidiaries effective as of the date hereof or providing benefits as of the
date hereof to current employees, former employees, officers, trustees or
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directors of EUA or pursuant to which EUA or any of its subsidiaries has or
could reasonably be expected to have any liability (collectively, the "EUA
Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure
Letter, is in material compliance with applicable law, and has been administered
and operated in all material respects in accordance with its terms. Each EUA
Employee Benefit Plan which is intended to be qualified within the meaning of
Section 401(a) of the Code has received a favorable determination letter from
the IRS as to such qualification and, to the knowledge of EUA, no event has
occurred and no condition exists which could reasonably be expected to result in
the revocation of, or have any adverse effect on, any such determination.
(b) Complete and correct copies of the following documents have
been made available to NEES as of the date of this Agreement: (i) all EUA
Employee Benefit Plans and any related trust agreements or insurance contracts,
(ii) the most current summary descriptions of each EUA Employee Benefit Plan
subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto
for each EUA Employee Benefit Plan subject to such reporting, (iv) the most
recent determination of the IRS with respect to the qualified status of each EUA
Employee Benefit Plan that is intended to qualify under Section 401(a) of the
Code, (v) the most recent accountings with respect to each EUA Employee Benefit
Plan funded through a trust and (vi) the most recent actuarial report of the
qualified actuary of each EUA Employee Benefit Plan with respect to which
actuarial valuations are conducted.
(c) Except as set forth in Section 4.11(c) of the EUA Disclosure
Letter, neither EUA nor any Subsidiary maintains or is obligated to provide
benefits under any EUA Employee Benefit Plan (other than as an incidental
benefit under a Plan qualified under Section 401(a) of the Code) which provides
health or welfare benefits to retirees or other terminated employees other than
benefit continuations as required pursuant to Section 601 of ERISA. Each EUA
Employee Benefit Plan subject to the requirements of Section 601 of ERISA has
been operated in material compliance therewith. EUA has not contributed to a
nonconforming group health plan (as defined in Code Section 5000(c)) and no
person under common control with EUA within the meaning of Section 414 of the
Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a)
that is or could reasonably be expected to be a liability of EUA's.
(d) Except as set forth in Section 4.11(d) of the EUA Disclosure
Letter, each EUA Employee Benefit Plan covers only employees who are employed by
EUA or a Subsidiary (or former employees or beneficiaries with respect to
service with EUA or a Subsidiary).
(e) Except as set forth in Section 4.11(e) of the EUA Disclosure
Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other
corporation or organization controlled by or under common control with any of
the foregoing within the meaning of Section 4001 of ERISA has, within the
five-year period preceding the date of this Agreement, at any time contributed
to any "multiemployer plan," as that term is defined in Section 4001 of ERISA.
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(f) No event has occurred, and there exists no condition or set
of circumstances in connection with any EUA Employee Benefit Plan, under which
EUA or any Subsidiary, directly or indirectly (through any indemnification
agreement or otherwise), could be subject to any liability under Section 409 of
ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code
except for instances of non-compliance which, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect.
(g) Neither EUA nor any ERISA Affiliate has incurred any
liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section
302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been
satisfied in full and no event or condition exists or has existed which could
reasonably be expected to result in any such material liability. As of the date
of this Agreement, no "reportable event" within the meaning of Section 4043 of
ERISA has occurred with respect to any EUA Employee Benefit Plan that is a
defined benefit plan under Section 3(35) of ERISA.
(h) Except as set forth in Section 4.11(h) of the EUA Disclosure
Letter, no employer securities, employer real property or other employer
property is included in the assets of any EUA Employee Benefit Plan.
(i) Full payment has been made of all material amounts which EUA
or any affiliate thereof was required under the terms of EUA Employee Benefit
Plans to have paid as contributions to such plans on or prior to the Effective
Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which
is subject to Part III of Subtitle B of Title I of ERISA has incurred any
"accumulated funding deficiency" within the meaning of Section 302 of ERISA or
Section 412 of the Code, whether or not waived.
(j) Except as set forth in Section 4.11(j) of the EUA Disclosure
Letter, no amounts payable under any EUA Employee Benefit Plan or other
agreement, contract, or arrangement will fail to be deductible for federal
income tax purposes by virtue of Section 280G or Section 162(m) of the Code.
4.12 Labor Matters. As of the date hereof, except as set forth in
Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries is a party to any material collective bargaining agreement or other
labor agreement with any union or labor organization. To the knowledge of EUA,
as of the date hereof, there is no current union representation question
involving employees of EUA or any of its Subsidiaries, nor does EUA know of any
activity or proceeding of any labor organization (or representative thereof) or
employee group to organize any such employees. Except as set forth in Section
4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice,
employment discrimination or other employment-related complaint or proceeding
against EUA or any of its Subsidiaries pending or, to the knowledge of EUA,
threatened, which has or could reasonably be expected to have an EUA Material
Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or
lockout pending, or, to the knowledge of EUA, threatened, against or involving
EUA or any of its Subsidiaries which has or could reasonably be expected to
have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim,
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suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries,
threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any
Governmental Authority investigation pending or threatened, in respect of which
any trustee, director, officer, employee or agent of EUA or any of its
Subsidiaries is or may be entitled to claim indemnification from EUA or any of
its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and
their respective articles of incorporation and by-laws, in the case of EUA's
Subsidiaries, or as provided in the indemnification agreements listed in Section
4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the
EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all
federal, state and local laws with respect to employment practices and labor
relations, including, without limitation, any provisions relating to affirmative
action, employment discrimination, wages, hours, collective bargaining, and the
payment of social security and similar taxes, safety and health regulations and
mass layoffs and plant closings except for such instances of noncompliance
which, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect.
4.13 Environmental Matters. Except as disclosed in EUA SEC Reports
filed prior to the date of this Agreement or in Section 4.13 of the EUA
Disclosure Letter:
(a) (i) Each of EUA and its Subsidiaries is in compliance with
all applicable Environmental Laws (as hereinafter defined), except where the
failure to be in compliance, in the aggregate could not reasonably be expected
to result in an EUA Material Adverse Effect; and
(ii) Neither EUA nor any of its Subsidiaries has received
any written communication from any person or Governmental Authority that alleges
that EUA or any of its Subsidiaries is not in such compliance (including the
materiality qualifier set forth in clause (i) above) with applicable
Environmental Laws.
(b) Each of EUA and its Subsidiaries has obtained all
environmental, health and safety permits and governmental authorizations
(collectively, the "Environmental Permits") necessary for the construction of
their facilities and the conduct of their operations, as applicable, and all
such Environmental Permits are in good standing or, where applicable, a renewal
application has been timely filed and agency approval is expected in the
ordinary course of business, and EUA and its Subsidiaries are in compliance with
all terms and conditions of the Environmental Permits, except where the failure
have such Environmental Permits, file a renewal application for such
Environmental Permits, or to be in compliance with such Environmental Permits,
in the aggregate could not reasonably be expected to result in an EUA Material
Adverse Effect.
(c) There is no Environmental Claim (as hereinafter defined)
that could, individually or in the aggregate, reasonably be expected to have an
EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries;
(ii) against any person or entity whose liability for any Environmental Claim
EUA or any of its Subsidiaries has or may have retained or assumed either
contractually or by operation of law; or (iii) against any real or personal
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property or operations which EUA or any of its Subsidiaries owns, leases or
manages, in whole or in part.
(d) To the knowledge of EUA there have not been any material
Releases (as hereinafter defined) of any Hazardous Material (as hereinafter
defined) that would be reasonably likely to form the basis of any material
Environmental Claim against EUA or any of its Subsidiaries, or against any
person or entity whose liability for any material Environmental Claim EUA or any
of its Subsidiaries has or may have retained or assumed either contractually or
by operation of law, except for any Environmental Claim that, individually or in
the aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
(e) To the knowledge of EUA with respect to any predecessor of
EUA or any of its Subsidiaries, there is no material Environmental Claim pending
or threatened, and there has been no Release of Hazardous Materials that could
reasonably be expected to form the basis of any material Environmental Claim
except for any Environmental Claim that, individually or in the aggregate, could
not be reasonably be expected to have an EUA Material Adverse Effect.
(f) As used in this Section 4.13:
(i) "Environmental Claim" means any and all written
administrative, regulatory or judicial actions, suits, demands, demand letters,
directives, claims, liens, investigations, proceedings or notices or
noncompliance, liability or violation by any person or entity (including any
Governmental Authority) alleging potential liability (including, without
limitation, potential responsibility or liability for enforcement, investigatory
costs, cleanup costs, governmental response costs, removal costs, remedial
costs, natural resources damages, property damages, personal injuries or
penalties) arising out of, based on or resulting from
(A) the presence, or Release or threatened Release into the
environment, of any Hazardous Materials at any
location, whether or not owned, operated, leased or
managed by EUA or any of its Subsidiaries; or
(B) circumstances forming the basis of any violation, or
alleged violation, of any Environmental Law; or
(C) any and all claims by any third party seeking damages,
contribution, indemnification, cost recovery,
compensation or injunctive relief resulting from the
presence or Release of any Hazardous Materials;
(ii) "Environmental Laws" means all federal, state and local
laws, rules and regulations and binding interpretation thereof, relating to
pollution, the environment (including, without limitation, ambient air, surface
water, groundwater, land surface or subsurface strata) or protection of human
health as it relates to the environment including, without limitation, laws and
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regulations relating to Releases or threatened Releases of Hazardous
Materials, or otherwise relating to the manufacture, generation, processing,
distribution, use, treatment, storage, disposal, transport or handling of
Hazardous Materials;
(iii) "Hazardous Materials" means (A) any petroleum or
petroleum products, radioactive materials, asbestos in any form that is or could
become friable, urea formaldehyde foam insulation, and transformers or other
equipment that contain dielectric fluid containing polychlorinated biphenyls;
and (B) any chemicals, materials or substances which are now defined as or
included in the definition of "hazardous substances", "hazardous wastes",
"hazardous materials", "extremely hazardous wastes", "restricted hazardous
wastes", "toxic substances", "toxic pollutants", or words of similar import,
under any Environmental Law; and (c) any other chemical, material, substance or
waste, exposure to which is now prohibited, limited or regulated under any
Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x)
operates or (y) stores, treats or disposes of Hazardous Materials; and
(iv) "Release" means any release, spill, emission, leaking,
injection, deposit, disposal, discharge, dispersal, leaching or migration into
the atmosphere, soil, surface water, groundwater or property.
4.14 Regulation as a Utility. (a) EUA is a public utility holding
company registered under Section 5, and subject to the provisions, of the 1935
Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA
that are "public utility companies" within the meaning of Section 2(a)(5) of the
1935 Act and lists the jurisdictions where each such Subsidiary is subject to
regulation as a public utility company or public service company. Except as set
forth above and as set forth in Section 4.14 of the EUA Disclosure Letter,
neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to
regulation as a public utility or public service company (or similar
designation) by the federal government of the United States, any state in the
United States or any political subdivision thereof, or any foreign country.
(b) As used in this Section 4.14, the terms "subsidiary company"
and "affiliate" shall have the respective meanings ascribed to them in Section
2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act.
4.15 Insurance. Except as set forth in Section 4.15 of the EUA
Disclosure Letter, each of EUA and its Subsidiaries is, and has been
continuously since January 1, 1994, insured with financially responsible
insurers in such amounts and against such risks and losses as are customary in
all material respects for companies in the United States conducting the business
conducted by EUA and its Subsidiaries during such time period. Except as set
forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries has received any notice of cancellation or termination with respect
to any material insurance policy of EUA or any of its Subsidiaries. The
insurance policies of EUA and each of its Subsidiaries are valid and enforceable
policies.
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4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of
EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power
Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a
minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described
in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities").
With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric
Company holds the required operating licenses from the NRC. With respect to the
Yankee Companies, each Yankee Company holds its own operating license from the
NRC. Because it is a minority stockholder or a minority joint owner, Montaup
Electric Company does not have responsibility for the operation of EUA Nuclear
Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or
as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge
of EUA, neither EUA nor any of its Subsidiaries is in violation of any
applicable health, safety, regulatory and other legal requirement, including NRC
laws and regulations and Environmental Laws, applicable to EUA Nuclear
Facilities except for such failure to comply as could not reasonably be expected
to have a material adverse effect with respect to EUA Nuclear Facilities and the
ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear
Facilities maintains emergency plans designed to respond to an unplanned release
therefrom of radioactive materials into the environment and insurance coverages
consistent with industry practice. EUA has funded, or has caused the funding of,
its portion of the decommissioning cost of each of the EUA Nuclear Facilities
and the storage of spent nuclear fuel consistent with the most recently approved
plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as
set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA,
no EUA Nuclear Facility is as of the date of this Agreement on the List of
Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the
NRC.
4.17 Vote Required. The affirmative vote of two-thirds of the
outstanding EUA Shares voting as a single class (with each EUA Share having one
vote per share) with respect to the approval of the Merger and other
transactions contemplated hereby is the only vote of the holders of any class or
series of equity securities of EUA or its Subsidiaries required to approve this
Agreement and approve the Merger and other transactions contemplated hereby.
4.18 Opinion of Financial Advisor. EUA has received the opinion of
Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that,
as of such date, the Merger Consideration is fair from a financial point of view
to the holders of EUA Shares. A true and complete copy of the written opinion
will be delivered to NEES promptly after receipt thereof by EUA.
4.19 Ownership of NEES Common Shares. Neither EUA nor any of its
Subsidiaries or other affiliates beneficially owns any NEES Common Shares.
4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions
so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply
to this Agreement, the Merger or other transactions contemplated hereby or
thereby.
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4.21 Year 2000. The Information Systems operated by EUA and its
Subsidiaries which is used in the conduct of their business is capable of
providing or being adapted to provide uninterrupted millennium functionality to
record, store, process and present calendar dates falling on or after January 1,
2000 in substantially the same manner and with the same functionality as such
Information Systems record, store, process and present such calendar dates
falling on or before December 31, 1999 other than such interruptions in
millennium functionality that could not, individually or in the aggregate,
reasonably be expected to result in a EUA Material Adverse Effect. EUA
reasonably believes as of the date hereof that the remaining cost of adaptations
referred to in the foregoing sentence will not exceed the amounts reflected in
the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding
the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o)
hereof and of the implementation of any recommendations by such Y2K Consultant
actually made by EUA that are not already part of EUA's compliance plan as of
the date hereof). "Information Systems" means mainframe and midrange hardware,
operating system software and applications programs; network and desktop (PC)
hardware, operating system software and applications programs; EDI (Electronic
Date Interchange) and FTP (File Transfer Protocol) software; and embedded
systems hardware and applications software.
4.22 EUA Associates. The representations and warranties set forth in
Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all
material respects with regard to EUA Associates.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES
NEES represents and warrants to EUA as follows:
5.01 Organization and Qualification. NEES is a voluntary association
duly organized, validly existing and in good standing under the laws of the
Commonwealth of Massachusetts and has full power, authority and legal right to
own its property and assets and to transact the business in which it is engaged.
Each of the NEES Subsidiaries is a corporation duly organized or incorporated,
validly existing and in good standing under the laws of its jurisdiction of
organization or incorporation and has full corporate power and authority to
conduct its business as and to the extent now conducted and to own, use and
lease its assets and properties, except where failure to be so organized or
incorporated, existing and in good standing or to have such power and authority,
individually or in the aggregate, could not reasonably be expected to have a
NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material
Adverse Effect" means a material adverse effect on the business, assets, results
of operations, condition (financial or otherwise) or prospects of NEES and its
Subsidiaries taken as a whole. LLC is a limited liability company validly
existing under the laws of the Commonwealth of Massachusetts. LLC was formed
solely for the purpose of engaging in the Merger and other transactions
contemplated hereby, has engaged in no other business activities (other than in
connection with the formation and capitalization of LLC pursuant to or in
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accordance with the LLC Agreement (as defined below)) and has conducted its
operations only as contemplated hereby and by the LLC Agreement. Each of NEES
and its Subsidiaries is duly qualified, licensed or admitted to do business and
is in good standing in each jurisdiction in which the ownership, use or leasing
of its assets and properties, or the conduct or nature of its business, makes
such qualification, licensing or admission necessary, except where failure to be
so qualified, licensed or admitted and in good standing, individually or in the
aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect. NEES has previously delivered to EUA correct and complete copies of its
Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles
of association of LLC.
5.02 Authority. Each of NEES and LLC has full power and authority to
enter into this Agreement, and to perform its obligations hereunder, and to
consummate the Merger and other transactions contemplated hereby. The execution,
delivery and performance of this Agreement by each of NEES and LLC and the
consummation by each of NEES and LLC of the Merger and other transactions
contemplated hereby have been duly authorized by all necessary corporate action
on the part of NEES and all necessary action on the part of LLC. This Agreement
has been duly and validly executed and delivered by each of NEES and LLC and
constitutes a legal, valid and binding obligation of each of NEES and LLC
enforceable against each of NEES and LLC in accordance with its terms, except as
enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
5.03 Capital Stock. The authorized equity securities of NEES consists
of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986
shares were issued and outstanding as of the close of business on January 29,
1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares
were held in the treasury of NEES. All of the issued and outstanding NEES Shares
are duly authorized, validly issued, fully paid and nonassessable. Except as may
be provided by the New England Electric System Companies' Incentive Share Plan,
the New England Electric System Companies Incentive Thrift Plan I, the New
England Electric System Companies Incentive Thrift Plan II, the New England
Electric Companies Long-Term Performance Share Award Plan, and the New England
Electric System Directors' annual retainer shares, and except as set forth in
Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES
and LLC concurrently with the execution and delivery of this Agreement (the
"NEES Disclosure Letter"), on the date hereof there are no outstanding Options
obligating NEES or any of its Subsidiaries to issue or sell any shares of equity
securities of NEES or to grant, extend or enter into any Option with respect
thereto.
5.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by each of NEES and LLC do not, and the performance
by each of NEES and LLC of its obligations hereunder and the consummation of the
Merger and other transactions contemplated hereby will not, conflict with,
result in a violation or breach of, constitute (with or without notice or lapse
of time or both) a default under, result in or give to any person any right of
payment or reimbursement, termination, cancellation, modification or
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acceleration of, or result in the creation or imposition of any Lien upon any of
the assets or properties of NEES, or LLC under, any of the terms, conditions or
provisions of (i) the NEES Agreement and Declaration of Trust or the articles of
organization of LLC, (ii) subject to the actions described in paragraph (b) of
this Section, (x) any laws or orders of any Governmental Authority applicable to
NEES or LLC or any of their respective assets or properties, or (y) subject to
obtaining the third-party consents (the "NEES Required Consents") set forth in
Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a
party or by which NEES or any of its Subsidiaries or any of their respective
assets or properties is bound, excluding from the foregoing clauses (x) and (y)
conflicts, violations, breaches, defaults, terminations, modifications,
accelerations and creations and impositions of Liens which, individually or in
the aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect.
(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by NEES or LLC or the
consummation by NEES or LLC of the Merger and other transactions contemplated
hereby except as described in Section 5.04 of the NEES Disclosure Letter or the
failure of which to obtain could not reasonably be expected to result in a NEES
Material Adverse Effect (the "NEES Required Statutory Approvals," it being
understood that references in this Agreement to "obtaining" such NEES Required
Statutory Approvals shall mean making such declarations, filings or
registrations; giving such notices; obtaining such authorizations, consents or
approvals; and having such waiting periods expire as are necessary to avoid a
violation of law).
5.05 Information Supplied. (a) The information supplied by NEES or LLC
and included in the Proxy Statement with the written consent of NEES or LLC, as
the case may be, will not, at the date mailed to EUA's Shareholders or at the
time of EUA Shareholder's Meeting, contain any untrue statements of a material
fact or omit to state any material fact required to be stated therein or
necessary in order to make the statements therein, in light of the circumstances
under which they were made, not misleading.
(b) Notwithstanding the foregoing provisions of this Section
5.05, no representation or warranty is made by NEES with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by EUA for inclusion or incorporation by reference therein or based on
information which is not made in or incorporated by reference in such documents
but which should have been disclosed pursuant to this Section 5.05.
5.06 Compliance. Except as set forth in Section 5.06 of the NEES
Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date
hereof, NEES is not in violation of, is, to the knowledge of NEES, under
investigation with respect to any violation of, or has been given notice or been
charged with any violation of, any law, statute, order, rule, regulation,
ordinance or judgment (including, without limitation, any applicable
environmental law, ordinance or regulation) of any Governmental Authority,
except for possible violations which, individually or in the aggregate, could
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not reasonably be expected to have a NEES Material Adverse Effect. Except as set
forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES
Reports filed prior to the date hereof, NEES and its Subsidiaries have all
material permits, licenses and other governmental authorizations, consents and
approvals necessary to conduct their businesses as presently conducted which are
material to the operation of the businesses of NEES. NEES is not in breach or
violation of, or in default in the performance or observance of, any term or
provision of, and no event has occurred which, with lapse of time or action by a
third party, could result in a default by NEES under (i) the NEES Agreement and
Declaration of Trust or by-laws or (ii) any contract, commitment, agreement,
indenture, mortgage, loan agreement, note, lease, bond, license, approval or
other instrument to which it is a party or by which NEES is bound or to which
any of their respective property is subject, except for possible violations,
breaches or defaults which, individually or in the aggregate, could not
reasonably be expected to have a NEES Material Adverse Effect.
5.07 Financing. NEES has or will have available, prior to the
Effective Time, sufficient cash in immediately available funds to pay or to
cause LLC to pay the Merger Consideration pursuant to Article II hereof and to
consummate the Merger and other transactions contemplated hereby.
5.08 No Vote Required. No vote of the NEES Shares or of any class or
series of equity securities of NEES or its Subsidiaries is necessary for the
approval of the Merger and other transactions contemplated hereby.
5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries
or other affiliates beneficially owns any EUA Shares.
5.10 Merger with The National Grid Group plc. NEES has entered into an
Agreement and Plan of Merger dated as of December 11, 1998 by and among The
National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly
known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to
Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of
this Agreement to National Grid Group, and National Grid Group has given NEES
its written consent to enter into this Agreement and consummate the Merger on
the terms set forth in this Agreement. Prior to the execution of this Agreement,
NEES has provided EUA with a copy of such written consent.
ARTICLE VI
COVENANTS
6.01 Covenants of EUA. At all times from and after the date hereof
until the Effective Time, EUA covenants and agrees as to itself and its
Subsidiaries that (except as expressly contemplated or permitted by this
Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to
the extent that NEES shall otherwise previously consent in writing):
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(a) Ordinary Course. EUA and each of its Subsidiaries shall
conduct their businesses only in, and EUA and each of its Subsidiaries shall not
take any action except in, the ordinary course consistent with good utility
practice. Without limiting the generality of the foregoing, EUA and its
Subsidiaries shall use all commercially reasonable efforts to preserve intact in
all material respects their present business organizations and reputation, to
maintain in effect all existing permits, to keep available the services of their
key officers and employees, to maintain their assets and properties in good
working order and condition, ordinary wear and tear excepted, to maintain
insurance on their tangible assets and businesses in such amounts and against
such risks and losses as are currently in effect, to preserve their
relationships with customers and suppliers and others having significant
business dealings with them and to comply in all material respects with all laws
and orders of all Governmental Authorities applicable to them.
(b) Charter Documents. EUA shall not, nor shall it permit any of
its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the
case of EUA, and its certificate or articles of incorporation or organization or
bylaws (or other comparable charter documents), in the case of EUA's
Subsidiaries.
(c) Dividends. EUA shall not, nor shall it permit any of its
Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other
distributions in respect of, any of its capital stock or share capital, except:
(A) that EUA may continue the declaration and payment of
regular quarterly dividends on EUA Shares with usual
record and payment dates not, in any fiscal year, in
excess of the dividend for the comparable period in the
prior fiscal year;
(B) that the Subsidiaries of EUA set forth in Section
6.01(c) of the EUA Disclosure Letter may continue the
declaration and payment of dividends on preferred stock
in accordance with the terms of such stock, with the
record and payment dates and in the amounts set forth
in Section 6.01(c) of the EUA Disclosure Letter;
(C) if the Effective Time does not occur between a record
date and payment date of a regular quarterly dividend,
for a special dividend on EUA Shares with respect to
the quarter in which the Effective Time occurs with a
record date on or prior to the date on which the
Effective Time occurs, which does not exceed an amount
equal to the product of (x) the number of days between
the last payment date of a regular quarterly dividend
and the record date of such special dividend,
multiplied by (y) $.0045; and
(D) for dividends and distributions (including liquidating
distributions) by a direct or indirect Subsidiary of
EUA to its parent.
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(ii) split, combine, subdivide, reclassify or take similar action with respect
to any of its capital stock or share capital or issue or authorize or propose
the issuance of any other securities in respect of, in lieu of or in
substitution for shares of its capital stock or comprised in its share capital,
(iii) adopt a plan of complete or partial liquidation or resolutions providing
for or authorizing such liquidation or a dissolution, merger, consolidation,
restructuring, recapitalization or other reorganization or (iv) directly or
indirectly redeem, repurchase or otherwise acquire any shares of its capital
stock or any Option with respect thereto except:
(A) in connection with intercompany purchases of capital
stock or share capital,
(B) for the purpose of funding EUA's dividend reinvestment
and share purchase plan in accordance with past
practice, or
(C) subject to EUA's obligations under the Securities Act
and the Exchange Act, pursuant to EUA's previously
announced share repurchase program provided that the
number of EUA Shares repurchased does not exceed
3,000,000 and the price paid per share does not exceed
95% of the Per Share Amount.
(d) Share Issuances. EUA shall not, nor shall it permit any of
its Subsidiaries to, issue, deliver or sell, or authorize or propose the
issuance, delivery or sale of, any shares of its capital stock or any Option
with respect thereto (other than the issuance by a wholly owned Subsidiary of
its capital stock to its direct or indirect parent corporation, or modify or
amend any right of any holder of outstanding shares of capital stock or Options
with respect thereto).
(e) Acquisitions. EUA shall not, nor shall it permit any of its
Subsidiaries to acquire or agree to acquire (by merging or consolidating with,
or by purchasing a substantial equity interest in or substantial portion of the
assets of, or by any other manner) any business or any corporation, partnership,
association or other business organization or division thereof.
(f) Dispositions. EUA shall not, nor shall it permit any of its
Subsidiaries to sell, lease, securitize, grant any security interest in or
otherwise dispose of or encumber any of its assets or properties, other than
dispositions in the ordinary course of its business consistent with past
practice and having an aggregate value of less than $1,000,000 for each
disposition and $5,000,000 in the aggregate.
(g) Indebtedness. EUA shall not, nor shall it permit any of its
Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed
or guaranteed or otherwise assumed, including, without limitation, the issuance
of debt securities or warrants or rights to acquire debt) or enter into any
"keep well" or other agreement to maintain any financial condition of another
Person or enter into any arrangement having the economic effect of any of the
foregoing other than (i) short-term indebtedness in the ordinary course of
business consistent with past practice (such as the issuance of commercial paper
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or the use of existing credit facilities) in amounts not exceeding the amounts
set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term
indebtedness in connection with the refinancing of existing indebtedness either
at its stated maturity or at a lower cost of funds (calculating such cost on an
aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in
favor of wholly owned Subsidiaries of EUA in connection with the conduct of the
business of such wholly owned Subsidiaries of EUA not aggregating more than
$1,000,000.
(h) Capital Expenditures. Except (i) as required by law or (ii)
as reasonably deemed necessary by EUA after consulting with NEES following a
catastrophic event, such as a major storm, EUA shall not, nor shall it permit
any of its Subsidiaries to make any capital expenditures or commitments during
any fiscal year that is in excess of 110% of (i) the aggregate amount set forth
in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its
Subsidiaries that are public utility companies within the meaning of Section
2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the
EUA Disclosure Letter with respect to each of EUA's other Subsidiaries.
(i) Employee Benefits. EUA shall not, nor shall it permit any of
its Subsidiaries to enter into, adopt, amend (except as may be required by
applicable law) or terminate any EUA Employee Benefit Plan, or other agreement,
arrangement, plan or policy between EUA or one of its Subsidiaries and one or
more of its trustees, directors, officers, employees or former employees, or,
except for normal increases in the ordinary course of business, (a) increase in
any manner the compensation or fringe benefits of any trustee, director or
executive officer, (b) increase in any manner the compensation or fringe
benefits of any employee, (c) pay any benefit not required by any plan or
arrangement in effect as of the date hereof or, (d) cause any trustee, director,
officer, employee or former employee of EUA to accrue or receive additional
benefits, accelerate vesting or accelerate the payment of any benefits under any
EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA,
prior to the Closing Date, shall take all necessary action and make all
necessary amendments to its stock-based plans so that all such plans will be in
a form that allows the plans to function after the Effective Time and after any
merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to
the Closing Date, shall take all necessary actions, in a manner satisfactory to
NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity
nor their affiliates' stock or securities will be required to be held in, or
distributed pursuant to, any EUA Employee Benefit Plan.
(j) Labor Matters. Notwithstanding any other provision of this
Agreement to the contrary, EUA or its Subsidiaries may negotiate successor
collective bargaining agreements to those referenced in Section 4.12 hereof, and
may negotiate other collective bargaining agreements or arrangements as required
by law or for the purpose of implementing the agreements referenced in Section
4.12 hereof. EUA will keep NEES informed as to the status of, and will consult
with NEES as to the strategy for, all negotiations with collective bargaining
representatives. EUA and its Subsidiaries shall act prudently and reasonably and
consistent with their obligation under applicable law in such negotiations.
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(k) Discharge of Liabilities. EUA shall not, nor shall it permit
its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities
or obligations (absolute, accrued, asserted or unasserted, contingent or
otherwise), other than the payment, discharge or satisfaction, in the ordinary
course of business consistent with past practice (which includes the payment of
final and unappealable judgments) or in accordance with their terms, of
liabilities reflected or reserved against in, or contemplated by, the most
recent consolidated financial statements (or the notes thereto) of such party
included in EUA SEC Reports, or incurred in the ordinary course of business
consistent with past practice.
(l) Contracts. EUA shall not, nor shall it permit its
Subsidiaries, except in the ordinary course of business consistent with past
practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to
modify, amend, terminate or fail to use commercially reasonable efforts to renew
any material Contract to which EUA or any of its Subsidiaries is a party or
waive, release or assign any material rights or claims or (ii) to enter into any
new material Contracts except as expressly permitted by Sections 6.01 (f), (g)
or (i) and 7.06 hereof.
(m) Equity Investments. EUA shall not, nor shall it permit its
Subsidiaries or affiliates to, make equity contributions to non-affiliates or to
its non-utility Subsidiaries.
(n) Loans. EUA shall not, nor shall it permit its Subsidiaries
or affiliates to, loan money to non-affiliates or to its non-utility
Subsidiaries.
(o) Year 2000. EUA, within 15 days of the date of this
Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a
detailed assessment of the adequacy and state of completion of its Year 2000
Program, including but not limited to assessment and testing of its customer,
accounting, and operational systems. The Y2K Consultant and scope of work of the
Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be
completed as soon thereafter as practicable. EUA shall have such assessment
updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA
shall allow designated NEES personnel and representatives access to the Y2K
Consultant's personnel, reports and recommendations and access to EUA's
personnel, documents, and information related to the Y2K issue. EUA and the
third party shall meet with such designated NEES personnel and representatives
on a periodic basis (but not less frequently than monthly) to update NEES on
EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section
9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K
Consultant.
(p) Insurance. EUA shall, and shall cause its Subsidiaries to,
maintain with financially responsible insurance companies (or through
self-insurance, consistent with past practice) insurance in such amounts and
against such risks and losses as are customary for companies engaged in their
respective businesses.
(q) 1935 Act. EUA shall not, nor shall it permit any of its
Subsidiaries to, engage in any activities which would cause a change in its
status, or that of its Subsidiaries, under the 1935 Act.
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(r) Regulatory Matters. Subject to applicable law and except for
non-material filings in the ordinary course of business consistent with past
practice, EUA shall consult with NEES prior to implementing any changes in its
or any of its Subsidiaries' rates or charges, standards of service or accounting
or executing any agreement with respect thereto that is otherwise permitted
under this Agreement and shall, and shall cause its Subsidiaries to, deliver to
NEES a copy of each such filing or agreement at least four (4) business days
prior to the filing or execution thereof so that NEES may comment thereon. EUA
shall, and shall cause its Subsidiaries to, make all such filings (i) only in
the ordinary course of business consistent with past practice or (ii) as
required by a Governmental Authority or regulatory agency with appropriate
jurisdiction.
(s) Accounting. EUA shall not, nor shall it permit any of its
Subsidiaries to make any changes in their accounting methods, policies or
procedures, except as required by law, rule, regulation or applicable generally
accepted accounting principles;
(t) Tax Status. Neither EUA nor any of its Subsidiaries shall
(i) make or rescind any material express or deemed election relating to Taxes,
(ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii)
settle or compromise any material claim, action, suit, litigation, proceeding,
arbitration, investigation, audit, or controversy relating to Taxes or (iv)
change in any material respect any of its methods of reporting income,
deductions or accounting for federal income tax purposes from those employed in
the preparation of its federal income Tax Return for the taxable year ending
December 31, 1997, except as may be required by applicable law.
(u) No Breach. EUA shall not, nor shall it permit any of its
Subsidiaries to willfully take or fail to take any action that would or is
reasonably likely to result in (i) a material breach of any provision of this
Agreement or (ii) its representations and warranties set forth in this Agreement
being untrue in any material respect on and as of the Closing Date.
(v) Advice of Changes. EUA shall confer with NEES on a regular
and frequent basis with respect to EUA's business and operations and other
matters relevant to the Merger to the extent permitted by law, and shall
promptly advise NEES, orally and in writing, of any material change or event,
including, without limitation, any complaint, investigation or hearing by any
Governmental Authority (or communication indicating the same may be
contemplated) or the institution or threat of material litigation; provided that
EUA shall not be required to make any disclosure to the extent such disclosure
would constitute a violation of any applicable law or regulation.
(w) Notice and Cure. EUA will notify NEES in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to EUA, that causes or will or may be likely to cause any covenant or agreement
of EUA under this Agreement to be breached or that renders or will render untrue
in any material respect any representation or warranty of EUA contained in this
Agreement. EUA also will notify NEES in writing of, and will use all
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commercially reasonable efforts to cure, before the Closing, any material
violation or breach, as soon as practical after it becomes known to EUA, of any
representation, warranty, covenant or agreement made by EUA. No notice given
pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(x) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, EUA will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to the other's obligations contained in
this Agreement and to consummate and make effective the Merger and other
transactions contemplated by this Agreement, and EUA will not, nor will it
permit any of its Subsidiaries to, take or fail to take any action that could be
reasonably expected to result in the nonfulfillment of any such condition.
(y) Third Party Standstill Agreements. Except as provided in
Section 7.08 hereto, during the period from the date of this Agreement through
the Effective Time, neither EUA nor any of its Subsidiaries shall terminate,
amend, modify or waive any provision of any confidentiality or standstill
agreement to which it is a party. During such period, EUA shall take all steps
necessary to enforce, to the fullest extent permitted under applicable law, the
provisions of any such agreement.
6.02 Covenants of NEES. At all times from and after the date hereof
until the Effective Time, NEES covenants and agrees that (except as expressly
contemplated or permitted by this Agreement or to the extent that EUA shall
otherwise previously consent in writing):
(a) No Breach. NEES shall not, nor shall it permit any of its
Subsidiaries to, except as otherwise expressly provided for in this Agreement,
willfully take or fail to take any action that would or is reasonably likely to
result in (i) a material breach of any of its covenants or agreements contained
in this Agreement or (ii) any of its representations and warranties set forth in
Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this
Agreement being untrue in any material respect on and as of the Closing Date.
(b) Advice of Changes. NEES shall confer with EUA on a regular
and frequent basis with respect to any matter having, or which, insofar as can
be reasonably foreseen, could reasonably be expected to have, a NEES Material
Adverse Effect or materially impair the ability of NEES to consummate the Merger
and other transactions contemplated hereby; provided that NEES shall not be
required to make any disclosure to the extent such disclosure would constitute a
violation of any applicable law or regulation.
(c) Notice and Cure. NEES will notify EUA in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to NEES, that causes or will or may be likely to cause any covenant or agreement
of NEES under this Agreement to be breached or that renders or will render
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untrue in any material respect any representation or warranty of NEES contained
in this Agreement. NEES also will notify EUA in writing of, and will use all
commercially reasonable efforts to cure before the Closing, any material
violation or breach, as soon as practical after it becomes known to such party,
of any representation, warranty, covenant or agreement made by NEES. No notice
given pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(d) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, NEES will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to its obligations contained in this
Agreement and to consummate and make effective the Merger and other transactions
contemplated by this Agreement, and NEES will not, nor will it permit any of its
Subsidiaries to, take or fail to take any action that could be reasonably
expected to result in the nonfulfillment of any such condition.
(e) Conduct of Business of LLC. Prior to the Effective Time,
except as may be required by applicable law and subject to the other provisions
of this Agreement, NEES shall cause LLC to (i) perform its obligations under
this Agreement in accordance with its terms, and (ii) not engage directly or
indirectly in any business or activities of any type or kind and not enter into
any agreements or arrangements with any person, or be subject to or bound by any
obligation or undertaking, which is inconsistent with this Agreement.
(f) Certain Mergers. NEES shall not, and shall not permit any of
its Subsidiaries to, acquire or agree to acquire by merging or consolidating
with, or by purchasing a substantial portion of the assets of or equity in, or
by any other manner, any business or any corporation, partnership, association
or other business organization or division thereof, or otherwise acquire or
agree to acquire any assets if the entering into of a definitive agreement
relating to or the consummation of such acquisition, merger or consolidation
could reasonably be expected to (i) impose any material delay in the obtaining
of, or significantly increase the risk of not obtaining, any authorizations,
consents, orders, declarations or approvals of any Governmental Authority
necessary to consummate the Merger or the expiration or termination of any
applicable waiting period, (ii) significantly increase the risk of any
Governmental Authority entering an order prohibiting the consummation of the
Merger, (iii) significantly increase the risk of not being able to remove any
such order on appeal or otherwise or (iv) materially delay the consummation of
the Merger.
6.03 Additional Covenants by NEES and EUA.
(a) Control of Other Party's Business. Nothing contained in this
Agreement shall give NEES, directly or indirectly, the right to control or
direct EUA's operations prior to the Effective Time. Nothing contained in this
Agreement shall give EUA, directly or indirectly, the right to control or direct
NEES' operations prior to the Effective Time. Prior to the Effective Time, each
of EUA and NEES shall exercise, consistent with the terms and conditions of this
Agreement, complete control and supervision over its respective operations.
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(b) Transition Steering Team. As soon as reasonably practicable
after the date hereof, NEES and EUA shall create a special transition steering
team, with representation from EUA and NEES, that will develop recommendations
concerning the future structure and operations of EUA after the Effective Time,
subject to applicable law. The members of the transition steering team shall be
appointed by the Chief Executive Officers of NEES and EUA. The functions of the
transition steering team shall include (i) to direct the exchange of information
and documents between the parties and their Subsidiaries as contemplated by
Section 7.01 and (ii) the development of regulatory plans and proposals,
corporate organizational and management plans, workforce combination proposals,
and such other matters as they deem appropriate.
ARTICLE VII
ADDITIONAL AGREEMENTS
7.01 Access to Information. EUA shall, and shall cause each of its
Subsidiaries to, and shall use commercially reasonable efforts to cause EUA
Associates to, throughout the period from the date hereof to the Effective Time
to the extent permitted by law, (i) provide NEES and its Representatives with
full access, upon reasonable prior notice and during normal business hours, to
all facilities, operations, officers (including EUA's environmental, health and
safety personnel), employees, agents and accountants of EUA and its Subsidiaries
and Associates and their respective assets, properties, books and records, to
the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal
obligation not to provide access or to the extent that such access would not
constitute a waiver of the attorney client privilege and does not unreasonably
interfere with the business and operations of EUA and its Subsidiaries and
Associates and (ii) furnish promptly to such persons (x) a copy of each report,
statement, schedule and other document filed or received by EUA or any of its
Subsidiaries pursuant to the requirements of federal or state securities laws
and each material report, statement, schedule and other document filed with any
other Governmental Authority, and (y) all other information and data (including,
without limitation, copies of Contracts, EUA Employee Benefit Plans, and other
books and records) concerning the business and operations of EUA and its
Subsidiaries as NEES or any of its Representatives reasonably may request. No
review pursuant to this Section 7.01 or otherwise shall affect any
representation or warranty contained in this Agreement or any condition to the
obligations of the parties hereto. Any such information or material obtained
pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such
term is defined in the letter agreement dated as of December 18, 1998 between
EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms
of the Confidentiality Agreement. NEES may provide information or materials that
it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01
to National Grid Group; the treatment by National Grid Group of such information
or material shall be governed by the terms of the letter agreement dated as of
December 21, 1998 between EUA and National Grid Group.
7.02 Proxy Statement. As soon as reasonably practicable after the
date of this Agreement, EUA shall prepare and file the Proxy Statement with the
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SEC. NEES and EUA shall cooperate with each other in the preparation of the
Proxy Statement and any amendment or supplement thereto, and EUA shall promptly
notify NEES of the receipt of any comments of the SEC with respect to the Proxy
Statement and of any requests by the SEC for any amendment or supplement thereto
or for additional information, and shall promptly provide to NEES copies of all
correspondence between EUA or any of its Representatives and the SEC with
respect to the Proxy Statement (except reports from financial advisors other
than with the consent of such financial advisors). Each of the parties hereto
shall furnish all information concerning itself which is required or customary
for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the
Proxy Statement and have due regard to any comments NEES may make in relation to
the Proxy Statement. EUA shall give NEES and its counsel the opportunity to
review the Proxy Statement and all responses to requests for additional
information by and replies to comments of the SEC before their being filed with,
or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best
efforts, after consultation with the other parties hereto, to respond promptly
to all such comments of and requests by the SEC. After obtaining the consent of
EUA, which consent shall not be unreasonably withheld, NEES may provide
information supplied to NEES by EUA to National Grid Group for inclusion of such
information in the Super Class 1 circular ("NGG Circular") to be issued to
shareholders of National Grid Group in connection with approval by such
shareholders of the National Grid Merger Agreement. NEES shall use its best
efforts to provide EUA with a draft of any portion of the NGG Circular with
information relating to EUA prior to the issuance of the NGG Circular.
7.03 Approval of Shareholders. EUA shall, through its Board of
Trustees, duly call, give notice of, convene and hold a meeting of its
shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the
approval of the Merger and other transactions contemplated hereby (the "EUA
Shareholders' Approval") as soon as reasonably practicable after the date
hereof; provided, however, subject to the fiduciary duties of its Board of
Trustees and the requirements of applicable law, EUA shall include in the Proxy
Statement the recommendation of the Board of Trustees of EUA that the
Shareholders of EUA approve the Merger and the other transactions contemplated
hereby, and shall use its reasonable best efforts to obtain such approval.
7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party
hereto shall file or cause to be filed with the Federal Trade Commission and the
Department of Justice any notifications required to be filed by its respective
"ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated
thereunder with respect to the Merger and other transactions contemplated
hereby. Such parties will use all commercially reasonable efforts to make such
filings in a timely manner and to respond on a timely basis to any requests for
additional information made by either of such agencies.
(b) Other Regulatory Approvals. Each party shall cooperate and
use its best efforts to promptly prepare and file all necessary applications,
notices, petitions, filings and other documents with, and to use all
commercially reasonable efforts to obtain all necessary permits, consents,
approvals and authorizations of, all Governmental Authorities necessary or
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advisable to obtain the EUA Required Statutory Approvals, the NEES Required
Statutory Approvals and the approvals of the state utility commissions referred
to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The
parties agree that they will consult with each other with respect to obtaining
the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have
primary responsibility for the preparation and filing of any related
applications, filings or other material with the SEC, the FERC, the NRC and
state utility commissions. EUA shall have the right to review and approve in
advance drafts of and final applications, filings and other material (including
material with respect to proposed settlements) submitted to or filed with the
SEC, the FERC, the NRC and state utility commissions or parties to such
proceedings before such Governmental Authority, which approval shall not be
unreasonably withheld or delayed.
(c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge
that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA
Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the
regulatory approvals (the "NEES-NGG Regulatory Approvals") required to
consummate the transactions contemplated by the National Grid Merger Agreement.
NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA
Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the
prosecution by National Grid Group and NEES of the proceedings relating to the
NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but
recognize that one or more of the NEES-EUA Regulatory Proceedings may be
consolidated with one or more of the NEES-NGG Regulatory Proceedings by the
relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA
reasonably apprised of the status of the NEES-NGG Regulatory Proceedings.
7.05 Employee Benefit Plans.
(a) For a period of twelve (12) months immediately following the
Closing Date, the compensation, benefits and coverage provided to those
non-union individuals who continue to be employees of the Surviving Entity (the
"Affected Employees") pursuant to employee benefit plans or arrangements
maintained by NEES or the Surviving Entity shall be, in the aggregate, not less
favorable (as determined by NEES and the Surviving Entity using reasonable
assumptions and benefit valuation methods) than those provided, in the
aggregate, to such Affected Employees immediately prior to the Closing Date. In
addition to the foregoing, NEES shall, or shall cause the Surviving Entity to,
pay any Affected Employee whose employment is terminated by NEES or the
Surviving Entity within twelve (12) months of the Closing Date a severance
benefit package equivalent to the severance benefit package that would be
provided under the NEES Standard Severance Plan as in effect on the date hereof.
(b) NEES shall, or shall cause the Surviving Entity to, give the
Affected Employees full credit for purposes of eligibility, vesting, benefit
accrual (including, without limitation, benefit accrual under any defined
benefit pension plans) and determination of the level of benefits under any
employee benefit plans or arrangements maintained by NEES or the Surviving
Entity in effect as of the Closing Date for such Affected Employees' service
with EUA or any Subsidiary of EUA (or any prior employer) to the same extent
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recognized by EUA or such Subsidiary immediately prior to the Closing Date. With
respect to any employee benefit plan or arrangement established by NEES, EUA or
the Surviving Entity after the Closing Date (the "Post Closing Plans"), service
shall be credited in accordance with the terms of such Post Closing Plans.
(c) NEES shall, or shall cause the Surviving Entity to, (i)
waive all limitations as to preexisting conditions, exclusions and waiting
periods with respect to participation and coverage requirements applicable to
the Affected Employees under any welfare benefit plan established to replace any
EUA welfare benefit plans in which such Affected Employees may be eligible to
participate after the Closing Date, other than limitations or waiting periods
that are already in effect with respect to such Affected Employees and that have
not been satisfied as of the Closing Date under any welfare plan maintained for
the Affected Employees immediately prior to the Closing Date, and (ii) provide
each Affected Employee with credit for any co-payments and deductibles paid
prior to the Closing Date in satisfying any applicable deductible or
out-of-pocket requirements under any welfare plans that such Affected Employees
are eligible to participate in after the Closing Date.
(d)(i) NEES shall, or shall cause the Surviving Entity and its
Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect
on the date hereof; provided, however, that this Section 7.05(d)(i) is not
intended to prevent NEES or the Surviving Entity from exercising their rights
with respect to all EUA Employee Benefit Plans solely in accordance with their
terms, including but not limited to the right to alter, terminate or otherwise
amend such EUA Employee Benefit Plans.
(ii) NEES shall, or shall cause the Surviving Entity and
its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, (A) all employment severance, consulting and
retention agreements or arrangements as in effect on the date hereof, as set
forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in
accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or
arrangements, the "EUA Employee Agreements" and the individuals who are parties
to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee
Benefit Plans in which such EUA Executives participate; provided, however, that
this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity
from exercising their rights with respect to the EUA Employee Agreements and the
EUA Employee Benefit Plans in which such EUA Executives participate, in each
case solely in accordance with their terms, including but not limited to the
right to alter, terminate or otherwise amend such EUA Employee Agreements and
EUA Employee Benefit Plans.
(e) Notwithstanding the foregoing, NEES and the Surviving Entity
and its subsidiaries shall neither be required to or prevented from merging
EUA's benefit plans, agreements, or arrangements into NEES or the Surviving
Entity and its subsidiaries benefit plans, agreements, or arrangements or from
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replacing EUA's benefit plans, agreements or arrangements with NEES or the
Surviving Entity and its subsidiaries benefit plans, agreements or arrangements.
7.06 Labor Agreements and Workforce Matters.
(a) Labor Agreements. NEES shall honor, or shall cause the
appropriate subsidiaries of the Surviving Entity to honor, all collective
bargaining agreements of EUA or its subsidiaries in effect as of the Effective
Time until their expiration; provided, however, that this undertaking is not
intended to prevent NEES or the Surviving Entity and its subsidiaries from
exercising their rights with respect to such collective bargaining agreements
and in accordance with their terms, including any right to amend, modify,
suspend, revoke or terminate any such contract, agreement, collective bargaining
agreement or commitment or portion thereof.
(b) Workforce Matters. Subject to applicable law and obligations
under applicable collective bargaining agreements, for a period of 2 years
following the Effective Time, any reductions in workforce in respect of
employees of the Surviving Entity and its Subsidiaries shall be made on a fair
and equitable basis as determined by the Surviving Entity, with due
consideration to prior experience and skills, and any employee whose employment
is terminated or job is eliminated during such period shall be entitled to
participate on a fair and equitable basis as determined by NEES or the Surviving
Entity in the job opportunity and employment placement programs offered by NEES
or the Surviving Entity or any of their Subsidiaries for which they are
eligible. Any workforce reductions carried out following the Effective Time by
the Surviving Entity and its Subsidiaries shall be done in accordance with all
applicable collective bargaining agreements and all laws and regulations
governing the employment relationship and termination thereof including, without
limitation, the Worker Adjustment and Retraining Notification Act, and the
regulations promulgated thereunder, and any comparable state or local law.
7.07 Post Merger Operations.
(a) NEES Advisory Board. If the Merger is consummated, then,
promptly following the closing of the merger contemplated by the National Grid
Merger Agreement, NEES shall take such action as is necessary to cause all of
the members of the Board of Directors of EUA to be appointed to serve on the
advisory board to be formed pursuant to Section 7.07(e) of the National Grid
Merger Agreement.
(b) Charities. The parties agree that provision of charitable
contribution and community support within the New England region serves a number
of important goals. After the Effective Time, NEES intends to cause the
Surviving Entity to provide charitable contributions and community support
within the New England region at annual levels substantially comparable to the
annual level of charitable contributions and community support provided,
directly or indirectly, by EUA and its public utility subsidiaries within the
New England region during 1998.
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7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a)
that neither it nor any of its Subsidiaries shall, and it shall use its best
efforts to cause its Representatives (as defined in Section 10.10) not to,
knowingly initiate, solicit or encourage, directly or indirectly, any inquiries
or any proposal or offer (including, without limitation, any proposal or offer
to its Shareholders) with respect to a merger, consolidation or other business
combination including EUA or any of its significant Subsidiaries (as defined in
Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than
EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or
similar transaction (including, without limitation, a tender or exchange offer)
involving the purchase of (i) all or any significant portion of the assets of
EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the
outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the
capital stock of any EUA Significant Subsidiary (any such proposal or offer
being hereinafter referred to as an "Alternative Proposal"), or engage in any
negotiations concerning, or provide any confidential information or data to, or
have any other discussions with, any person or group relating to an Alternative
Proposal, or otherwise knowingly facilitate any effort or attempt to make or
implement an Alternative Proposal other than from NEES and its affiliates; (b)
that it will immediately cease and cause to be terminated any existing
activities, discussions or negotiations with any parties with respect to any
Alternative Proposal; and (c) that it will notify NEES immediately if any such
inquiries, proposals or offers are received by, any such information is
requested from, or any such negotiations or discussions are sought to be
initiated or continued with, it or any of such persons; provided, however, that,
prior to receipt of the EUA Shareholders' Approval, nothing contained in this
Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing
information to (but only pursuant to a confidentiality agreement in customary
form and having terms and conditions no less favorable to EUA than the
Confidentiality Agreement (as defined in Section 7.01)) or entering into
discussions or negotiations with any person or group that makes an unsolicited
Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees
of EUA, based upon advice of outside counsel with respect to fiduciary duties,
determines in good faith that such action is necessary for the Board of Trustees
to act in a manner consistent with its fiduciary duties to Shareholders under
applicable law, (B) the Board of Trustees of EUA has reasonably concluded in
good faith (after consultation with its financial advisors) that the person or
group making such Alternative Proposal will have adequate sources of financing
to consummate such Alternative Proposal and that such Alternative Proposal is
likely to be more favorable to EUA's shareholders than the Merger, (C) prior to
furnishing such information to, or entering into discussions or negotiations
with, such person or group, EUA provides written notice to NEES to the effect
that it is furnishing information to, or entering into discussions or
negotiations with, such person or group, which notice shall identify such person
or group and the material terms of the Alternative Proposal in reasonable
detail, and (D) EUA keeps NEES promptly informed of the status and all material
information with respect to any such discussions or negotiations; and (ii) to
the extent required, complying with Rule 14e-2 promulgated under the Exchange
Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall
(x) permit EUA to terminate this Agreement (except as specifically provided in
Article IX), (y) permit EUA to enter into any agreement with respect to an
Alternative Proposal for so long as this Agreement remains in effect (it being
agreed that for so long as this Agreement remains in effect, EUA shall not enter
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into any agreement with any person or group that provides for, or in any way
knowingly facilitates, an Alternative Proposal (other than a confidentiality
agreement under the circumstances described above)), or (z) affect any other
obligation of EUA under this Agreement.
7.09 Directors' and Officers' Indemnification and Insurance.
(a) Indemnification. To the extent, if any, not provided by an
existing right of indemnification or other agreement or policy, from and after
the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the
fullest extent permitted by applicable law, indemnify, defend and hold harmless
each person who is now, or has been at any time prior to the date hereof, or who
becomes prior to the Effective Time, (x) an officer, trustee or director or (y)
an employee covered as of the date hereof (to the extent of the coverage
extended as of the date hereof) of EUA or any Subsidiary of EUA (each an
"Indemnified Party," and collectively, the "Indemnified Parties") against (i)
all losses, expenses (including reasonable attorney's fees and expenses),
claims, damages or liabilities or, subject to the first proviso of the next
succeeding sentence, amounts paid in settlement, arising out of actions or
omissions occurring at or prior to the Effective Time (and whether asserted or
claimed prior to, at or after the Effective Time) that are, in whole or in part,
based on or arising out of the fact that such person is or was a director,
trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified
Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based
on or arise out of or pertain to the transactions contemplated by this
Agreement, in each case, to the extent permitted by the EUA Trust Agreement or
the indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter. In the event of any such loss, expense, claim, damage or liability
(whether or not arising before the Effective Time), (i) NEES shall, or shall
cause the Surviving Entity to, pay the reasonable fees and expenses of counsel
selected by the Indemnified Parties, which counsel shall be reasonably
satisfactory to NEES or the Surviving Entity, as appropriate, promptly after
statements therefor are received and otherwise advance to such Indemnified Party
upon request, reimbursement of documented expenses reasonably incurred, in
either case to the extent not prohibited by the EUA Trust Agreement or the
indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter upon receipt of an undertaking by or on behalf of such director, trustee
or officer to repay such amounts as and to the extent required by the EUA Trust
Agreement or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of
any such matter and (iii) any determination required to be made with respect to
whether an Indemnified Party's conduct complies with the standards set forth
under the EUA Trust Agreement or the indemnification agreements set forth in
Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation
or by-laws or similar governing documents of the Surviving Entity shall be made
by independent counsel mutually acceptable to the Surviving Entity and the
Indemnified Party; provided, however, that the Surviving Entity shall not be
liable for any settlement effected without its written consent (which consent
shall not be unreasonably withheld) and provided further that no indemnification
shall be made if such indemnification is prohibited by the EUA Trust Agreement
or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter.
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(b) Insurance. For a period of six years after the Effective
Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be
maintained in effect an extended reporting period for current policies of
directors' and officers' liability insurance for the benefit of such persons who
are currently covered by such policies of EUA on terms no less favorable than
the terms of such current insurance coverage or (ii) shall provide tail coverage
for such persons which provides such persons with coverage for a period of six
years for acts prior to the Effective Time on terms no less favorable than the
terms of such current insurance coverage.
(c) Successors. In the event the Surviving Entity or any of its
successors or assigns (i) consolidates with or merges into any other person or
entity and shall not be the continuing or surviving corporation or entity of
such consolidation or merger or (ii) transfers all or substantially all of its
properties and assets to any person or entity, then and in either such case,
proper provisions shall be made so that the successors and assigns of the
Surviving Entity, as applicable, shall assume the obligations set forth in this
Section 7.09.
(d) Survival of Indemnification. To the fullest extent permitted
by law, from and after the Effective Time, all rights to indemnification as of
the date hereof in favor of the employees, agents, directors, trustees and
officers of EUA and EUA's Subsidiaries with respect to their activities as such
prior to the Effective Time, as provided in the EUA Trust Agreement or the
respective certificates of incorporation and by-laws or similar governing
documents in effect on the date hereof, or otherwise in effect on the date
hereof, shall survive the Merger and shall continue in full force and effect for
a period of not less than six years from the Effective Time.
(e) Benefit. The provisions of this Section 7.09 are intended to
be for the benefit of, and shall be enforceable by, each Indemnified Party, his
or her heirs and his or her representatives.
(f) Amendment of the EUA Trust Agreement. NEES shall not, and
shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement
to in any way limit the indemnification provided to the Indemnified Parties
under this Section 7.09.
7.10 Expenses. Except as set forth in Section 9.03, whether or not
the Merger is consummated, all costs and expenses incurred in connection with
the Merger and other transactions contemplated hereby shall be paid by the party
incurring such cost or expense, except that the filing fees in connection with
the filings required under the HSR Act and the 1935 Act shall be paid by NEES.
7.11 Brokers or Finders. EUA represents, as to itself and its
affiliates, that no agent, broker, investment banker, financial advisor or other
firm or person is or will be entitled to any broker's, finder's or investment
banker's fee or any other commission or similar fee in connection with the
Merger and other transactions contemplated by this Agreement except Salomon
Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance
with EUA's agreement with such firm, and EUA shall indemnify and hold NEES
harmless from and against any and all claims, liabilities or obligations with
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respect to any other such fee or commission or expenses related thereto asserted
by any person on the basis of any act or statement alleged to have been made by
EUA or its affiliates.
7.12 Anti-Takeover Statutes. If any "fair price", "moratorium",
"business combination", "control share acquisition" or other form of
anti-takeover statute or regulation shall become applicable to the Merger or
other transactions contemplated hereby, EUA and the members of the Board of
Trustees of EUA shall grant such approvals and take such actions consistent with
their fiduciary duties and in accordance with applicable law as are reasonably
necessary so that the Merger and other transactions contemplated hereby may be
consummated as promptly as practicable on the terms contemplated hereby and
otherwise act to eliminate or minimize the effects of such statute or regulation
on the Merger and other transactions contemplated hereby.
7.13 Public Announcements. Except as otherwise required by law or the
rules of any applicable securities exchange or national market system or any
other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA
will not, and will not permit any of their respective Subsidiaries or
Representatives to, issue or cause the publication of any press release or make
any other public announcement with respect to the Merger and other transactions
contemplated by this Agreement without the consent of the other party, which
consent shall not be unreasonably withheld. NEES and EUA will cooperate with
each other in the development and distribution of all press releases and other
public announcements with respect to the Merger and other transactions
contemplated hereby, and will furnish the other with drafts of any such releases
and announcements as far in advance as practicable.
7.14 Restructuring of the Merger. It may be preferable to effectuate
a business combination between NEES and EUA by means of an alternative structure
to the Merger. Accordingly, if, prior to satisfaction of the conditions
contained in Article VIII hereto, NEES proposes the adoption of an alternative
structure that otherwise substantially preserves for NEES and EUA the economic
benefits of the Merger and will not materially delay the consummation thereof,
then the parties shall use their respective best efforts to effect a business
combination among themselves by means of a mutually agreed upon structure other
than the Merger that so preserves such benefits; provided, however, that prior
to closing any such restructured transaction, all material third party and
Governmental Authority declarations, filings, registrations, notices,
authorizations, consents or approvals necessary for the effectuation of such
alternative business combination shall have been obtained and all other
conditions to the parties' obligations to consummate the Merger and other
transactions contemplated hereby, as applied to such alternative business
combination, shall have been satisfied or waived.
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ARTICLE VIII
CONDITIONS
8.01 Conditions to Each Party's Obligation to Effect the Merger. The
respective obligation of each party to effect the Merger and other transactions
contemplated hereby is subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following conditions:
(a) Shareholder Approval. EUA Shareholders' Approval shall have
been obtained.
(b) HSR Act. Any waiting period (and any extension thereof)
applicable to the consummation of the Merger under HSR shall have expired or
been terminated.
(c) Injunctions or Restraints. No court of competent
jurisdiction or other competent Governmental Authority shall have enacted,
issued, promulgated, enforced or entered any law or order (whether temporary,
preliminary or permanent) which is then in effect and has the effect of making
illegal or otherwise restricting, preventing or prohibiting consummation of the
Merger or other transactions contemplated hereby.
(d) Governmental and Regulatory and Other Consents and
Approvals. The NEES Required Statutory Approvals and EUA Required Statutory
Approvals shall have been obtained prior to the Effective Time, and shall have
become Final Orders (as hereinafter defined). The Final Orders shall not,
individually or in the aggregate, impose terms and conditions that (i) could
reasonably be expected to have an EUA Material Adverse Effect; (ii) could
reasonably be expected to have a NEES Material Adverse Effect; or (iii)
materially impair the ability of the parties to complete the Merger. The parties
shall have received Final Orders from the Massachusetts Department of
Telecommunications and Energy and the Rhode Island Public Utilities Commission
pertaining to the recovery of costs (including, without limitation, transaction
premium and integration costs) associated with the Merger that are materially
consistent with existing policy and previous orders of such agencies. "Final
Order" for all purposes of this Agreement means action by the relevant
regulatory authority which has not been reversed, stayed, enjoined, set aside,
annulled or suspended with respect to which any waiting period prescribed by law
before the Merger and other transactions contemplated hereby may be consummated
has expired, and as to which all conditions to be satisfied before the
consummation of such transactions prescribed by law, regulation or order have
been satisfied.
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger.
The obligation of NEES and LLC to effect the Merger and other transactions
contemplated hereby is further subject to the satisfaction or waiver at or prior
to the Closing, of each of the following additional conditions (all or any of
which may be waived in whole or in part by NEES and LLC in the sole discretion):
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(a) Representations and Warranties. The representations and
warranties made by EUA in this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "EUA Material Adverse Effect", shall be true and correct as so
made as of the Closing Date as though so made on and as of the Closing Date,
except to the extent expressly given as of a specified date, except where the
failure of such representations and warranties to be true and correct as so made
does not have and could not reasonably be expected to have, individually or in
the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to
NEES a certificate, dated the Closing Date and executed in the name and on
behalf of EUA by its Chairman of the Board, President or any Executive or Senior
Vice President, to such effect.
(b) Performance of Obligations. EUA shall have performed and
complied with, in all material respects, each agreement, covenant and obligation
required by this Agreement to be so performed or complied with by EUA at or
prior to the Closing, and EUA shall have delivered to NEES a certificate, dated
the Closing Date and executed in the name and on behalf of EUA by its Chairman
of the Board, President or any Executive or Senior Vice President, to such
effect.
(c) Material Adverse Effect. No EUA Material Adverse Effect
shall have occurred and there shall exist no facts or circumstances which in the
aggregate could reasonably be expected to have an EUA Material Adverse Effect.
(d) EUA Required Consents. All EUA Required Consents shall have
been obtained by EUA, except where the failure to receive such EUA Required
Consents could not reasonably be expected to (i) have an EUA Material Adverse
Effect, or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
8.03 Conditions to Obligation of EUA to Effect the Merger. The
obligation of EUA to effect the Merger and other transactions contemplated
hereby is further subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following additional conditions (all or any of which may
be waived in whole or in part by EUA in its sole discretion):
(a) Representations and Warranties. The representations and
warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07,
5.08 and 5.09 of this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "NEES Material Adverse Effect," shall be true and correct as so
made as of the Closing Date, except to the extent expressly given as of a
specified date and except where the failure of such representations and
warranties to be so true and correct as so made does not have and could not
reasonably be expected to have, individually or in the aggregate, a NEES
Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC
shall each have delivered to EUA a certificate, dated the Closing Date and
executed in the name and on behalf of NEES by any director of NEES and in the
name and on behalf of LLC by a member of its management committee its Chairman
of the Board, President or any Executive or Senior Vice President to such
effect.
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(b) NEES Required Consents. All NEES Required Consents shall
have been obtained by NEES, except where the failure to receive such NEES
Required Consents could not reasonably be expected to (i) have a NEES Material
Adverse Effect or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
(c) Performance of Obligations. NEES and LLC shall have
performed and complied with, in all material respects, each agreement, covenant
and obligation required by this Agreement to be so performed or complied with by
NEES or LLC at or prior to the Closing, and NEES and LLC shall each have
delivered to EUA a certificate, dated the Closing Date and executed in the name
and on behalf of NEES by its Chairman of the Board, President or any Executive
or Senior Vice President, or on behalf of LLC by a member of its management
committee to such effect.
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER
9.01 Termination. This Agreement may be terminated, and the Merger
and other transactions contemplated hereby may be abandoned, at any time prior
to the Effective Time, whether prior to or after EUA Shareholders' Approval
(except as otherwise provided in Section 9.01(c) below):
(a) By mutual written agreement of the Board of Directors of
NEES and Board of Trustees of EUA, respectively;
(b) By EUA or NEES, by written notice to the other, if the
Closing Date shall not have occurred on or before December 31, 1999 (the
"Initial Termination Date"); provided, however, that the right to terminate the
Agreement under this Section 9.01(b) shall not be available to any party whose
failure to fulfill any obligation under this Agreement has been the cause of, or
resulted in, the failure of the Effective Time to occur on or before such date;
and provided, further, that if on the Initial Termination Date the conditions to
the Closing set forth in Section 8.01(d) shall not have been fulfilled but all
other conditions to the Closing shall be fulfilled or shall be capable of being
fulfilled, then the Initial Termination Date shall be extended for four (4)
months beyond the Initial Termination Date (the "Extended Termination Date");
(c) By NEES, by written notice to EUA, if EUA Shareholders'
Approval shall not have been obtained at a duly held meeting of such
Shareholders, including any adjournments thereof;
(d) By EUA or NEES, if any applicable state or federal law or
applicable law of a foreign jurisdiction or any order, rule or regulation is
adopted or issued that has the effect, as supported by the written opinion of
outside counsel for such party, of prohibiting the Merger or other transactions
contemplated hereby, or if any court of competent jurisdiction or any
Governmental Authority shall have issued a nonappealable final order, judgment
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or ruling or taken any other action having the effect of permanently
restraining, enjoining or otherwise prohibiting the Merger or other transactions
contemplated hereby (provided that the right to terminate this Agreement under
this Section 9.01(d) shall not be available to any party that has not defended
such lawsuit or other legal proceeding (including seeking to have any stay or
temporary restraining order entered by any court or other Governmental Authority
vacated or reversed)).
(e) By EUA upon ten (10) days' prior notice to NEES if the Board
of Trustees of EUA determines in good faith, that termination of this Agreement
is necessary for the Board of Trustees of EUA to act in a manner consistent with
its fiduciary duties to Shareholders under applicable law by reason of an
unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B)
of Section 7.08 having been made; provided that
(A) The Board of Trustees of EUA shall determine based
on advice of outside counsel with respect to the Board of
Trustees' fiduciary duties that notwithstanding a binding
commitment to consummate an agreement of the nature of this
Agreement entered into in the proper exercise of its applicable
fiduciary duties, and notwithstanding all concessions which may
be offered by NEES in negotiation entered into pursuant to clause
(B) below, it is necessary pursuant to such fiduciary duties that
the trustees reconsider such commitment as a result of such
Alternative Proposal, and
(B) prior to any such termination, EUA shall, and
shall cause its respective financial and legal advisors to,
negotiate with NEES to make such adjustments in the terms and
conditions of this Agreement as would enable EUA to proceed with
the Merger or other transactions contemplated hereby on such
adjusted terms;
and provided further that EUA's ability to terminate this Agreement pursuant to
this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES
of any amounts owed by it pursuant to Section 9.03(a);
(f) By EUA, by written notice to NEES, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of NEES hereunder (other than a breach
described in clause (ii)), and such breach shall not have been remedied within
twenty (20) days after receipt by NEES of notice in writing from EUA, specifying
the nature of such breach and requesting that it be remedied; or (ii) NEES shall
fail to deliver or cause to be delivered the amount of cash to the Paying Agent
required pursuant to Section 2.02(a) at a time when all conditions to NEES's
obligation to close have been satisfied or otherwise waived in writing by NEES.
(g) By NEES, by written notice to EUA, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of EUA hereunder, and such breach shall not
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have been remedied within twenty (20) days after receipt by EUA of notice in
writing from NEES, specifying the nature of such breach and requesting that it
be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify
in any manner adverse to NEES its approval of the Merger and other transactions
contemplated hereby or its recommendation to its shareholders regarding the
approval of this Agreement, the Merger and other transactions contemplated
hereby, (B) shall approve or recommend or take no position with respect to an
Alternative Proposal or (C) shall resolve to take any of the actions specified
in clause (A) or (B).
9.02 Effect of Termination. If this Agreement is validly terminated
by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith
become null and void and there shall be no liability or obligation on the part
of either EUA or NEES (or any of their respective Representatives or
affiliates), except that the provisions of this Section 9.02, Sections 7.10,
7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply
following any such termination.
9.03 Termination Fees. (a) In the event that (i) this Agreement is
terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall
have made an Alternative Proposal that has not been withdrawn and this Agreement
is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B)
by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a
definitive agreement with respect to such Alternative Proposal is executed
within two years after such termination, then EUA shall pay to NEES, by wire
transfer of same day funds, either on the date contemplated in Section 9.01(e)
if applicable, or otherwise, within five (5) business days after such
termination, a termination fee of $20 million, plus an amount equal to all
documented out-of-pocket expenses and fees incurred by NEES arising out of, or
in connection with or related to, the Merger and other transactions contemplated
hereby, not in excess of $5 million in the aggregate.
(b) In the event that this Agreement is terminated by either
NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i)
the conditions to the Closing set forth in Section 8.01(d) shall not have been
fulfilled, (ii) if the date of termination is any date other than a date which
is on or after the Extended Termination Date, all conditions contained in
Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or
are capable of being fulfilled as of such date, and (iii) the merger
contemplated by the National Grid Merger Agreement has not yet been consummated,
then NEES shall pay to EUA, by wire transfer of same day funds, within five (5)
business days after such termination, a termination fee of $10 million, plus an
amount equal to all documented out-of-pocket expenses and fees incurred by EUA
arising out of, or in connection with or related to, the Merger and other
transactions contemplated hereby, not in excess of $5 million in the aggregate.
(c) Nature of Fees. The parties agree that the agreements
contained in this Section 9.03 are an integral part of the Merger and the other
transactions contemplated hereby and constitute liquidated damages and not a
penalty. The parties further agree that if any party is or becomes obligated to
pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive
such termination fee shall be the sole remedy of the other party with respect to
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the facts and circumstances giving rise to such payment obligation. If this
Agreement is terminated by a party as a result of a willful breach of a
representation, warranty, covenant or agreement by the other party, including a
termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue
any remedies available to it at law or in equity and shall be entitled to
recover any additional amounts thereunder. Notwithstanding anything to the
contrary contained in this Section 9.03, if one party fails to promptly pay to
the other any fee or expense due under this Section 9.03, in addition to any
amounts paid or payable pursuant to such Section, the defaulting party shall pay
the costs and expenses (including legal fees and expenses) in connection with
any action, including the filing of any lawsuit or other legal action, taken to
collect payment, together with interest on the amount of any unpaid fee at the
publicly announced prime rate of Citibank, N.A. from the date such fee was
required to be paid.
9.04 Amendment. This Agreement may be amended, supplemented or
modified by action taken by or on behalf of the Board of Directors of NEES or
the Board of Trustees of EUA at any time prior to the Effective Time, whether
prior to or after EUA Shareholders' Approval shall have been obtained, but after
such adoption and approval only to the extent permitted by applicable law. No
such amendment, supplement or modification shall be effective unless set forth
in a written instrument duly executed and delivered by or on behalf of each
party hereto.
9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by
action taken by or on behalf of its Board of Directors or Board of Trustees,
respectively, may to the extent permitted by applicable law (i) extend the time
for the performance of any of the obligations or other acts of the other parties
hereto, (ii) waive any inaccuracies in the representations and warranties of the
other parties hereto contained herein or in any document delivered pursuant
hereto or (iii) waive compliance with any of the covenants, agreements or
conditions of the other parties hereto contained herein. No such extension or
waiver shall be effective unless set forth in a written instrument duly executed
by or on behalf of the party extending the time of performance or waiving any
such inaccuracy or non-compliance. No waiver by any party of any term or
condition of this Agreement, in any one or more instances, shall be deemed to be
or construed as a waiver of the same or any other term or condition of this
Agreement on any future occasion.
ARTICLE X
GENERAL PROVISIONS
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements. The representations, warranties, covenants and agreements contained
in this Agreement or in any instrument delivered pursuant to this Agreement
shall not survive the Merger but shall terminate at the Effective Time, except
for the agreements contained in Article I and Article II, in Sections 7.05,
7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective
Time.
10.02 Notices. All notices, requests and other communications
hereunder must be in writing and will be deemed to have been duly given only if
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delivered personally or by facsimile transmission or sent by overnight courier
(providing proof of delivery) to the parties at the following addresses or
facsimile numbers:
If to NEES or LLC, to:
New England Electric System
25 Research Drive
Westborough, MA 01582
Attn: Richard P. Sergel
President and Chief Executive Officer
Telephone: (508) 389-2764
Facsimile: (508) 366-5498
with a copy to:
Skadden, Arps, Slate, Meagher & Flom LLP
919 Third Avenue
New York, NY 10022
Attn: Sheldon S. Adler, Esq.
Telephone: (212) 735-3000
Facsimile: (212) 735-2000
If to EUA, to:
Eastern Utilities Associates
One Liberty Square
Boston, MA 02109
Attn: Donald G. Pardus
Chairman and Chief Executive Officer
Telephone: (617) 357-9590
Facsimile: (617) 357-7320
with a copy to:
Winthrop, Stimson, Putnam & Roberts
1 Battery Park Plaza
New York, NY 10004
Attn: David P. Falck
Telephone: (212) 858-1000
Facsimile: (212) 858-1500
All such notices, requests and other communications will (i) if
delivered personally to the address as provided in this Section, be deemed given
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upon delivery, (ii) if delivered by facsimile transmission to the facsimile
number as provided in this Section, be deemed given when sent, provided that the
facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if
delivered by mail in the manner described above to the address as provided in
this Section, be deemed given one business day after delivery (in each case
regardless of whether such notice, request or other communication is received by
any other person to whom a copy of such notice, request or other communication
is to be delivered pursuant to this Section). Any party from time to time may
change its address, facsimile number or other information for the purpose of
notices to that party by giving notice specifying such change to the other
parties hereto.
10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement
supersedes all prior discussions and agreements, both written and oral, among
the parties hereto with respect to the subject matter hereof, other than the
Confidentiality Agreement, which shall survive the execution and delivery of
this Agreement in accordance with its terms, and contains, together with the
Confidentiality Agreement, the sole and entire agreement among the parties
hereto with respect to the subject matter hereof.
(b) The EUA Disclosure Letter, the NEES Disclosure Letter and
any Exhibit attached to this Agreement and referred to herein are hereby
incorporated herein and made a part hereof for all purposes as if fully set
forth herein.
10.04 No Third Party Beneficiary. The terms and provisions of this
Agreement are intended solely for the benefit of each party hereto and their
respective successors or permitted assigns, and except as provided in Article II
and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit
of the persons entitled to therein, and may be enforced by any of such persons),
it is not the intention of the parties to confer third-party beneficiary rights
upon any other person.
10.05 No Assignment; Binding Effect. Neither this Agreement nor any
right, interest or obligation hereunder may be assigned, in whole or in part, by
operation of law or otherwise, by any party hereto without the prior written
consent of the other parties hereto and any attempt to do so will be void,
except that LLC may assign any or all of its rights, interests and obligations
hereunder to another direct or indirect wholly owned Subsidiary of NEES,
provided that any such Subsidiary agrees in writing to be bound by all of the
terms, conditions and provisions contained herein and provided further that such
assignment (i) does not require a greater vote for EUA's Shareholder Approval,
(ii) does not require a subsequent vote following EUA's Shareholders Meeting, or
(iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES,
as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required
Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals,
or the NEES Required Consents. Subject to the preceding sentence, this Agreement
is binding upon, inures to the benefit of and is enforceable by the parties
hereto and their respective successors and assigns.
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10.06 Headings. The headings used in this Agreement have been
inserted for convenience of reference only and do not define, modify or limit
the provisions hereof.
10.07 Invalid Provisions. If any provision of this Agreement is held
to be illegal, invalid or unenforceable under any present or future law or
order, and if the rights or obligations of any party hereto under this Agreement
will not be materially and adversely affected thereby, (i) such provision will
be fully severable, (ii) this Agreement will be construed and enforced as if
such illegal, invalid or unenforceable provision had never comprised a part
hereof, and (iii) the remaining provisions of this Agreement will remain in full
force and effect and will not be affected by the illegal, invalid or
unenforceable provision or by its severance herefrom.
10.08 Governing Law. This Agreement shall be governed by and
construed in accordance with the laws of the Commonwealth of Massachusetts.
10.09 Enforcement of Agreement. The parties hereto agree that
irreparable damage would occur in the event that any of the provisions of this
Agreement was not performed in accordance with its specified terms or was
otherwise breached. It is accordingly agreed that the parties shall be entitled
to an injunction or injunctions to prevent breaches of this Agreement and to
enforce specifically the terms and provisions hereof in any court of competent
jurisdiction, this being in addition to any other remedy to which they are
entitled at law or in equity.
10.10 Certain Definitions. As used in this Agreement:
(a) except as provided in Section 4.14, the term "affiliate," as
applied to any person, shall mean any other person directly or indirectly
controlling, controlled by, or under common control with, that person; for
purposes of this definition, "control" (including, with correlative meanings,
the terms "controlling," "controlled by" and "under common control with"), as
applied to any person, means the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of that
person, whether through the ownership of voting securities, by contract or
otherwise;
(b) a person will be deemed to "beneficially" own securities if
such person would be the beneficial owner of such securities under Rule 13d-3
under the Exchange Act, including securities which such person has the right to
acquire (whether such right is exercisable immediately or only after the passage
of time);
(c) the term "business day" means a day other than Saturday,
Sunday or any day on which banks located in the Massachusetts are authorized or
obligated to close;
(d) the term "knowledge" or any similar formulation of
"knowledge" shall mean, with respect to any party hereto, the actual knowledge
after due inquiry of the executive officers of NEES and its Subsidiaries or EUA
and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES
Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided
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that as used in Section 4.13 the term "knowledge" shall also include the
knowledge of the environmental, health and safety personnel of EUA;
(e) the term "person" shall include individuals, corporations,
partnerships, trusts, limited liability companies, other entities and groups
(which term shall include a "group" as such term is defined in Section 13(d)(3)
of the Exchange Act);
(f) the "Representatives" of any entity shall have the same
meaning as set forth in the Confidentiality Agreement;
(g) the term "Subsidiary" means any corporation or other entity,
whether incorporated or unincorporated, in which such party directly or
indirectly owns at least a majority of the voting power represented by the
outstanding capital stock or other voting securities or interests having voting
power under ordinary circumstances to elect a majority of the directors or
similar members of the governing body, or otherwise to direct the management and
policies, or such corporation or entity.
10.11 Counterparts. This Agreement may be executed in any number of
counterparts, each of which will be deemed an original, but all of which
together will constitute one and the same instrument and will become effective
when one or more counterparts have been signed by each party and delivered to
the other parties.
10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE
FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY
JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING
TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON
CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO
REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY
OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK
TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER
PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER
THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
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IN WITNESS WHEREOF, each party hereto has caused this Agreement to be
signed by its officer thereunto duly authorized as of the date first above
written.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability therefor.
EASTERN UTILITIES ASSOCIATES
By: /s/ Donald G. Pardus
-----------------------------------
Name: Donald G. Pardus
Title: Chairman
The name "Eastern Utilities Associates" is the designation of the Trustees of
EUA for the time being in their collective capacity but not personally, under a
Declaration of Trust dated April 2, 1928, as amended, a copy of which amended
Declaration of Trust has been filed in the office of the Secretary of The
Commonwealth of Massachusetts and elsewhere as required by law; and all persons
dealing with EUA must look solely to the trust property for the enforcement of
any claim against EUA, as neither the Trustees nor the officers or shareholders
of EUA assume any personal liability for obligations entered into on behalf of
EUA.
RESEARCH DRIVE LLC
By: /s/ John G. Cochrane
-----------------------------------
Name: John G. Cochrane
Title: Manager
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Exhibit H-1
UNITED STATES OF AMERICA
before the
SECURITIES AND EXCHANGE COMMISSION
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
Release No. / , 1999
- ------------------------------------
)
In the Matter of )
)
New England Electric System )
25 Research Drive )
Westborough, MA 01582 )
)
and )
)
Eastern Utilities Associates )
One Liberty Square, P.O. Box 2333 )
Boston, MA 02109 )
)
(70- ) )
- ------------------------------------
New England Electric System ("NEES"), organized and existing under the
laws of Massachusetts as a voluntary association pursuant to an Agreement and
Declaration of Trust dated January 2, 1926, as amended, and Eastern Utilities
Associates ("EUA"), organized and existing under the laws of Massachusetts
pursuant to a Declaration of Trust dated April 2, 1928, as amended, have filed
an Application on Form U-1 seeking approvals related to the proposed combination
of NEES, EUA and Research Drive LLC ("LLC"), a Massachusetts limited liability
company wholly-owned by NEES (the "Merger"). Pursuant to the Merger, LLC will
merge with and into EUA, with EUA as the surviving entity, and, therefore, a
wholly-owned subsidiary of NEES. EUA subsequently will be merged with and into
NEES, with NEES as the surviving entity (together with the Merger, the
"Transaction"). Subsequent to the Transaction, EUA shall cease to exist and NEES
will remain a registered holding company pursuant to the Public Utility Holding
Company Act of 1935 (the "Act").
NEES is a registered public utility holding company, and NEES and its
subsidiaries are subject to the broad regulatory provisions of the Act
administered by the Securities and Exchange Commission (the "Commission"). NEES
owns all of the voting securities of the following four distribution
subsidiaries: Massachusetts Electric Company ("Mass. Electric"), The
Narragansett Electric Company ("Narragansett"), Granite State Electric Company
<PAGE>
("Granite State"), and Nantucket Electric Company ("Nantucket"). NEES also owns
99.97 percent of the outstanding voting securities of its principal transmission
subsidiary, New England Power Company ("NEP"). NEES and its utility subsidiaries
(the "NEES System") serve a territory covering more than 4,500 square miles with
a population of approximately 3,000,000. NEES also engages in non-utility
operations through various other subsidiaries including New England Power
Service Company ("Service Company"), which provides, at cost, such
administrative, engineering, construction, legal, and financial services as NEES
and its subsidiaries request pursuant to a service agreement approved by the
Commission in accordance with the requirements of Rule 90.
EUA operates as a registered holding company pursuant to the Act, and
EUA and its subsidiaries are subject to the broad regulatory provisions of the
Act administered by the Commission. EUA directly owns all of the shares of
common stock of the following electric public utility companies: Blackstone
Valley Electric Company ("Blackstone"), Eastern Edison Company ("Eastern
Edison") and Newport Electric Corporation ("Newport"). Eastern Edison presently
owns all of the outstanding securities of Montaup Electric Company ("Montaup").
On July 14, 1999, Eastern Edison filed a Form U-1 requesting the Commission's
authorization for Eastern Edison to transfer to EUA, and for EUA to acquire from
Eastern Edison, all of Eastern Edison's investment in Montaup's capitalization.
EUA and its utility subsidiaries (the "EUA System") serve approximately 305,000
retail customers in Massachusetts and Rhode Island. EUA also engages in
non-utility operations through various other subsidiaries, including EUA Service
Corporation ("EUA Service"), which provides various accounting, financial,
engineering, planning, data processing, and other services to EUA System
companies.
As part of the Transaction, Eastern Edison and Mass. Electric will
merge, with Mass. Electric being the surviving entity; NEP and Montaup will
merge, with NEP being the surviving entity; and Blackstone, Newport and
Narragansett will merge, with Narragansett being the surviving entity. In
addition, NEES will indirectly acquire EUA's non-utility businesses through
NEES' ownership of common shares or equity in those non-utility businesses.
Finally, EUA Service and Service Company will merge, with Service Company being
the surviving company.
Pursuant to an Agreement and Plan of Merger, dated as of December 11,
1998, by and among The National Grid Group plc ("NGG"), NGG Holdings LLC, a
Massachusetts limited liability company and a wholly-owned subsidiary of NGG,
and NEES, NGG Holdings LLC will be merged with and into NEES with NEES as the
surviving entity. As a result, NEES will become an indirect, wholly-owned
subsidiary of NGG, which will become a registered holding company under the Act.
The merger of EUA with and into LLC will be governed by the terms of
an Agreement and Plan of Merger, dated as of February 1, 1999 (the "Merger
Agreement"), by and among NEES, EUA and LLC. As a result of the Transaction,
each one percent of the issued and outstanding membership interests in LLC will
be converted into one transferable certificate of participation or share in EUA.
<PAGE>
All EUA shares that are owned by EUA as treasury shares and any EUA shares owned
by NEES or any other wholly-owned subsidiary of NEES will be cancelled and
retired and shall cease to exist, and no cash or other consideration shall be
delivered in exchange therefor. The remaining EUA shares issued and outstanding
immediately prior to the Effective Date (as defined below) will be cancelled and
converted into the right to receive cash in the amount of $31.00 per share (the
"Per Share Amount"), as such amount may be adjusted. The Effective Date shall be
the date upon which a certificate of merger has been executed and filed by EUA
and LLC with the Secretary of Massachusetts, or any later date specified by such
certificate.
NEES and EUA state that the Transaction fully complies with the Act
and does not prompt any of the concerns that the Act was intended to address.
NEES and EUA further contend that the Transaction promotes the goals of the Act
by creating an integrated merged entity that will benefit the interests of the
general public, investors and consumers. Finally, NEES and EUA state that both
state and federal regulation will ensure that the interests of the public,
investors and consumers continue to be protected.
The Application and any amendments thereto are available for public
inspection through the Commission's Office of Public Reference. Interested
persons wishing to comment or request a hearing should submit their views in
writing by _______, 1999, to the Secretary, Securities and Exchange Commission,
Washington, D.C. 20549, and serve a copy on NEES and EUA at the addresses
specified above. Proof of service (by affidavit or, in case of an attorney at
law, by certificate) should be filed with the request. Any request for hearing
shall identify specifically the issues of fact or law that are disputed. A
person who so requests will be notified of any hearing, if ordered, and will
receive a copy of any notice or order issued in the manner. After said date, the
Application, as filed or as amended, may be granted and/or permitted to become
effective.
For the Commission, by the Division of Investment Management, pursuant
to delegated authority.
Jonathan G. Katz
Secretary
<PAGE>
Exhibit K-1
Discussion of Negotiations
Between NEES and EUA
A special meeting of the EUA Board was held on May 29, 1998. The sole
purpose of this meeting was to review in detail EUA's strategic options for
future operations. Following this special meeting, Donald G. Pardus, EUA's
Chairman of the Board was instructed to open communication with selected
electric utilities in the region in an attempt to determine their interest in
discussing some type of business combination.
From June 1998 through October 1998, EUA's Chairman had informal
conversations with respect to business combinations with senior executives of
four electric utilities in the region.
In early December 1998, EUA's Chairman was contacted by the chairman
of a regional electric utility company ("Company A") with whom previous informal
conversations had taken place. EUA's Chairman was asked if EUA was still
interested in entering into discussions with Company A with respect to a
possible business combination. EUA's Chairman indicated that EUA was continually
reviewing its options and that, subject to the EUA Board's concurrence, EUA
would be interested in entering into such discussions. The EUA Board agreed and
EUA entered into a confidentiality agreement with Company A shortly thereafter
and a due diligence process began.
Shortly after the telephone call from Company A, EUA's Chairman
contacted Richard P. Sergel, the President and Chief Executive Officer of
NEES, and suggested that a meeting take place to explore NEES's interest in
discussing a possible business combination with EUA.
A meeting between Mr. Sergel and Mr. Padus took place on December 10,
1998. A follow-up meeting took place on December 16 and was attended by Alfred
D. Houston, NEES's Chairman, Mr. Sergel, Mr. Pardus and John R. Stevens, EUA's
President. On December 18 and December 21, confidentiality agreements were
signed between EUA, NEES and NEES's prospective parent, NGG. A due diligence
process commenced immediately.
<PAGE>
In addition, during the period December 7, 1998 through January 13,
1999, and as the due diligence process was taking place, EUA's Chairman had four
face-to-face meetings and 10 telephone conversations with the Chairman of
Company A and four face-to-face meetings and five telephone conversations with
the Chief Executive Officer of NEES.
On January 13, 1999, NEES submitted to EUA a proposal to acquire EUA,
which included an indicative price and was subject to the negotiation of a
satisfactory merger agreement.
On January 14, 1999, Company A submitted to EUA a proposal to acquire
EUA, which also included an indicative price and was subject to the negotiation
of a satisfactory merger agreement.
Company A and NEES both anticipated that EUA Cogenex, EUA's energy
services subsidiary, would be sold in a separate transaction, and therefore did
not include a value for EUA Cogenex in their proposals.
The EUA Board met on January 19, 1999 and, with input from EUA
executives and its financial advisors, considered the proposals received from
Company A and NEES. The EUA Board instructed the Chairman and EUA's financial
advisors to go back to Company A and to NEES and inform them that EUA Cogenex
would not be disposed of in a separate transaction; therefore, their proposals
needed to be modified to include a valuation for EUA Cogenex. Both Company A and
NEES were requested to present their best revised proposal by the close of
business on January 26, 1999.
Significant due diligence took place with respect to EUA Cogenex
between January 19, 1999 and January 26, 1999. In addition, during the period
January 19, 1999 through January 28, 1999, EUA's Chairman had eight telephone
conversations with the Chairman or his associates of Company A and one
face-to-face meeting and two telephone conversations with the Chief Executive
Officer of NEES. During this period, there were also frequent discussions
between EUA's financial advisors and the financial advisors for Company A and
NEES.
On January 26, 1999, NEES presented its revised proposal which
included a valuation for EUA Cogenex. Following presentation of NEES's January
26, 1999 proposal, negotiations continued with NEES and its financial advisors
in an effort to enhance the proposal.
<PAGE>
On the evening of January 28, 1999, Company A presented its revised
proposal. Two face-to-face meetings were held on January 29, 1999 between the
Chairman of EUA and the Chief Executive Officer of NEES.
On January 31, 1999 and February 1, 1999, the EUA Board held a special
meeting to review and consider the proposals received from Company A and NEES.
After presentations by Mr. Pardus and Mr. Stevens and the EUA Board's legal and
financial advisors, and a full discussion and analysis by the EUA Board, the EUA
Board unanimously (1) determined that it was in the best interests of EUA
shareholders, its employees and its customers for EUA to enter into a business
combination with NEES; (2) determined that the terms of the Merger were fair to,
and in the best interests of EUA shareholders; and (3) authorized, approved and
adopted the proposed agreement and plan of merger and the transaction
contemplated by the Merger Agreement and the execution and delivery of the
Merger Agreement. EUA was advised that NEES obtained the consent of NGG to enter
into the Merger Agreement and on the morning of February 1, 1999, at the
conclusion of the EUA Board meeting and prior to the opening of markets, EUA and
NEES executed and delivered the Merger Agreement.
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70-000
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, et al.
AND MONTAUP ELECTRIC COMPANY, et al.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
APPLICATION, ATTACHMENTS AND VERIFICATIONS
Edward Berlin, Esq. David A. Fazzone, Esq. of
Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and
Scott P. Klurfeld, Esq. McDermott, Will & Emery
Swidler Berlin Shereff Friedman, LLP 28 State Street
3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775
Washington, D.C. 20007-5116 (617) 535-4000
(202) 424-7500 Attorneys for Montaup Electric Company
and Affiliated Applicants
Thomas G. Robinson, Esq.
New England Power Company
25 Research Drive
Westborough, MA 01582
(508) 389-2877
Attorneys for New England Power
Company and Affiliated Applicants
May, 1999
<PAGE>
TABLE OF CONTENTS
PAGE
I. INTRODUCTION..................................................... 1
II. EXECUTIVE SUMMARY................................................ 4
A. The Merger will not adversely affect
competition............................................ 5
B. The Merger will not subject customers to
increased rates........................................ 6
C. The Merger will not impair the effectiveness
of federal or state regulation......................... 7
III. DESCRIPTION OF THE PARTIES TO THE MERGER......................... 8
A. The NEES System of Companies........................... 8
1. NEES......................................... 8
2. NEP.......................................... 8
3. Affiliates of NEP............................ 9
B. The EUA System of Companies............................ 12
1. EUA.......................................... 12
2. Affiliates of EUA............................ 12
IV. DESCRIPTION OF THE MERGER........................................ 16
A. Goals and Benefits of the Merger....................... 16
B. Procedural Status of the Merger........................ 17
V. THE MERGER IS CONSISTENT WITH THE PUBLIC INTEREST................ 19
A. The Merger Will Have No Adverse Effect on
Competition............................................ 19
1. The Merger Will Not Increase Market
Power with Respect to Generation............. 20
2. The Merger Will Not Have an Adverse
Effect on the Transmission Market in
New England.................................. 21
<PAGE>
TABLE OF CONTENTS (Cont'd)
PAGE
3. The Merger Does Not Raise Vertical
Market Power Issues.......................... 22
4. Conclusion Regarding Effect of the
Merger on Competition........................ 23
B. The Merger Will Have No Adverse Effect on Rates........ 24
1. Applicants Have Proposed a Rate Plan
That Will Hold Transmission Ratepayers
Harmless..................................... 24
2. No Recovery of Transaction Costs and
Acquisition Premium Will Be Awarded
Without Proof of Countervailing
Benefits..................................... 27
3. Conclusion Regarding Effect on Rates......... 28
C. The Merger Will Have No Adverse Effect on Regulation... 28
1. Federal Regulation........................... 29
2. State Regulation............................. 30
VI. ACCOUNTING TREATMENT............................................. 30
VII. INFORMATION REQUIRED OF APPLICANTS BY SECTION 33.2 OF
THE COMMISSION'S REGULATIONS..................................... 32
A. The exact name and address of the
principal business office.............................. 32
B. Name and address of the person authorized to
receive notices and communications with
respect to application................................. 33
C. Designation of the territories served by
counties and states.................................... 33
D. A general statement briefly describing the
facilities owned or operated for transmission
of electric energy in interstate commerce or
the sale of electric energy at wholesale in
interstate commerce.................................... 35
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<PAGE>
TABLE OF CONTENTS (Cont'd)
PAGE
E. Whether the application is for disposition of
facilities by sale, lease, or otherwise, a
merger or consolidation of facilities, or for
purchase or acquisition of securities of a
public utility, also a description of the
consideration, if any, and the method of
arriving at the amount thereof......................... 36
F. A statement of facilities to be disposed of,
consolidated, or merged, giving a description
of their present use and of their proposed
use after disposition, consolidation, or
merger. State whether the proposed
disposition of facilities or plan for
consolidation or merger includes all the
operating facilities of the parties to the
transaction............................................ 36
G. A statement (in the form prescribed by the
Commission's Uniform System of Accounts for
Public Utilities and Licensees) of the cost
of the facilities involved in the sale,
lease, or other disposition or merger or
consolidation. If original cost is not known,
an estimate of original cost based, insofar
as possible, upon records or data of the
applicant or its predecessors must be
furnished, together with a full explanation
of the manner in which such estimate has been
made, and a description and statement of the
present custody of all existing pertinent
data and records....................................... 37
H. A statement as to the effect of the proposed
transaction upon any contract for the
purchase, sale, or interchange of electric
energy................................................. 37
I. A statement as to whether or not any
application with respect to the transaction
or any part thereof is required to be filed
with any other Federal or State regulatory
body................................................... 37
J. The facts relied upon by applicants to show
that the proposed disposition, merger, or
consolidation of facilities or acquisition of
securities will be consistent with the public
interest............................................... 38
K. A brief statement of franchises held, showing
date of expiration if not perpetual.................... 38
L. A form of notice suitable for publication in
the Federal Register, which will briefly
summarize the facts contained in the
application in such way as to acquaint the
public with its scope and purpose...................... 40
-iii-
<PAGE>
TABLE OF CONTENTS (Cont'd)
PAGE
VIII. EXHIBITS REQUIRED PURSUANT TO SECTION 33.3 OF THE
COMMISSION'S REGULATIONS......................................... 40
IX. REQUEST FOR APPROVAL OF NATIONAL GRID-NEES MERGER WITH
RESPECT TO EUA COMPANIES AND FOR INCORPORATION BY
REFERENCE OF REQUIRED EXPLANATIONS AND EXHIBITS.................. 41
X. PROCEDURAL MATTERS............................................... 44
XI. CONCLUSION....................................................... 45
-iv-
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
NEW ENGLAND POWER COMPANY, et al. )
and ) Docket No. EC99-70-000
MONTAUP ELECTRIC COMPANY, et al. )
)
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, et al.
and MONTAUP ELECTRIC COMPANY, et al.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
I. INTRODUCTION
Pursuant to Section 203 of the Federal Power Act ("FPA"),1/ and Part 33 of
the Commission's Regulations,2/ New England Power Company ("NEP") and its
affiliates holding jurisdictional assets3/ (collectively, the "NEES Companies"),
Montaup Electric Company ("Montaup") and its affiliates holding jurisdictional
assets4/ (collectively the "EUA Companies"),5/ and Research Drive LLC submit
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1/ 16 U.S.C. section 824b (1994).
2/ 18 C.F.R. section 33.1 et seq. (1998).
3/ These include the following: Massachusetts Electric Company ("Massachusetts
Electric"); The Narragansett Electric Company ("Narragansett"); New England
Electric Transmission Corporation; New England Hydro-Transmission Corporation;
New England Hydro-Transmission Electric Company, Inc.; and AllEnergy Marketing
Company, L.L.C. (which holds no physical facilities for the generation or
transmission of electricity but does hold a power marketing certificate (see 82
FERC P. 61,179 (1998))).
4/ These include the following: Blackstone Valley Electric Company
("Blackstone Valley"), Eastern Edison Company ("Eastern Edison"), and Newport
Electric Corporation ("Newport Electric").
5/ All the applicants together are referred to jointly as "Applicants." While
not applicants, the parent companies of NEP and Montaup, New England Electric
System and Eastern Utilities Associates, respectively, join this Application for
purposes of supporting the approvals sought by the Applicants.
<PAGE>
this Application seeking the Commission's approval and related waivers or
authorizations to effectuate the following: (i) the merger of Eastern Utilities
Associates ("EUA") with Research Drive LLC, which will make EUA a subsidiary of
New England Electric System ("NEES"), with EUA subsequently being consolidated
into NEES (referred to as the "HoldCo Merger"); and (ii) the subsequent mergers
and consolidations of the complementary operating companies of the two systems,
to the extent such mergers involve companies holding jurisdictional assets
(referred to as the "OpCo Mergers").
NEES is the existing holding company for the NEES Companies and EUA is
the existing holding company for the EUA Companies. Through the HoldCo Merger,
EUA will be merged so that it becomes a subsidiary of NEES, and will thereafter
be consolidated into NEES. It is expected that as soon as practicable after the
completion of the HoldCo Merger, Montaup will be merged into NEP, and the retail
operating companies of EUA will be merged into the complementary NEES operating
companies.6/ This Application seeks approval of both the HoldCo Merger and the
subsequent OpCo Mergers (which together are referred to below as the "Merger").
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6/ This means that Eastern Edison will merge into Massachusetts Electric, and
Blackstone Valley and Newport Electric will be merged and consolidated into
Narragansett. These mergers will be completed only after receipt of necessary
regulatory approvals or other authorizations. (In Rhode Island, for example,
there may be a need for a statutory change.) It is also contemplated that some
of the non-jurisdictional subsidiaries of NEES and EUA (such as the service
companies) will be merged and consolidated.
-2-
<PAGE>
The NEES Companies currently have pending in Docket No. EC99-49-000 a
request for approval of a merger that will make NEES a subsidiary of The
National Grid Group plc ("National Grid"). The two mergers are not conditioned
on each other and National Grid supports the merger of NEES and EUA and their
operating companies.7/ It is possible that the National Grid-NEES merger will be
completed before the OpCo Mergers. In that case, Commission approval would be
required for the acquisition of the EUA Companies by National Grid as a result
of the National Grid-NEES merger.8/ The NEES Companies and the EUA Companies
believe that the most efficient means of obtaining such approval would be by
having the Commission grant such approval in connection with this Application.9/
The basis and reasons for approving the National Grid-NEES merger are fully
explained in the application filed in Docket No. EC99-49. Section IX of this
Application summarizes the reasons why the same analysis should apply to the
National Grid-NEES merger with respect to the EUA Companies. Applicants thus
request that the necessary descriptions regarding the National Grid transaction,
which are presented in full in the filings in Docket No. EC99-49, be
incorporated by reference into this proceeding to permit the Commission to
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7/ While not an applicant, National Grid also joins this Application for
purposes of supporting the approvals sought by the Applicants.
8/ The reverse is not true. If the OpCo Mergers are completed before the
National Grid-NEES merger, the jurisdictional facilities at issue in this
proceeding will have been fully incorporated into and become part of the
facilities held by the applicants in Docket No. EC99-49. Accordingly, no further
approval beyond that requested in Docket No. EC99-49 would be required to
complete the National Grid merger with the then-expanded NEES operating
companies.
9/ This is a slight change from the original view noted in the EC99-49
application, which indicated that an amendment would be made to that filing.
Instead, National Grid, the NEES Companies and the EUA Companies believe that it
is more efficient to seek the approval in this Application and are doing so. No
amendment will be sought for the application seeking approval of the National
Grid merger.
-3-
<PAGE>
approve the acquisition by National Grid of the EUA Companies, which would
result from the consummation of the National Grid-NEES merger.
This Application includes all the information and exhibits required by
Part 33 of the Commission's regulations and the Commission's Merger Policy
Statement.10/ As demonstrated below, the Merger easily satisfies the criteria
established by the Commission. Accordingly, the Applicants respectfully request
that the Commission approve this Application without condition, modification or
evidentiary, trial-type hearing. The parties are attempting to close the Merger
expeditiously and seek approval by July 31, 1999.
II. EXECUTIVE SUMMARY
The Applicants request that the Commission approve the Merger pursuant
to Section 203 of the FPA. The Merger establishes a synergistic combination that
brings together the resources and skills of two complementary companies, NEES
and EUA, each focused on providing low-cost transmission and distribution
services in the New England market. Combined, the two companies provide the size
and expertise needed to allow the merged entity to take advantage of economies
of scale that would permit it to increase efficiency and thereby reduce costs
and improve service.
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10/ Inquiry Concerning the Commission's Merger Policy Under the Federal Power
Act: Policy Statement, Order No. 592, Docket No. RM96-6-000, 61 Fed. Reg. 68,595
(Dec. 30, 1996), III FERC Stats. & Regs., Regulations Preambles P. 31,044
("Merger Policy Statement"). The materials supporting the request for approval
regarding the acquisition by National Grid of the EUA Companies resulting from
the National Grid- NEES merger are incorporated by reference.
-4-
<PAGE>
Included with the Application are the required exhibits, as well as a
declaration of Dr. Henry J. Kahwaty, Senior Managing Economist at LECG, Inc.
(formerly, the Law and Economics Consulting Group) (Attachment 1), demonstrating
that the Merger will not have any adverse impact on competition. The Application
shows that the Merger is in the public interest, satisfying each of the three
tests established in the Merger Policy Statement: (1) it does not adversely
affect competition in any market; (2) it does not increase customers' rates; and
(3) it does not impair the effectiveness of regulation.
A. The Merger will not adversely affect competition.
The Merger will not have an adverse effect on competition. Indeed, as
demonstrated by the declaration of Dr. Kahwaty and as explained further below,
the Merger creates no issues with respect to generation or transmission market
power, or vertical effects. In accordance with electric restructuring
legislation and settlement agreements approved by the Commission and state
regulators, subsidiaries of both NEES and EUA have divested virtually all of
their generation assets and power purchase contracts. As a result of these
restructuring agreements, neither company has operational control over any
generation resources or the ability to increase generation prices. Moreover,
there will be no limitation on access to transmission facilities created by the
Merger because transmission will continue to be provided under
Commission-regulated open-access tariffs. Finally, both NEES' and EUA's
-5-
<PAGE>
operating affiliates provide retail access to power suppliers under open
delivery tariffs.11/ As a result, the Merger presents no vertical issues.
B. The Merger will not subject customers to increased rates.
The Merger will not increase transmission rates to wholesale customers
because Applicants are making a "hold harmless" commitment. To that end, NEP and
Montaup are contemporaneously filing under Section 205 of the FPA a transmission
rate plan that will assure that transmission customers' rates do not increase as
a result of the Merger.12/ No other rates or contracts with wholesale customers
are affected by the Merger, and the restructuring settlements terminating
requirements sales between NEP or Montaup and their respective wholesale
customers will continue to be honored after the Merger.
In addition, although the Merger will generate certain costs in the form of
an acquisition premium and transaction costs, to avoid any rate impact from
these costs, the Applicants commit to exclude the premium and the transaction
costs from Commission jurisdictional rates, unless and until permitted to
include them by specific order of this Commission. In Massachusetts and Rhode
Island, these costs are recoverable if offsetting benefits from the Merger are
demonstrated. Accordingly, the retail operating companies intend to seek
recovery of these costs as part of a comprehensive rate plan filed in those two
states. The retail rate plans are subject to the jurisdiction of the state
commissions in those states. Consequently, the Merger's effects on the rates
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11/ NEES, through its subsidiary AllEnergy, sells electricity at retail within
and outside the operating companies' combined service territories. The
electricity is delivered by the affiliated operating companies at filed,
non-discriminatory tariff rates and all affiliate dealings are subject to
standards of conduct approved by this Commission and the state commissions in
Massachusetts, Rhode Island and New Hampshire.
12/ Applicants have requested consolidation of that filing with this proceeding
since the Section 205 filing is contingent upon approval of and consummation of
the Merger.
-6-
<PAGE>
paid by the retail customers of the NEES or EUA Companies will be subject to
full regulatory review by the agency with jurisdiction. That regulatory review
will assure that the wholesale and retail rate plans associated with the Merger
are reasonable for all customers.
C. The Merger will not impair the effectiveness of federal
or state regulation.
The Merger will not adversely affect either federal or state
regulation. With respect to federal regulation, NEES and EUA are currently
registered holding companies under the Public Utility Holding Company Act of
1935 ("PUHCA")13/ and consequently there will be only a very limited impact on
the federal regulatory structure as a result of the Merger. To avoid any impact
on federal regulation from this change, the Applicants commit to be subject to
the Commission's policy regarding intra-corporate transactions for those
transactions involving the sale of non-power goods and services between Montaup,
NEP, and their franchised public utility affiliates.
With respect to state regulation, Applicants believe that the states
will continue to have the same jurisdiction over the operations of the utilities
after the Merger as they had before. In any case, filings have been or will be
made with the appropriate state regulatory commissions seeking approval of the
Merger, where necessary. Each affected state will thus have a full opportunity
to address any impact on state regulation in connection with those filings. The
Merger, accordingly, will not impair state regulation.
* * * *
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13/ 15 U.S.C. ss. 79 et seq. (1994).
-7-
<PAGE>
Because the Merger satisfies all of the requirements of Section 203 of
the FPA, the Commission's regulations and the Merger Policy Statement, the
Commission should find that the Merger is consistent with the public interest
and approve the Application by July 31, 1999, without modification or condition
and without holding a trial-type hearing.
III. DESCRIPTION OF THE PARTIES TO THE MERGER
A. The NEES System of Companies
1. NEES
NEES is a registered public utility holding company headquartered in
Westborough, Massachusetts. Its subsidiaries are engaged in the transmission and
distribution of electricity and the marketing of energy commodities and
services. The electricity delivery companies serve approximately 1.3 million
customers in Massachusetts, Rhode Island, and New Hampshire. Other NEES
subsidiaries offer telecommunications and other services. NEES does not directly
own any facilities subject to Commission jurisdiction.
2. NEP
NEP, a wholly-owned subsidiary of NEES, is a Commission-regulated
public utility company organized and operated under the laws of the Commonwealth
of Massachusetts. It operates over 2,600 miles of transmission facilities. NEP
has recently disposed of effectively all its non-nuclear generating assets,14/
but still holds minority, non-operating interests in three nuclear generating
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14/ NEP continues to own a 9.3 percent share in a single oil-fired generating
unit, which it is selling. See Attachment 1 at paragraph 6.
<PAGE>
companies with retired nuclear facilities (Connecticut Yankee, Maine Yankee, and
Yankee Atomic) and in three other operating nuclear units (Millstone 3, Seabrook
and Vermont Yankee). NEP has agreed to attempt to divest these nuclear
entitlements as required by its restructuring settlements approved by this
Commission and the state commissions regulating its affiliates.
3. Affiliates of NEP
a. Distribution Companies
(1) Massachusetts Electric
Massachusetts Electric is a wholly-owned subsidiary of NEES and
delivers electric energy to approximately 980,000 retail customers in 146 cities
and towns in the Commonwealth of Massachusetts. Massachusetts Electric's service
area covers approximately 43 percent of the Commonwealth.
(2) Narragansett
Narragansett is a wholly-owned subsidiary of NEES. Narragansett is the
largest electric utility company in Rhode Island and provides delivery service
to approximately 335,000 retail customers across a service territory that covers
27 cities and towns.
(3) Granite State Electric Company
Granite State Electric Company ("Granite State") is a wholly-owned
subsidiary of NEES operating in New Hampshire. It is engaged in the distribution
of electric energy at retail. Granite State provides service to approximately
37,000 customers in 21 communities.
(4) Nantucket Electric Company
Nantucket Electric Company ("Nantucket Electric") is a wholly-owned
subsidiary of NEES operating in the Commonwealth of Massachusetts. Nantucket
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Electric is engaged in the distribution of electric energy at retail to
approximately 10,000 customers on Nantucket Island. The company's service area
covers the entire island.15/
b. Transmission Companies
(1) New England Electric Transmission Corporation
New England Electric Transmission Corporation is a wholly-owned
subsidiary of NEES and operates a direct current/alternating current converter
terminal and related facilities for the first phase of the Hydro-Quebec and New
England interconnection and six miles of high-voltage direct current
transmission line in New Hampshire.
(2) New England Hydro-Transmission Corporation
NEES owns 50.4338 percent of the common stock of New England
Hydro-Transmission Corporation. New England Hydro-Transmission Corporation
operates 121 miles of high-voltage direct current transmission line in New
Hampshire for the second phase of the Hydro-Quebec and New England
interconnection, extending to the Massachusetts border.
(3) New England Hydro-Transmission Electric
Company, Inc.
NEES owns 50.4338 percent of the common stock of New England
Hydro-Transmission Electric Company, Inc. which operates a direct
current/alternating current terminal and related facilities for the second phase
of the Hydro-Quebec and New England interconnection and 12 miles of high-voltage
direct current transmission line in Massachusetts.
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15/ Both Granite State and Nantucket Electric support the transaction, but are
not listed as applicants because neither owns any jurisdictional facilities.
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<PAGE>
c. Energy Marketer - AllEnergy Marketing
Company, L.L.C.
NEES, through its subsidiary, NEES Energy, Inc., owns 100 percent of
the voting securities of AllEnergy Marketing Company, L.L.C. ("AllEnergy").
AllEnergy is a power marketer operating under a Commission certificate. It is
engaged in the sale of electric energy, natural gas and heating oil to
commercial, industrial and residential consumers in competitive markets in the
Northeast, as well as offering related value-added services. AllEnergy also
markets propane, fuel oil and other liquid fuels through its subsidiary, Texas
Fluids. In addition, AllEnergy sells fuel oil through its PAL and Griffith
operating divisions, which were recently acquired by the Company.
d. Research Drive LLC
Research Drive LLC, a Massachusetts limited liability company, is
owned by NEES and NEES Global, Inc. and was formed for the express purpose of
effectuating the HoldCo Merger.
e. Other Companies
NEES owns equity in the following companies: NEES Global, which owns a
100 percent equity interest in New England Water Heater Co., Inc. (providing
rental, service, sales and installation of water heaters) and which also
provides consulting services to utilities in the United States, Canada and
elsewhere; New England Power Service Company (providing support services to NEES
and its subsidiaries); NEES Communications, Inc. (providing telecommunication
and information-related products and services); Granite State Energy, Inc.
(marketing electricity to New Hampshire customers participating in that state's
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<PAGE>
pilot program for retail choice) and Metrowest Realty LLC (owning certain
properties occupied by NEES subsidiaries).
B. The EUA System of Companies
1. EUA
EUA is a diversified energy-services holding company organized and
existing in Massachusetts. Its utility subsidiaries are engaged in the
transmission and distribution of electricity in Massachusetts and Rhode Island,
delivering electric service to more than 305,000 consumers in southeastern
Massachusetts and northern and coastal Rhode Island. Non-utility subsidiaries
market energy efficiency services nationwide and invest in other non-regulated
businesses.
2. Affiliates of EUA
a. Distribution Companies
(1) Eastern Edison
Eastern Edison is a wholly-owned subsidiary of EUA. It provides
distribution service to approximately 186,000 customers in non-contiguous
service territories covering the southeastern Massachusetts cities of Brockton
and Fall River plus 20 surrounding towns. Together with Montaup, it owns
approximately 4,600 miles of transmission and distribution lines.
(2) Blackstone Valley
Blackstone Valley is a wholly-owned subsidiary of EUA. It provides
distribution service to approximately 86,000 customers in the northern Rhode
Island cities of Pawtucket and Woonsocket and five neighboring communities. It
owns approximately 1,700 miles of transmission and distribution lines.
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<PAGE>
(3) Newport Electric
Newport Electric is a wholly-owned subsidiary of EUA. It provides
distribution service to approximately 33,000 customers in Newport, Jamestown,
Middletown, and Portsmouth, Rhode Island. Newport Electric owns approximately
800 miles of transmission and distribution lines.
b. Transmission Company
(1) Montaup
Montaup, which is a subsidiary of Eastern Edison, provides
transmission service in interstate commerce to its retail distribution
affiliates (Eastern Edison, Blackstone Valley, and Newport Electric) and to two
non-affiliated municipal electric utilities.16/ Montaup previously sold
significant amounts of wholesale electricity but, as part of the restructuring
of the utility industry in Massachusetts and Rhode Island, Montaup has
negotiated comprehensive settlement agreements with its regulators. These
settlement agreements, which have been approved by the state commissions as well
as by this Commission (in Docket Nos. ER97-2800-000, et al.), provide for the
complete divestiture of Montaup's generating business. In conformance with those
settlements, Montaup has recently sold or signed purchase and sale agreements
for all its non-nuclear generation assets.17/
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16/ Montaup has a very small stock ownership investment in New England
Hydro-Transmission Corporation and New England Hydro-Electric Transmission
Electric Company, Inc.
17/ See Attachment 1 at paragraph 8. As explained below, Montaup's affiliate,
EUA Ocean State Corporation, continues to retain its ownership interest in Ocean
State Power, an independent power producer.
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Montaup currently has minority, non-operating interests in the same
nuclear generating companies as NEP, including those with retired nuclear
facilities (Connecticut Yankee, Maine Yankee and Yankee Atomic) and those with
operating units (Millstone 3, Seabrook and Vermont Yankee). Montaup has signed
an agreement for the sale of its share of Seabrook, for which it is seeking
regulatory approval, and it is attempting to divest its remaining nuclear
ownership interests.
c. Energy Providers
(1) EUA Ocean State Corporation
EUA Ocean State, wholly-owned by EUA, owns a 29.9 percent partnership
interest in the Ocean State Power generating station in northern Rhode Island, a
non-utility generating plant that is subject to regulation by the Commission.
EUA Ocean State does not market the power produced from this plant. All rights
to the power produced are committed under long term contracts.
d. Other Companies18/
(1) EUA Cogenex Corporation
EUA Cogenex, a wholly-owned subsidiary of EUA, is an energy services
company that utilizes energy efficient technology and equipment to reduce the
energy consumption and costs of its customers.19/ EUA Cogenex has service
agreements nationwide and in Canada.
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18/ Besides the companies listed in this section, EUA also owns EUA Energy
Services, which was created to own an interest in a limited liability company.
That limited liability company has broken up, and EUA Energy Services is
currently inactive.
19/ EUA Cogenex Corporation also owns EUA Day, which is primarily engaged in
the business of customization, installation, and servicing of building
temperature control systems for the purpose of energy conservation.
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<PAGE>
(2) EUA Energy Investment Corporation
EUA Energy Investment Corporation is a wholly-owned subsidiary of EUA.
It invests in energy-related projects, including the following: Bluestone Energy
Services (proposed regional water desalinization plant); EUA BIOTEN (developing
biomass-fueled generating units); EUA Compression Services (joint venture being
developed to market automated electric compression systems to natural gas
pipeline companies); Separation Technologies, Inc. (markets and installs
equipment for separating unburned carbon); Renova (provides lighting products
designed to achieve an efficiency gain through the integration of various lamp,
ballast, and light reflector products); and EUA TransCapacity (markets services
and computer software to natural gas clients).
(3) EUA Service Corporation
EUA Service Corporation provides professional and technical services
to all EUA System companies.
(4) EUA Telecommunications
EUA Telecommunications was established to provide telecommunications
and information services to third-party customers.
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<PAGE>
IV. DESCRIPTION OF THE MERGER
A. Goals and Benefits of the Merger
As is explained in more detail in the attached filings with state
commissions,20/ the Merger is one that produces traditional synergies from
combining the resources and skills of two complementary companies focused on
providing services in the same market. The two companies are organized
similarly, with a holding company established over a federally regulated
transmission company serving retail distribution affiliates, a service company
and various unregulated affiliates. Each is a low-cost provider, has a similar
philosophy of system operations, offers strong customer service and has a lean
workforce. Combined, the two companies will achieve economies of scale necessary
to increase efficiency and thereby reduce costs. Applicants believe that
customers, employees and shareholders will all benefit from the combination.
Customers will benefit by being served by a larger, more
cost-efficient enterprise, with the same commitment to the region that each
company has demonstrated in the past. Consolidation and elimination of redundant
operations will help produce efficiency gains that will result in savings, which
in turn will be important in maintaining low rates. Applicants have studied the
potential for these efficiency gains.21/ The study identifies annual savings
(after netting out costs to achieve them) of more than $27 million in 2002,
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20/ See Testimony of M. Jesanis and Testimony of R.G. Powderly in New England
Electric Systems and Eastern Utilities Associates, Massachusetts Department of
Telecommunications and Energy, Dkt. No. D.T.E.99-47 ("Joint Massachusetts
Filing"), copy included in Exhibit G.
21/ The results of the study are included in the Testimony of Hoffman and Levin
in Joint Massachusetts Filing.
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<PAGE>
escalating thereafter.22/ The Applicants also believe that the combination of
the two companies will enhance expertise and allow more resources to be invested
in customer service and modern transmission and distribution technology.23/ This
will permit the merged entity to provide better service to all customers.
Employees will also benefit from the Merger. Although there will be an
initial, small reduction in the workforce (which will be accomplished through
attrition or early retirement), the new, stronger company will have both the
incentive and resources to expand the business. This will offer increased
opportunities for employees. Upon conclusion of NEES's merger with National
Grid, these opportunities will expand to encompass the international market.
Finally, shareholders will benefit. EUA's shareholders will receive a
price for their stock that reflects a premium over value, whether compared to
market (23 percent over the price on the last trading day before other mergers
in this industry were announced and 5 percent over the price on the day before
this Merger was announced) or book value (169 percent of book value).
B. Procedural Status of the Merger
The Merger Agreement (attached as Exhibit H) establishes the procedure
for the HoldCo Merger. It will be accomplished by having Research Drive LLC
merge with EUA, which will make EUA a wholly-owned subsidiary of NEES. EUA will
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22/ Testimony of Hoffman and Levin, supra n. 21 at 7, 26 and Exhibit DJH-1.
23/ As the applicants in Docket No. EC99-49-000 explained, National Grid has
expertise in operating transmission systems in connection with ISO, Transco, and
power exchange structures in the United Kingdom, Argentina and other countries.
The EUA-NEES merger extends to EUA's customers the benefits that will be
produced from gaining access to that expertise as a result of the National
Grid-NEES merger.
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<PAGE>
then merge into NEES. EUA's shareholders will receive in return for their shares
a cash payment of $31.00 per share (subject to upward adjustment). The total
purchase price is approximately $634 million.
After completion of the HoldCo Merger, Applicants intend to merge EUA's
operating companies into the NEES operating companies, as well as merge certain
non-regulated entities (such as the service companies). The NEES operating
companies will be the surviving entities in these OpCo Mergers, which require
the approval of various state regulators.24/
The Boards of Directors of both NEES and EUA have approved the Merger,
as shown in Exhibit A. The completion of the Merger is subject to certain
conditions, including those involving regulatory and shareholder approval, which
are now being sought.
As the Commission is aware by the Section 203 application filed on
March 10, 1999, in Docket No. EC99-49-000, NEES is seeking authority to merge
with National Grid, with NEES becoming a wholly-owned subsidiary of National
Grid. If the National Grid-NEES merger is completed before the OpCo Mergers,
National Grid would effectively acquire the EUA Companies. That acquisition
would require Commission approval, which, as explained earlier, this Application
is seeking concurrently with approval of this Merger.
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24/ In addition, legislative action may be required in Rhode Island.
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<PAGE>
V. THE MERGER IS CONSISTENT WITH THE PUBLIC INTEREST
Section 203(a) of the FPA provides, in pertinent part, that
No public utility shall sell, lease, or otherwise
dispose of . . . its facilities subject to the
jurisdiction of the Commission . . . or by any means
whatsoever, directly or indirectly, merge or
consolidate such facilities or any part thereof with
those of any other person, or purchase, acquire, or
take any security of any other public utility, without
first having secured an order of the Commission
authorizing it to do so . . . . After notice and
opportunity for hearing, if the Commission finds that
the proposed disposition, consolidation, acquisition,
or control will be consistent with the public interest,
it shall approve the same.25/
The statute thus requires the Commission to approve a merger if it
finds the merger is in the public interest. In the Merger Policy Statement the
Commission established that the following issues need to be examined to
determine if a merger is in the public interest: (1) the effect of the merger on
competition; (2) the effect of the merger on rates; and (3) the effect of the
merger on regulation. As is demonstrated in this Application and supporting
materials, the Merger will not have an adverse effect in any of the three areas.
Consequently, the Merger is in the public interest and the Commission should
approve it promptly.
A. The Merger Will Have No Adverse Effect on Competition.
The declaration of Dr. Henry Kahwaty (Attachment 1) establishes that
the Merger raises no competitive issues. Dr. Kahwaty examines the Merger with
respect to horizontal market power concerns involving generation and
transmission, and with respect to vertical issues. Dr. Kahwaty concludes that
the Merger will not result in a reduction in competition in any of these areas.
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25/ 16 U.S.C. section 824b(a) (1994) (emphasis added).
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<PAGE>
1. The Merger Will Not Increase Market Power with
Respect to Generation
Dr. Kahwaty explains that pursuant to electric utility restructuring
legislation and settlement agreements approved by the Commission and state
regulators, both NEP and Montaup have divested virtually all of their generation
assets and power purchase contracts.26/ Upon conclusion of all pending sales,
the combined entity will own a de minimus share of generation in the relevant
market of New England, less than 2 percent.27/ Moreover, since both companies
are committed to selling their few remaining generation resources, this de
minimus share will decrease to zero when the resources are successfully sold.28/
While NEP and Montaup retain ownership interests, neither has
operational control over any generation resources, and thus neither has control
over the output of those facilities. They cannot restrict output in an attempt
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26/ Attachment 1 at paragraphs 6 and 8. Montaup also has a power purchase
agreement with the buyer of the Pilgrim nuclear facility, which, upon
termination of its existing life of unit contract would entitle Montaup to an 11
percent share of the plant's output, which share declines over time. Id. at
paragraph 8. Both NEP and Montaup have either transferred or agreed to transfer,
subject to Commission approval, the economic benefit and burden of their other
power purchase contracts, although technically each may still be a party to many
of them even after the transfer is complete. NEP and Montaup do sell the output
from their share of the few remaining generation units (primarily nuclear) that
have not been divested. Those sales are made to entities participating in the
competitive wholesale market in New England.
27/ Attachment 1 at paragraphs 18 and 19.
28/ Id. at paragraph 21.
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to increase prices.29/ Similarly, neither company has direct ability to increase
prices, given the remaining de minimus share of generation resources they own.
Even assuming arguendo that there were a concern with respect to de
minimus generation assets held by the Applicants, Dr. Kahwaty explains that
construction and expansion of generation is occurring in the New England market,
and this new entry limits horizontal market power concerns with respect to
generation.30/
Finally, Dr. Kahwaty examines the generation market by applying the
Department of Justice and Federal Trade Commission's Horizontal Merger
Guidelines, using the Herfindahl-Hirschman Index of Concentration ("HHI"). This
analysis is performed by overlaying the EUA-NEES changes on the results from
three other recent studies of the market. Given that this is a moderately
concentrated market, the safe-harbor screening threshold for the HHI Index is an
increase of 100. In each of the three cases for the markets examined, the
increase in the HHI is almost nonexistent, producing increases of less than two
(2) to less than twelve (12) at the highest.31/ Consequently, Dr. Kahwaty
concludes that there will be no adverse competitive effects in the generation
market from the Merger.
2. The Merger Will Not Have an Adverse Effect on
the Transmission Market in New England.
NEP and Montaup are members of the New England Power Pool ("NEPOOL")
and have committed their pool transmission facilities to the operational control
of the ISO-New England. The NEPOOL tariff provides for open-access transmission
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29/ Id. at paragraph 22.
30/ Id. at paragraphs 24 - 26.
31/ Id. at paragraphs 27 - 30 and Appendix.
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under regulated rates.32/ In addition, NEP and Montaup provide transmission
service on their local facilities under existing open-access transmission
tariffs. Neither NEP nor Montaup have offered discounts under their tariffs to
gain transmission customers or otherwise.33/ Moreover, none of the three
transmission-dependent utilities served by Montaup is interconnected with NEP's
system. As a result, these three entities do not choose between taking service
from NEP or Montaup, and NEP and Montaup do not compete for the sale of
transmission services.34/ Furthermore, as explained in the Section 205
application filed by NEP and Montaup contemporaneously with this Section 203
Application, after the HoldCo Merger, NEP and Montaup will provide service under
a unified set of terms and conditions under a Commission-approved open-access
transmission tariff.35/ Consequently, access to the combined transmission
facilities of NEP and Montaup will not be restricted in any manner by the
Merger, and there can be no concern regarding transmission market power.36/
3. The Merger Does Not Raise Vertical Issues.
Dr. Kahwaty's declaration also considers potential vertical issues. He
explains that, as a result of industry restructuring, both NEES and EUA are
exiting the generation business and the operating companies provide retail
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32/ Id. at paragraph 32.
33/ Id. at paragraph 33.
34/ Id.
35/ See Testimony of P. Viapiano filed in Application for Required Approvals
Under Section 205 of the Federal Power Act for Merger of New England Electric
System and Eastern Utilities Associates, Docket No. ER99-_____ ("Section 205
Filing").
36/ Attachment 1 at paragraph 33.
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<PAGE>
access under filed non-discriminatory transmission and distribution tariffs. The
operating companies are all subject as well to standards of conduct established
by the Commission and relevant state commissions. All retail customers served by
NEP's and Montaup's distribution affiliates therefore have the ability and right
to purchase electricity from the market and have it delivered under
non-discriminatory, filed rates. Consequently, the NEES and EUA Companies no
longer operate as vertically integrated concerns, and the Merger will not result
in adverse vertical competitive effects.37/
Dr. Kahwaty also concludes that, except for transmission and
distribution services, which, as explained above, are provided at
non-discriminatory, regulated tariff rates, the NEES and EUA Companies do not
control key inputs used in the production or delivery of electric products or
services to each other or to other utilities in New England.38/ Accordingly, Dr.
Kahwaty concludes that the Merger is not a vertical merger, and will not impact
the incentive or ability of the NEES or EUA Companies to affect competition or
competitors through vertical effects.
4. Conclusion Regarding Effect of the Merger on Competition
Dr. Kahwaty's analysis demonstrates that the Merger will not have any
adverse effect on competition. The Merger creates no market power issues with
respect to generation, transmission or vertical arrangements and the transaction
easily passes the competitive screen adopted by the Commission in its Merger
Policy Statement. In fact, Dr. Kahwaty concludes that the Merger will likely
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37/ Id. at paragraph 34.
38/ Id. at paragraph 35. It should be noted that NEP and Montaup own land for
future use that may be considered potential generation sites, but those
properties will be divested.
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result in significant efficiencies that will promote competition in retail
electricity markets.39/ The Merger thus satisfies the first test of the
Commission's Merger Policy Statement. (It should be noted that on April 30,
1999, the Federal Trade Commission granted the Applicants early termination of
the pre-merger notification waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976.)
B. The Merger Will Have No Adverse Effect on Rates.
The Merger Policy Statement provides that the Commission's concern
regarding the effect on rates is with wholesale and transmission ratepayer
protection.40/ The Commission has made clear that if customers are held harmless
from cost increases as a result of a merger, this second test is satisfied.41/
Applicants commit to hold their customers harmless from such rate increases.
1. Applicants Have Proposed a Rate Plan That Will Hold
Transmission Ratepayers Harmless.
As described in the accompanying Section 205 Filing, Applicants
propose a rate plan for their local transmission service charges42/ that would
apply to the two phases of the Merger: (1) during the period between the
conclusion of HoldCo Merger but before the conclusion of the merger of NEP and
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39/ Id. at paragraphs 37-40; see Jesanis, supra note 20 and Hoffman and Levin,
supra note 21 for further descriptions of the efficiencies.
40/ Merger Policy Statement at 68,599.
41/ See, e.g., id. at 68,603; MidAmerican Energy Co. and MidAmerican Energy
Holdings Co., 85 FERC paragraph 61,354 (1998) (no additional protection needed
for transmission customers if held harmless from costs).
42/ There will be no impact from the Merger on the rates applicable to the use
of NEP's or Montaup's transmission systems for non-local service, since the
NEPOOL tariff rate would continue to apply.
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Montaup; and (2) after the merger and consolidation of Montaup into NEP. During
the first phase, the formula rates for local transmission service on the
effective date of the HoldCo Merger would continue to apply to each company's
respective customers. Accordingly, during the first phase, transmission
customers would see no change in the formula or the cost elements that are
included in their local transmission service charge.43/
During the second phase, a single formula transmission rate, using
NEP's currently effective tariff formula, would be placed into effect. Because
NEP's rates are slightly higher than Montaup's, all of NEP's customers,
affiliated and non-affiliated, would experience lower rates. Montaup's existing
non-affiliated customers (the municipalities of Middleborough, Taunton and
Pascoag) would face a slight rate increase if no action were taken. To avoid
this, the rate plan would apply special provisions to these customers that would
freeze their local transmission service charges at the pre-existing Montaup rate
level. As explained in the testimony in the Section 205 Filing, under the terms
of a transition rate plan adopted by NEPOOL, over several years these local
charges would be phased out for those customers not actually using local
facilities. For those customers actually using such local facilities, the charge
would remain, but would be reduced to reflect Montaup's pre-existing local
facilities charges prior to the OpCo Mergers, and then locked-in for at least
five years.44/
With regard to transmission charges to NEP's and Montaup's affiliated
distribution companies and the transmission components of retail rates, the
analysis is similar. NEP's distribution affiliates would see lower transmission
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43/ See Testimony of P. Viapiano, supra, n. 35 at 6-8.
44/ Id. at 10-11.
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rates, while customers of Montaup's distribution affiliates would face a small
increase in transmission rates. This small increase in the transmission
component of retail rates to Montaup's affiliates, however, will be more than
offset by other components of a comprehensive rate plan.
Specifically, in Massachusetts, NEP's and Montaup's customers pay a
Contract Termination Charge ("CTC"), which is a charge assessed to former
requirements customers by NEP and Montaup that permits the companies to recover
an allocable share of the costs each had incurred to provide service to those
former requirements customers.45/ Montaup's CTC is greater than NEP's, and the
blending of the two more than offsets the small increase in the transmission
component of the retail rate. Moreover, the distribution component of the retail
rate will be frozen, providing economic benefits to all retail customers in
Massachusetts.
A similar result will occur in Rhode Island, where Montaup's
affiliates Blackstone Valley and Newport Electric will be consolidated with
Nagagansett. The rate plan will produce lower rates for Blackstone Valley's and
Newport Electric's customers by reducing distribution rates for their customers
and by equalizing over time transmission and CTC charges. In all cases, the
blending of the CTCs will offset any transmission cost increases to Montaup's
affiliates, producing no adverse rate effects from the transmission rate
consolidation.46/
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45/ The CTC includes the costs associated with investments in generating
assets, contractual commitments for purchased power and fuel transportation,
deferred costs, and other regulatory assets.
46/ See Testimony of P. Viapiano, supra, n. 35 at 14-17. Another change that
would be made as a result of the consolidation of Montaup's and NEP's tariffs is
one regarding charges applicable to interconnections to the local transmission
system for delivery to the NEPOOL "PTF" system. The tariff change, however,
would not increase any customer's cost, but instead would reduce the costs of
the one former Montaup customer affected. Id. at 6-7.
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2. No Recovery of Transaction Costs and Acquisition Premium
Will Be Awarded Without Proof of Countervailing Benefits.
There will be an acquisition premium and transaction costs associated
with the Merger,47/ but the Applicants are not requesting in this Application or
in the accompanying Section 205 rate filing to recover these items through
wholesale transmission rates that are subject to the Commission's
jurisdiction.48/ The acquisition premium and transaction costs may be pushed
down to the operating companies.49/ Under state law governing the operating
companies, recovery of the acquisition premium and transaction costs requires a
showing of countervailing savings or other benefits.50/ Neither the acquisition
premium nor transaction costs will be recovered in rates at either the state or
federal level without separate approval by the appropriate regulatory agency.
Consequently, there can be no adverse effect on rates.
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47/ See Testimony of M. Jesanis, supra, n. 20 at 30.
48/ Applicants recognize that Commission policy would ordinarily not allow
recovery in wholesale or transmission rates of an acquisition premium for this
kind of transaction. See, e.g., Arkla Energy Resources, 61 FERC paragraph 61,004
(1992); Minnesota Power & Light Co. and Northern States Power Co., 43 FERC
paragraph 61,104, 61,342 (1988); United Gas Pipe Line Co., 25 FPC 26 (1961),
reversed and remanded on other grounds sub nom., Willmut Gas and Oil Co. v. FPC,
299 F.2d 111 (D.C. Cir. 1962). Accordingly, Applicants will not request recovery
of the acquisition premium or transaction costs in rates subject to the
Commission's jurisdiction absent a change in policy from the Commission.
49/ See Testimony of M. Jesanis, supra, n. 20 at 30-33.
50/ See, e.g., Northern Indiana Public Service Co. - Bay State Gas Co.
Acquisition, Docket D.T.E. 98-31 (Mass. D.T.E. 1998); Eastern Enterprises -
Essex Gas Co. Acquisition, Docket D.T.E. 98-27 (Mass. D.T.E. 1998); Mergers and
Acquisitions, Docket D.T.E. 93-167-A (Mass. D.P.U. 1994); Valley Gas Co., Docket
No. 2276, pp. 18-20 (Rhode Island PUC, Oct. 18, 1995).
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3. Conclusion Regarding Effect on Rates.
Applicant's rate plan combined with their commitment regarding no
recovery of transaction costs or any acquisition premium without countervailing
savings will hold ratepayers harmless from the effects of the Merger.51/ The
second test is satisfied.
C. The Merger Will Have No Adverse Effect on Regulation.
In the Merger Policy Statement, the Commission stated that its
analysis would address two aspects in order to determine whether a merger would
impair effective regulation. The first is whether the merger would transfer
authority from the Commission to the Securities and Exchange Commission ("SEC").
If no such transfer would occur or if the applicants were to commit to abide by
the Commission's policies with respect to intra-system transactions within the
holding company structure, the test would be satisfied. Otherwise, a hearing on
the impact of the proposed transaction on effective regulation by the Commission
would be required. The second part of the test is whether the affected states
would have authority to act on the merger.52/ If the states have authority to
act on the merger, the Commission will find that there would be no adverse
effect on state regulation, and will not set the issue for hearing. The Merger
satisfies both aspects of this test and hence would not impair effective
regulation at the federal or state level.
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51/ There are no rate concerns associated with wholesale sales of electricity
because NEP and Montaup make only extremely limited wholesale sales to
non-affiliates, with Montaup's sales terminating in 1999 and 2000. Under
approved settlement agreements, Montaup and NEP have wholesale back-up sales
obligations to their affiliates, but these obligations are provided under
standard offer fixed price schedules, which, in any event, have been assigned to
the purchasers of NEP's and Montaup's generation assets.
52/ Merger Policy Statement at 68,603-04.
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1. Federal Regulation
NEES and EUA are currently registered holding companies under PUHCA
and consequently there will be only a very limited impact on the federal
regulatory structure as a result of the Merger. The Merger will have no impact
on the relationship of NEES to its subsidiaries. Although initially the EUA
operating companies will be separate affiliates of NEES, upon completion of the
OpCo Mergers, the EUA affiliates will cease to exist, and hence the companies'
structure will return to the pre-existing NEES structure.
At the same time, Applicants recognize the commitment that Montaup has
made currently in its Standards of Conduct53/ regarding sales of non-power goods
and services.54/ In order to avoid any change in the pre-existing scope of
federal regulation, Applicants make the following commitment: after completion
of the HoldCo Merger, any transaction involving the sale of non-power goods and
services between NEP or Montaup and any of their franchised public utility
affiliates will be subject to the same commitment currently applicable to
Montaup under its Standards of Conduct.55/ Because this commitment assures that
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53/ Applicants understand that, upon conclusion of the HoldCo Merger, both
NEP's and Montaup's Standards of Conduct will apply to their respective new
affiliated entities. Upon completion of the merger of Montaup into NEP,
Montaup's Standards of Conduct will cease to exist, and NEP will be governed by
its then-existing standards which, of course, would apply to any remaining
former EUA affiliates, as well as all existing NEES affiliates.
54/ These commitments are as follows: "(1) any sale of non-power goods or
services by the Company [Montaup] to its franchised public utility affiliate
shall be at a price equal to the higher of its cost or market; and (2) any sale
of non-power goods or services by a franchised public utility affiliate to the
Company [Montaup] shall be at a price not to exceed market."
55/ See n. 54, supra. Upon completion of the OpCo and related mergers, many of
the currently existing EUA Companies will cease to exist and, of course, this
commitment would cease with respect to those entities at that time.
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the Commission will have oversight over sales of non-power goods and services,
there will be no adverse effect on federal regulation from the transaction.
2. State Regulation
With respect to state regulation, the commissions in Massachusetts and
Rhode Island, which have direct jurisdiction over the consolidation of the
operating companies, will need to approve the mergers of the operating companies
and the associated retail rate plans. In addition, state commissions in New
Hampshire and Vermont, where Montaup owns property, may need to approve the
transaction. Applicants believe that the states will continue to have the same
jurisdiction over the operations of the utilities after the Merger as they had
before, but, in any case, each affected state will have a full opportunity to
address any impact on state regulation in connection with the filings that have
been or will be made. No further action or review by the Commission is therefore
required. Accordingly, there will be no adverse effect on state regulation as a
result of the Merger.
VI. ACCOUNTING TREATMENT
In accordance with the Merger Policy Statement,56/ proper accounting
principles will be applied to the Merger. The proposed transaction will be
accounted for using the purchase method of accounting because the necessary
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56/ Merger Policy Statement at 68,604.
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conditions to apply pooling of interest accounting are not met by the structure
of this business combination.57/ The purchase method has been approved by the
Commission when the pooling of interests method is not appropriate.58/ The
acquisition premium recorded under the purchase method of accounting may be
pushed down to the EUA operating companies.59/ Recording the acquisition premium
on the acquired companies' books is consistent with SEC guidance,60/ and the
Commission has approved it previously.61/
Section IV.A., above, explains that the Applicants expect to achieve
savings and efficiencies for their customers as a result of this Merger. To the
extent the acquisition premium and transaction costs are pushed down, the retail
operating companies are seeking permission from state authorities to recover the
acquisition premium and transaction costs in rates when it can be demonstrated
that such savings and efficiencies have been achieved.62/ The operating
companies subject to the Commission's jurisdiction will seek rate recovery only
if Commission policy changes to permit such recovery.
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57/ This acquisition is being accomplished by an exchange of EUA's shares for
cash, not by an exchange of EUA shares for NEES shares as required under the
pooling rules.
58/ MidAmerican Energy Co., 85 FERC at 62,370; PG&E Corp. and Valero Energy
Corp., 80 FERC paragraph 61,041 (1997); Enron Corp. and Portland General Corp.,
78 FERC paragraph 61,179, 61,739-40; Entergy Services, Inc. and Gulf States
Utils. Co., 65 FERC paragraph 61,332, 62,532-40 (1993).
59/ That premium would then be moved to the appropriate NEES company upon
conclusion of the OpCo Mergers.
60/ See APB Opinion No. 16.
61/ See El Paso Electric Co. and Central and South West Services, Inc., 68 FERC
paragraph 61,181, 61,918-19 (1994); Entergy Services, 65 FERC at 62,537.
62/ See Section V.B.2, above.
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Finally, consistent with Commission policy, Applicants will submit
their proposed accounting entries to the Commission for approval within six
months after the Merger is consummated.63/ This submission will provide all
accounting entries necessary to reflect the Merger, along with appropriate
narrative explanations describing the bases for the entries.
VII. INFORMATION REQUIRED OF APPLICANTS BY SECTION 33.2
OF THE COMMISSION'S REGULATIONS
A. The exact name and address of the principal business office.
The address of the principal business office to be used for the NEES
companies is:
New England Power Company
25 Research Drive
Westborough, MA 01582
The address of EUA's principal business office is:
Eastern Utilities Associates
1 Liberty Square
Boston, MA 02107
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63/ MidAmerican Energy Co., 85 FERC at 62,370; 18 C.F.R. Pt. 101, Electric
Plant Instruction No. 5 and Account 102, paragraph B (1998).
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B. Name and address of the person authorized to receive notices
and communications with respect to application.
For the NEES Companies:
Edward Berlin, Esq. Thomas G. Robinson, Esq.
Kenneth G. Jaffe, Esq. New England Power Company
Scott P. Klurfeld, Esq. 25 Research Drive
Swidler Berlin Shereff Friedman, LLP Westborough, MA 01582
3000 K Street, N.W., Suite 300 Telephone: 508-389-2877
Washington, DC 20007-5116 Facsimile: 508-389-2463
Telephone: 202-424-7500 [email protected]
Facsimile: 202-424-7643
[email protected]
[email protected]
[email protected]
For EUA:
David A. Fazzone, Esq. of
David A. Fazzone, P.C., and
McDermott, Will & Emery
28 State Street
Boston, Massachusetts 02109-1775
Telephone: 617-535-4000
Facsimile: 617-535-3800
[email protected]
C. Designation of the territories served by counties and states.
NEP provides transmission service through facilities located in
Massachusetts, Rhode Island, New Hampshire, and Vermont. It also continues to
provide very limited wholesale electric service to a few customers.
Granite State Electric Company provides retail electric service in 23
municipalities in Cheshire, Grafton, Hillsborough, Rockingham, and Sullivan
Counties in New Hampshire.
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Massachusetts Electric provides retail electric service in 149
municipalities in Berkshire, Bristol, Essex, Franklin, Hampden, Hampshire,
Middlesex, Norfolk, Suffolk, and Worcester Counties in Massachusetts.
Nantucket Electric Company provides retail electric service in the
County of Nantucket in Massachusetts.
Narragansett provides retail electric service in 27 municipalities in
Bristol, Kent, Newport, Providence, and Washington Counties in Rhode Island.
New England Electric Transmission Corporation, New England Hydro-
Transmission Corporation, and New England Hydro-Transmission Electric Company,
Inc. provide high-voltage transmission service in New Hampshire or
Massachusetts.
AllEnergy sells electric power and other energy products as a marketer
throughout the Northeast and elsewhere in the United States.
Montaup provides transmission service through facilities located in
Massachusetts and Rhode Island.
Blackstone Valley provides retail electric service in the cities of
Central Falls, Pawtucket, Woonsocket, and four surrounding towns in Rhode
Island.
Eastern Edison provides retail electric service in Brockton and Fall
River, Massachusetts, and 20 other cities and towns in southeastern
Massachusetts.
Newport Electric provides retail electric service in Jamestown,
Middleton, Newport and Portsmouth, Rhode Island.
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D. A general statement briefly describing the facilities owned or
operated for transmission of electric energy in interstate
commerce or the sale of electric energy at wholesale in
interstate commerce.
NEP is engaged in the wholesale sale and transmission of electric
energy in interstate commerce. NEP owns approximately 2,200 miles of
transmission lines that are used to transmit power in New England. As described
above in Section III, NEP owns minority, non-operating interests in certain
nuclear generating facilities and a very small minority interest in one
oil-fired plant.
Narragansett owns approximately 300 miles and Massachusetts Electric
owns approximately 80 miles of transmission facilities that are controlled by
NEP under integrated facilities agreements.
Three other NEES subsidiaries own and operate a total of approximately
139 miles of bi-polar transmission facilities that comprise part of the
transmission intertie between New England and Hydro Quebec: New England Electric
Transmission Corporation, New England Hydro-Transmission Corporation, and New
England Hydro-Transmission Electric Company, Inc.
NEES, as stated above, is a registered holding company and, as such,
is subject to regulation by the SEC. NEES does not directly own any facilities
subject to the Commission's jurisdiction.
Montaup is engaged in the wholesale sale and transmission of electric
energy in interstate commerce. As described above in Section III, it owns
minority, non-operating interests in certain nuclear generating facilities, but
has sold or entered into sales agreements regarding all other generation
facilities it once owned. Besides owning transmission facilities, it leases
transmission facilities from its affiliates.
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Eastern Edison is the direct holding company of Montaup. It owns with
Montaup approximately 4,600 miles of transmission and distribution lines.
Blackstone Valley owns approximately 1,700 miles of transmission and
distribution lines.
Newport Electric owns approximately 800 miles of transmission and
distribution lines.
EUA, as stated above, is a registered holding company and, as such, is
subject to regulation by the SEC. It does not directly own any facilities
subject to the Commission's jurisdiction.
E. Whether the application is for disposition of facilities by
sale, lease, or otherwise, a merger or consolidation of
facilities, or for purchase or acquisition of securities of a
public utility, also a description of the consideration, if
any, and the method of arriving at the amount thereof.
The Merger involves the acquisition by NEES of EUA, and subsequent
mergers of their respective operating companies, as described in Section IV of
the Application, above. A copy of the Merger Agreement is included as Exhibit H
to this Application.
F. A statement of facilities to be disposed of, consolidated, or
merged, giving a description of their present use and of their
proposed use after disposition, consolidation, or merger.
State whether the proposed disposition of facilities or plan
for consolidation or merger includes all the operating
facilities of the parties to the transaction.
The Merger includes all of the operating facilities of Applicants,
including all franchises, permits and operating rights owned by them and their
subsidiaries. Following the Merger, all jurisdictional facilities will be
operated in substantially the same manner as they are currently operated.
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G. A statement (in the form prescribed by the Commission's Uniform
System of Accounts for Public Utilities and Licensees) of the
cost of the facilities involved in the sale, lease, or other
disposition or merger or consolidation. If original cost is not
known, an estimate of original cost based, insofar as possible,
upon records or data of the applicant or its predecessors must be
furnished, together with a full explanation of the manner in
which such estimate has been made, and a description and
statement of the present custody of all existing pertinent data
and records.
See Exhibit C to this Application.
H. A statement as to the effect of the proposed transaction upon any
contract for the purchase, sale, or interchange of electric
energy.
Except as described in this Application and the accompanying Section
205 Filing, the Merger will not have any known effect on the rights, interests
or obligations of the parties to contracts for the purchase, sale, transmission
or interchange of electric energy involving NEES, the NEES Companies, EUA, or
the EUA Companies.
I. A statement as to whether or not any application with respect to
the transaction or any part thereof is required to be filed with
any other Federal or State regulatory body.
The following are the other regulatory approvals or filings that are
contemplated being made and copies are included with this Application in Exhibit
G or will be provided upon filing:
1. NEES and EUA will file an application with the SEC for approval
of the Merger pursuant to PUHCA.
2. Montaup, as holder of minority interests in several nuclear
facilities as described above, will file an application with the
Nuclear Regulatory Commission for approval because the Merger
will transfer these facilities to NEP.
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3. NEES and EUA obtained on April 30, 1999, from the Federal Trade
Commission early termination of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976.
4. NEP and Montaup are filing contemporaneously an application for
approval of consolidation of NEP's and Montaup's transmission
rates, as a rate change under Section 205 of the FPA and are
requesting consolidation of the proceedings. A Section 205 filing
modifying Montaup's CTC will be made if required.
5. Requests for approval of the Merger and approval of a rate plan
have been made with the Massachusetts Department of
Telecommunications & Energy and will shortly be filed with the
Rhode Island Public Utilities Commission.
6. Requests for approval of the Merger will be filed with the
Connecticut Department of Public Utility Control, the Vermont
Department of Public Service and the New Hampshire Public
Utilities Commission, if required.
J. The facts relied upon by applicants to show that the proposed
disposition, merger, or consolidation of facilities or
acquisition of securities will be consistent with the public
interest.
See Section V of this Application, above.
K. A brief statement of franchises held, showing date of expiration
if not perpetual.
The retail distribution affiliates of NEES and EUA have franchises.
The franchises of those companies that are Applicants are listed below.
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Massachusetts Electric Company has non-exclusive franchise rights to
serve in the following cities and towns located in the Commonwealth of
Massachusetts: Adams, Alford, Amesbury, Andover, Athol, Attleboro, Auburn, Ayer,
Barre, Belchertown, Bellingham, Berlin, Beverly, Billerica, Blackstone, Bolton,
Boxford, Brimfield, Brookfield, Charlemont, Charlton, Chelmsford, Cheshire,
Clarksburg, Clinton, Douglas, Dracut, Dudley, Dunstable, East Brookfield, East
Longmeadow, Egremont, Erving, Essex, Everett, Florida, Foxborough, Franklin,
Gardner, Gloucester, Goshen, Grafton, Granby, Great Barrington, Groton,
Hamilton, Hampden, Hancock, Hardwick, Harvard, Haverhill, Hawley, Heath,
Hingham, Holbrook, Holland, Hopedale, Hubbardston, Lancaster, Lawrence,
Leicester, Lenox, Leominster, Lowell, Lynn, Malden, Manchester, Marlborough,
Medford, Melrose, Mendon, Methuen, Milford, Millbury, Millville, Monroe, Monson,
Montery, Mt. Washington, Nahant, Nantucket, New Braintree, Newbury, Newburyport,
New Marlborough, New Salem, North Adams, Northampton, North Andover,
Northborough, Northbridge, North Brookfield, Norton, Oakham, Orange, Oxford,
Palmer, Paxton, Pepperell, Petersham, Phillipston, Plainville, Quincy, Randolph,
Rehoboth, Revere, Rockport, Rowe, Royalston, Rutland, Salem, Salisbury, Saugus,
Seekonk, Sheffield, Shirley, Shutesbury, Southborough, Southbridge, Spencer,
Stockbridge, Sturbridge, Sutton, Swampscott, Tewksbury, Topsfield, Tyngsborough,
Upton, Uxbridge, Wales, Ware, Warren, Warwick, Webster, Wendell, Wenham,
Westborough, West Brookfield, Westford, Westminster, West Newbury, West
Stockbridge, Weymouth, Wilbraham, Williamsburg, Williamstown, Winchendon,
Winthrop, Worcester, Wrentham.
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Narragansett has retail exclusive electric distribution franchises in
the State of Rhode Island, including the cities and towns of Barrington,
Bristol, Charlestown, Coventry, Cranston, East Greenwich, East Providence,
Exeter, Foster, Glocester, Hopkinton, Johnston, Little Compton, Narragansett,
North Kingstown, North Providence, Providence, Richmond, Scituate, Smithfield,
South Kingstown, Tiverton, Warren, Warwick, Westerly, West Greenwich, and West
Warwick.
Eastern Edison has retail franchises in the following communities in
the Commonwealth of Massachusetts: Abington, Avon, Bridgewater, Brockton,
Cohasset, Dighton, East Bridgewater, Easton, Fall River, Halifax, Hanson,
Hanover, Norwell, Pembroke, Rockland, Scituate, Somerset, Stoughton, Swansea,
West Bridgewater, Westport, and Whitman.
Blackstone Valley has retail franchises in the following communities
in the State of Rhode Island: Central Falls, Cumberland, Lincoln, North
Smithfield, Pawtucket, Woonsocket and Burrillville.
Newport Electric has retail franchises in the following communities in
the State of Rhode Island: Jamestown, Middletown, Newport, and Portsmouth.
L. A form of notice suitable for publication in the Federal
Register, which will briefly summarize the facts contained in
the application in such way as to acquaint the public with its
scope and purpose.
A form of notice suitable for publication in the Federal Register is
attached to this Application, both in hard copy form and on diskette.
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VIII. EXHIBITS REQUIRED PURSUANT TO SECTION 33.3 OF THE
COMMISSION'S REGULATIONS
Pursuant to Section 33.3 of the Commission's regulations, the
following Exhibits are submitted, which are attached to and included with this
Application:
Exhibit A. Copies of All Resolutions of Directors.
Exhibit B. Statement of Intercorporate Relationships.
Exhibit C. Statements A and B, FERC Form No. 1.
Exhibit D. Statement of All Known Contingent Liabilities.
Exhibit E. Statement C, FERC Form No. 1.
Exhibit F. Analysis of Retained Earnings.
Exhibit G. Copies of All Applications Filed with Other Federal and
State Regulatory Bodies and Certified Copies of Each
Order Relating Thereto, Where Applicable.
Exhibit H. Copies of All Contracts with Respect to the Merger.
Exhibit I. Map.
IX. REQUEST FOR APPROVAL OF NATIONAL GRID-NEES MERGER
WITH RESPECT TO EUA COMPANIES AND FOR INCORPORATION
BY REFERENCE OF REQUIRED EXPLANATIONS AND EXHIBITS
The NEES Companies currently have pending in Docket No. EC99-49-000 a
request for approval of a merger that will make NEES a subsidiary of National
Grid. If the National Grid-NEES merger is completed before the OpCo Mergers,
Commission approval would be required for the acquisition by National Grid of
the EUA Companies resulting from the National Grid-NEES merger. For
administrative efficiency, Applicants request that such approval be granted in
connection with approval of this Application because the National Grid
transaction satisfies the Commission's merger policy criteria with respect to
the EUA Companies in the same manner as it does with respect to the NEES
Companies.
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As explained in the National Grid-NEES application, National Grid is a
holding company incorporated in England and Wales. It owns all the shares of The
National Grid Company plc, a corporation that is the world's largest
privately-owned independent electric transmission company. The National Grid
Company owns, operates and maintains the high voltage network in England and
Wales, which connects power stations with distribution networks. The National
Grid Company is also responsible for scheduling and dispatching generation to
meet demand second-by-second and manages and controls the software systems to do
so. Additionally, The National Grid Company owns and operates interconnectors
that enable electricity to be transferred between the England and Wales market
and Scotland and France.
The National Grid-NEES application demonstrates that their merger is
in the public interest, satisfying the three requirements for approval
established by the Commission. The same criteria are equally satisfied with
respect to the EUA Companies.
First, as in the case of the NEES Companies, the EUA Companies do not
have facilities or sell products in any common geographic markets with National
Grid and its related companies.64/ Since National Grid and the EUA Companies do
not conduct business in the same geographic markets, there can be no adverse
impact on competition.65/
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64/ Attachment 2 is a declaration from Dr. Kahwaty confirming that the
competition analysis applicable to the NEES Companies and National Grid applies
equally to the EUA Companies.
65/ It should be noted that on April 9, 1999, the Federal Trade Commission
granted the request for early termination of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976 filed by NEES and National
Grid. A copy of that termination notice was filed in Docket No. EC99-49-000 on
April 14, 1999.
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Second, the combination of EUA with NEES in the overall context of a
National Grid acquisition will not increase rates, but instead will serve to
lower costs through improved efficiency and enhanced operations of EUA's
existing operating companies. These savings will be both direct, in terms of
reduced costs for transmission and distribution services, and indirect by
producing improvements in the transmission and distribution network that will in
turn improve the overall operations of the electricity market.
Finally, bringing the EUA Companies into the National Grid-NEES merger
will not adversely affect either federal or state regulation. With respect to
federal regulation, there will be no change in the relationship among the EUA
system of companies, and hence there will be no impact on federal regulation for
transactions among those companies. With respect to the new affiliate
relationships created by the National Grid-NEES merger, the EUA Companies will
make the same commitment as the NEES Companies have done: they commit to abide
by Commission policy with respect to sales of non-power goods and services for
transactions between the EUA Companies and National Grid or its affiliates.66/
With respect to state regulation, the structure of the EUA Companies will not be
changed by the National Grid-NEES merger. Each state commission that currently
has authority over the EUA operating companies will continue to have authority
over the rates, services and operations of those companies.
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66/ This separate commitment is applicable only for the interim period until
the OpCo Mergers are completed, since at that point, only NEES Companies
survive.
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Because (i) the analysis supporting approval of the National Grid-NEES
merger is exactly the same for the EUA Companies as it is for the NEES
Companies, and (ii) the specific information regarding National Grid that is not
included in this Application is included in the National Grid-NEES application
in Docket No. EC99-49, and (iii) administrative efficiency would be served by
avoiding the duplicative filing in this proceeding of the same materials that
are already included in that existing docket, Applicants request that the
Commission incorporate by reference all materials in Docket No. EC99-49 that are
needed to support approval here of the acquisition of the EUA Companies by
National Grid.
X. PROCEDURAL MATTERS
The facts and analysis provided in this Application demonstrate that
the Merger will not have an adverse effect on competition, rates or regulation.
It easily satisfies all requirements of Section 203 of the FPA, as implemented
by Commission regulation and policy, and thus is in the public interest.
Consequently, Applicants, NEES and EUA, as well as National Grid, respectfully
request, on the basis of the facts and analysis set forth in this Application
both directly and incorporated by reference, that by July 31, 1999, the
Commission act without hearing (i) to approve the Merger and, (ii) if required,
grant approval of the acquisition of the EUA Companies by National Grid.
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XI. CONCLUSION
For the foregoing reasons, Applicants, NEES and EUA respectfully
request that the Commission: (1) approve both the HoldCo Merger and the OpCo
Mergers under Section 203 of the FPA, (2) approve the acquisition by National
Grid of the EUA Companies (to the extent required), (3) grant any other
authorizations, approvals or waivers necessary or appropriate to allow this
Application to be accepted for filing and granted; and (4) issue such approvals,
authorizations and waivers expeditiously, without condition, modification or
trial-type hearing.
Respectfully submitted,
/s/ Scott P. Klurfeld /s/ David A. Fazzone
- ------------------------------------ ----------------------------------------
Edward Berlin, Esq. David A. Fazzone, Esq. of
Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and
Scott P. Klurfeld, Esq. McDermott, Will & Emery
Swidler Berlin Shereff Friedman, LLP 28 State Street
3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775
Washington, D.C. 20007-5116 (617) 535-4000
(202) 424-7500 Attorney for Montaup Electric Company
and Affiliated Applicants
Thomas G. Robinson, Esq.
New England Power Company
25 Research Drive
Westborough, MA 01582
(508) 389-2877
Attorneys for New England Power
Company and Affiliated Applicants
May 5, 1999
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[FORM OF NOTICE]
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70-000
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
NOTICE OF FILING
Take notice that on May 5, 1999, New England Power Company ("NEP") and
its affiliates holding jurisdictional assets (Massachusetts Electric Company,
The Narragansett Electric Company, New England Electric Transmission
Corporation, New England Hydro-Transmission Corporation, New England
Hydro-Transmission Electric Company, Inc., and AllEnergy Marketing Company,
L.L.C.) (collectively, the "NEES Companies"), Montaup Electric Company and its
affiliates holding jurisdictional assets (Blackstone Valley Electric Company,
Eastern Edison Company, Newport Electric Corporation) (collectively, the "EUA
Companies"), and Research Drive LLC submitted for filing an application under
Section 203 of the Federal Power Act (16 U.S.C. ss. 824b) and Part 33 of the
Commission's Regulations (18 C.F.R. ss. 33.1 et seq. (1998)) seeking the
Commission's approval and related authorizations to effectuate a merger, the
result of which would be to merge New England Electric System ("NEES"), the
parent company of the NEES Companies, with the Eastern Utilities Associates
("EUA"), the parent company of the EUA Companies. Through the Merger, EUA will
become a wholly-owned subsidiary of NEES, and will subsequently be consolidated
into NEES. In addition, the Application seeks the Commission's approval and
authorization for the subsequent mergers and consolidations of the complementary
operating companies of the two systems that hold jurisdictional assets. Finally,
the Application requests approval, if required, of the acquisition by The
National Grid Group plc ("National Grid") of the EUA Companies resulting from
<PAGE>
the proposed merger of National Grid and NEES, approval of which has been sought
in Docket No. EC99-49-000.
The Application states that it (i) includes all the information and
exhibits required by Part 33 of the Commission's regulations and the
Commission's Merger Policy Statement with respect to the Merger; (ii)
incorporates by reference any additional materials required with respect to the
acquisition by National Grid of the EUA Companies; and (iii) easily satisfies
the criteria set forth in the Commission's Merger Policy Statement. The
Application requests that the Commission grant whatever waivers or
authorizations are needed and grant approval without condition, modification or
an evidentiary, trial-type hearing. The Application states that the parties are
seeking to close the Merger expeditiously and thus the Applicants have requested
Commission approval by July 31, 1999.
The Applicants have served copies of the filing on the state
commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island and
Vermont.
Any person desiring to be heard or to protest said application should
file a motion to intervene or protest with the Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426 in accordance with
Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 C.F.R.
385.211 and 18 C.F.R. 385.214). All such motions or protests should be filed on
or before . Protests will be considered by the Commission in determining the
appropriate action to be taken, but will not serve to make the protestants
parties to the proceeding. Any person wishing to become a party must file a
motion to intervene. Copies of this filing are on file with the Commission and
are available for public inspection.
-2-
<PAGE>
Attachment 1
[LECG Logo]
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-_____
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
Declaration of Henry J. Kahwaty
I, Henry J. Kahwaty, declare:
I. Introduction.
1. My name is Henry J. Kahwaty. I am a Senior Managing Economist with LECG
(formerly Law & Economics Consulting Group, Inc.). LECG is a firm providing
management consulting and expert analysis in the areas of economics,
finance, and accounting. My business address is 1600 M Street, N.W., Suite
700, Washington, D.C. 20036.
2. I received my Ph.D. in Economics from the University of Pennsylvania in
1991. My fields of specialization include industrial organization and
<PAGE>
public economics. Industrial organization involves the study of competition
and regulation in individual markets. Prior to joining LECG, I worked for
nearly four years as an economist for the Antitrust Division of the U.S.
Department of Justice. I have analyzed the competitive implications of
numerous mergers, both during my employment with the Antitrust Division and
with LECG. I have worked on competition issues in electricity,
telecommunications, and other network industries, and I have broad
experience in applied microeconomic analysis. A copy of my curriculum vitae
is provided as Exhibit HJK-1.
3. I have been asked by counsel for New England Power Company ("New England
Power") and Montaup Electric Company ("Montaup") to consider the
competitive implications of the proposed acquisition of Eastern Utilities
Associates ("EUA") by New England Electric System ("NEES").1 This
Declaration summarizes my analysis of the acquisition.
4. I conclude that this acquisition will not result in any reduction in
competition because NEES, EUA, and their affiliates have divested nearly
all of their generation facilities or entitlements to others and have
exited the generation business as a part of the industry restructuring
efforts of several states and the Federal Energy Regulatory Commission
("FERC" or "Commission"). While both systems continue to hold minor
entitlements in generation assets, their shares of generation are de
minimus, and both are committed to divesting their small remaining
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1 New England Power is a subsidiary of NEES; Montaup is a subsidiary of EUA.
2
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entitlements. Furthermore, the merged company will not have
controlling interests in any generation facility. As a result, the
merged company will not be able to withhold supply in an effort to
increase prices. In addition, there is no competition between NEES and
EUA affiliates for the provision of transmission services.
Transmission services will continue to be available under the open
access tariffs of NEPOOL and the merged company. Finally, the
transaction will not result in harm to competition arising from
vertical effects. Both systems supply transmission and distribution
services at regulated rates under open access tariffs, and neither
controls other inputs, such as fuel supplies or equipment, necessary
for the generation or delivery of electricity. Thus, the proposed
acquisition of EUA by NEES will not result in harm to competition.
II. Background.
5. NEES is a holding company whose affiliates own and operate electric
transmission and distribution assets in New England. In particular, NEES
subsidiary New England Power owns transmission assets located in
Massachusetts, New Hampshire, and Vermont. In addition, New England Power
operates transmission facilities in Rhode Island and Massachusetts through
integrated transmission agreements with its affiliates, The Narragansett
Electric Company and Massachusetts Electric Company. Other NEES affiliates
own and operate transmission facilities interconnecting New England and
3
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Quebec.2 The NEES distribution companies include Massachusetts Electric
Company, Nantucket Electric Company, The Narragansett Electric Company, and
Granite State Electric Company. Massachusetts Electric Company and
Nantucket Electric Company provide distribution service in Massachusetts;
The Narragansett Electric Company provides distribution service in Rhode
Island; and Granite State Electric Company provides distribution service in
New Hampshire. NEES also owns several unregulated companies that market
energy or provide other services. These companies operate primarily in the
northeastern United States. As a result, virtually all of the NEES
companies' revenues are derived from services provided primarily in the
states of Massachusetts, Rhode Island, and New Hampshire.3
6. Pursuant to electric utility restructuring legislation enacted in Rhode
Island, Massachusetts, and New Hampshire and settlement agreements approved
by state regulators and the FERC, New England Power recently completed a
divestiture of its fossil and hydroelectric generation assets and its power
purchase contracts to USGen New England, Inc. This divestiture was
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2 These affiliates include New England Electric Transmission Corporation,
New England Hydro-Transmission Corporation, and New England Hydro-
Transmission Electric Company, Inc.
3 Revenues from activities outside the northeastern United States are
generated by NEES subsidiary NEES Global, Inc. This subsidiary performs
certain consulting services within and outside the United States. In
addition, NEES subsidiary AllEnergy recently purchased Griffith Consumers
Company, a distributor of residential and commercial heating oil in
Washington, D.C., and in parts of Maryland, Delaware, Virginia, and West
Virginia.
4
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finalized on September 1, 1998. Prior to divestiture, New England Power
owned approximately 5,450 MW of generation capacity, including fossil,
hydroelectric, nuclear, and purchased power contracts. All of its
generation capacity was located in New England. New England Power divested
over 5,000 MW of this capacity, including the sale of its ownership stakes
in 18 power plants and the assignment or transfer of its entitlements under
23 power contracts, to USGen New England. As a result, New England Power
retained only approximately 400 MW of generation capacity. This capacity
includes minority interests in three operating nuclear facilities and one
fossil generation facility.
o Millstone 3. New England Power owns 12.21 percent of the Millstone 3
nuclear generation station. This represents a generation capacity of
139 MW.4
o Seabrook 1. New England Power owns 9.96 percent of the Seabrook 1
nuclear generation station. This represents a generation capacity of
116 MW.5
o Vermont Yankee. New England Power has a net entitlement to 17.98
percent of the Vermont Yankee nuclear generation station. This
represents a generation capacity of 90 MW.6
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4 NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission
1997-2006 ("1997 CELT Report"), April 1, 1997 at 18.
5 NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission
1998-2007 ("1998 CELT Report"), April 1, 1998 at 19.
6 This is New England Power's share of Vermont Yankee's summer capability
rating. New England Power's share of this facility's winter capability
rating is 95 MW. 1998 CELT Report at 19. New England Power owns 20 percent
of Vermont Yankee, but it has resold a portion to a group of municipals.
5
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o Wyman 4. New England Power owns 9.27 percent of the Wyman 4 oil-fired
steam turbine generating station. This represents a generation
capacity of 57 MW.7
7. EUA is a holding company whose affiliates own and operate electric
transmission and distribution assets in Massachusetts and Rhode Island. In
particular, EUA subsidiary Montaup owns transmission assets in
Massachusetts and leases transmission facilities from affiliates in both
Massachusetts and Rhode Island. The EUA distribution companies include
Eastern Edison Company, Blackstone Valley Electric Company, and Newport
Electric Corporation. Eastern Edison Company provides distribution service
in Massachusetts, and both Blackstone Valley Electric Company and Newport
Electric Corporation provide distribution service in Rhode Island. The EUA
distribution companies do not provide transmission services. EUA also owns
several unregulated companies active in energy-related businesses,
including the energy management company, Cogenex Corporation.
8. As with New England Power, Montaup has sold or entered into agreements to
sell nearly all of its generation assets to other companies pursuant to
electric utility restructuring legislation and settlement agreements
approved by regulators in Rhode Island, Massachusetts, and at the FERC.
Prior to its divestitures, Montaup owned or held equity interest in
approximately 570 MW of generation capacity, all in New England. It also
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7 1998 CELT Report at 19.
6
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held power purchase entitlements in an additional 500 MW. Montaup, however,
recently has sold or entered into agreements to sell its fossil and
hydroelectric generation capacity. It has also signed agreements for the
transfer of power purchase contracts and for a buyout of its 11 percent
power entitlement from the Pilgrim nuclear generation station. Overall,
Montaup has sold, or agreed to sell or transfer, assets and rights to
purchase power entitlements to Constellation Power Source (an affiliate of
Baltimore Gas and Electric), NRG Energy (an affiliate of Northern State
Power), FPL Group, BayCorp Holdings (an affiliate of Great Bay Power),
Southern Energy (an affiliate of Southern Company), TransCanada Power
Marketing, and others.8 Montaup's remaining generation resources are
minority shares in three nuclear generating stations including:
o Millstone 3. Montaup owns 4.01 percent of the Millstone 3 nuclear
generation station. This represents a generation capacity of 46 MW.9
o Vermont Yankee. Montaup has a net entitlement to 2.25 percent of the
Vermont Yankee nuclear generation station. This represents a
generation capacity of 11 MW.10
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8 Montaup's sales of generation assets and entitlements to Southern Energy,
TransCanada Power Marketing, and NRG Energy, and Newport Electric
Corporation's sale to Wabash Power Equipment, have been completed. The
remaining asset and entitlement sales or transfers are pending.
9 1998 CELT Report at 15.
10 This is Montaup's share of Vermont Yankee's summer capability rating.
Montaup's share of this facility's winter capability rating is 12 MW. 1998
CELT Report at 15. Montaup owns 2.5 percent of Vermont Yankee, but it has
resold a portion to a group of municipals.
7
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o Pilgrim. Montaup has a purchased power agreement with Entergy giving
Montaup an entitlement to 11 percent of the output of this nuclear
station in 1999. This represents a generation capacity of 74 MW.11
This entitlement declines over time and ends after 2004.12
These resources represent a total of approximately 131 MW of generation
capacity currently, declining to 57 MW after 2004.
9. Industry restructuring in New England has involved the unbundling of
generation, transmission, and distribution, and the advent of the retail
marketing of electricity. Transmission and distribution remain regulated
activities, and competition is being introduced in generation and retail
supply. An independent system operator, ISO New England, was established on
July 1, 1997.13 ISO New England is responsible for managing the New England
region's electric bulk power generation and transmission systems and
administering the region's open access transmission tariff. The region's
open access transmission tariff includes a combination of "license plate"
and "postage stamp" pricing. This allows power to be transmitted from any
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11 1998 CELT Report at 15.
12 Montaup presently has a life-of-unit purchase power agreement with Boston
Edison Company covering 11 percent of the energy generated by the Pilgrim
station. Boston Edison Company is selling Pilgrim to Entergy Nuclear
Generating Company, and Montaup has an agreement with Entergy Nuclear
Generating to purchase power from this unit. The purchase power agreement
entitles Montaup to 11 percent of the output of the Pilgrim station in
1999. This entitlement declines to 8.8 percent in 2002, 5.5 percent in 2003
and 2004, and ends thereafter.
13 The FERC approved the creation of the ISO New England in 79 FERC paragraph
61,374 (1997), reh'g denied, 85 FERC paragraph 61,242 (1998).
8
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location in New England to load on a transmission provider's system at
uniform, flat rates that vary among the transmission providers. The ISO
also operates the wholesale electric power market for New England and
settles "spot" transactions. In addition, it tracks bilateral contracts
between market participants.
10. Access to New England's transmission system has been opened to all
competitors in electric generation via the region's open access
transmission tariff and the open access transmission tariffs of the
individual utilities owning transmission assets. Participants who desire to
reserve transmission services for the supply of electricity into the New
England region, or through the New England region, can do so through ISO
New England. An Internet-based Open Access Same Time Information System
("OASIS") has been designed to provide participants with real-time
information about the transmission system. Participants can use the OASIS
to reserve transmission services. NEPOOL's rates for transmission services
are derived from the actual costs of building and maintaining transmission
facilities and are reviewed and approved by the FERC.
III. The Analysis of Market Power.
11. Market power is the ability profitably to increase and maintain prices
above competitive levels for a significant period of time. My analysis of
9
<PAGE>
the proposed acquisition of EUA by NEES addresses whether this transaction
will create or enhance market power or otherwise facilitate its exercise.
12. The analysis of the competitive implications of mergers typically has
several parts. The first part includes the definition of the relevant
market or markets, the identification of the participants in these markets,
and the calculation of market shares and market concentration. Market
concentration is a measure that reflects that extent to which a few firms
account for market sales or capacity.14 Markets with many firms and low
levels of concentration are generally presumed to be competitive. Markets
with fewer firms and high levels of concentration require more detailed
analysis to determine whether significant market power exists. Thus, market
concentration is used to distinguish between markets where there are enough
participants to result in competitive outcomes and markets where an
analysis of other structural market features is required to evaluate the
prospects for a successful exercise of market power.
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14 The Herfindahl-Hirschman Index ("HHI") is a commonly used measure of market
concentration. This index is calculated by summing the squares of the
market shares of the firms in the market. For example, a market with three
firms with market shares of 35 percent, 40 percent, and 25 percent would
have an HHI value of 35(squared) + 40(squared) + 25 (squared) or 3,450.
Markets with a large number of firms, each with a small market share, have
HHI values near zero. Markets served by only one provider have an HHI of
1002 or 10,000.
10
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13. In its Policy Statement15 on mergers, the FERC adopted the market
concentration screening criteria set out in the Horizontal Merger
Guidelines of the U.S. Department of Justice and the Federal Trade
Commission.16 (These screens are described in more detail in the Appendix
to this Declaration.) When a merger fails to satisfy the safe harbor
concentration-based screening criteria, the analysis then considers the
competitive effects likely to result from the proposed transaction.
Concentration screens consider only market structure; competition analysis
moves past structure to consider both conduct and the effect of that
conduct on market prices.
14. After analyzing the likely competitive effects, if any, the next step in
merger analysis involves the study of the barriers to entry facing new
suppliers and the barriers to expansion by existing suppliers. In the
absence of significant barriers to entry, existing firms in an industry are
not likely to be able to exert substantial market power because any attempt
to raise prices above competitive levels would attract the entry of new
providers. Thus, entry can deter or counteract an exercise of market power.
On the other hand, where barriers to entry are substantial, new providers
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15 Inquiry Concerning the Commission's Merger Policy Under the Federal Power
Act: Policy Statement, ("Policy Statement"), Order No. 592, 77 FERC 61,263
(1996).
16 The Horizontal Merger Guidelines were issued April 2, 1992 and revised
April 8, 1997. http://www.usdoj.gov/atr/public/guidelines/horiz_book/
hmg1.html.
11
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would find it difficult or impossible to enter the market in response to an
attempt by the incumbent(s) to raise prices above competitive levels.
15. The final step in the analysis is to ask whether an otherwise
anticompetitive merger may nevertheless be socially beneficial due to the
potential for the merger to result in cost reductions or other efficiencies
that would not otherwise be achievable. Efficiencies from economies of
scale, the exploitation of complementary assets, expanded applications of
research and development, best-practice cost reductions, and others are
pro-competitive. The purpose of merger analysis is to consider whether the
potential harm to competition from the structural change induced by a
merger outweighs any resulting efficiencies from the merger. Regulators
should permit mergers when anticipated benefits exceed potential social
costs.17 In the next two sections, I discuss whether the proposed
acquisition of EUA by NEES will result in harm to competition in the
generation and transmission of electricity.
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17 For example, although not the case there, the antitrust enforcement
agencies will allow an otherwise anticompetitive merger or acquisition to
proceed unchallenged if the imminent failure of one of the merging parties
would cause the assets of that firm to exit the relevant market. Horizontal
Merger Guidelines at section 5.
12
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IV. The Proposed Merger Will Not Harm Electric Generation Competition
16. The proposed acquisition of EUA by NEES will not result in harm to
competition in the wholesale generation market. New England Power and
Montaup own only a de minimus share of the generation in New England. In
addition, both are committed to selling their few remaining generation
resources, so their ownership of generation is likely only to be temporary.
Furthermore, as the merged company will have only minority interests in
generation facilities, it will control neither the operations nor the
pricing of the NEPOOL market products from these facilities. In particular,
due to its lack of operational control, the merged company will not have
the ability to exercise market power by restricting output from these
facilities. In addition, the New England market recently has experienced
both entry by new merchant plants and the expansion of existing plants.
This demonstrates that barriers to entry are low and reinforces my
conclusion that the merged company will not possess generation market
power. My analysis bypasses the definition of relevant markets and the
consideration of market concentration screens and instead directly
considers competitive effects analysis. However, in the Appendix, I
consider recent screening analyses for New England prepared by others. When
modified to represent the NEES/EUA transaction, the resulting increases in
HHIs are well below the FERC's screening thresholds, further supporting my
conclusion that the acquisition of EUA by NEES will not harm competition in
wholesale markets.
13
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17. I assume for the purposes of my analysis that the relevant geographic
market is NEPOOL. This is reasonable because the pool-wide transmission
tariff in New England permits the delivery of power from anywhere in the
region covered by ISO New England to a given location for one price and
because, under ordinary conditions, NEPOOL dispatch is generally
unconstrained by transmission limitations. In the absence of transmission
limitations, NEPOOL's transmission pricing allows generation assets located
across the region to compete with each other without having cost advantages
or disadvantages caused by different transmission fees. This geographic
market definition is consistent with the hypothetical monopolist paradigm
of the Horizontal Merger Guidelines as it likely represents the most narrow
geographic market relevant to the analysis of this merger. Basing the
analysis on a larger relevant geographic market would only serve to reduce
the market shares of NEES and EUA insomuch as all their generation
resources are located with the NEPOOL geographic area.
18. Post-merger, NEES affiliates will own only a de minimus share of generation
in New England. Assuming that all of the generation asset sales and
purchase power transfers announced by EUA and its affiliates are
consummated, the post-merger generation portfolio of NEES and its
affiliates will consist solely of minority shares in five power plants
14
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resulting in generation resource entitlements totaling 533 MW.18 The merged
company's shares of these five facilities are summarized in Exhibit HJK-2.
19. There is over 24,200 MW of generation capacity in New England.19 As a
result, the merged firm's post-merger entitlement of 533 MW represents only
about two percent of all generation in New England.
20. Furthermore, USGen New England has an option to purchase 98 percent of New
England Power's nuclear plant capacity and energy output. This option lasts
as long as New England Power retains its interests in these facilities and
as long as USGen New England is obligated to supply wholesale standard
offer service to NEES's distribution company subsidiaries.20 Any sales to
USGen New England are made at the discretion of USGen New England and are
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18 This will fall to 455 MW after 2004 when Montaup's entitlements in the
Pilgrim station expire as contemplated in its pending agreement with
Entergy Nuclear Generation. See Footnote 12 above.
19 NEPOOL Forecast Report of Capacity, Energy, Loads and Transmission
1999-2008 ("1999 CELT Report"), April 1, 1999 at 5.
20 See Wholesale Sales Agreement between New England Power Company and USGen
Acquisition Corporation, August 5, 1997 ("Wholesale Sales Agreement") at
Article 3 section 3.1. All former retail customers of the NEES and EUA
distribution companies in Massachusetts and Rhode Island have an option to
take service from the distribution company under a standard contract at
regulated rates as opposed to taking service from competitive providers at
prices prevailing in the market. Standard offer rates increase over time to
encourage customers to move from regulated service to market alternatives.
The NEES and EUA distribution companies must make wholesale purchases to
meet their standard offer service obligations. For a description of the
standard offer, see, for example, Restructuring Settlement Agreement, Massa
chusetts Department of Public Utilities Docket Nos. 96-100 and 96-25
("Restructuring Settlement Agreement"), at section I.B.5,
http://www.nees.com/news/settlmnt.htm.
15
<PAGE>
priced at either spot market rates or regulated rates, depending on the use
of the electricity.21 USGen New England has exercised its option and has
taken most of the output from New England Power's nuclear entitlements
since August 1998. This further limits the amount of capacity and energy
under the control of New England Power.
21. The merged company's ownership of these assets will only be temporary,
however. New England Power and Montaup have each committed in their
Restructuring Agreements with Massachusetts and Rhode Island to endeavor to
divest all of their generation resources, including their nuclear
entitlements, and are presently attempting to do so.22 Vermont Yankee
Nuclear Power Corporation, with both New England Power's and Montaup's
support, has signed a letter of intent to sell the Vermont Yankee plant to
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21 The prices for sales to USGen New England are spot market prices for
energy, installed capacity, and operable capacity, except for the part of
the nuclear output used to provide wholesale standard offer service to NEES
distribution companies. Sales to USGen New England for wholesale standard
offer service are priced at the lower of spot market rates and rates just
below the wholesale standard offer price. See Wholesale Sales Agreement at
Article 5 section 5.1.
22 See, for example, Restructuring Settlement Agreement at section V.D.1.
16
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a third party. In addition, New England Power is currently in discussions
with a party interested in purchasing its share of Wyman 4. Furthermore,
New England Power is obligated to file a plan for divesting its remaining
generation with regulators in New Hampshire by July 1, 1999. As a result,
the ownership of the generation resources summarized in Exhibit HJK-2 by
New England Power, Montaup, or their affiliates is likely to be temporary.
22. Neither New England Power nor Montaup maintains operational control over
any generation facility. The firm's largest share in a generation resource
post-merger is approximately 20 percent, and its shares of both Seabrook 1
and Wyman 4 are below 10 percent. In addition to lacking operational
control, all but one of the generating stations in which the merged company
will have entitlements are non-dispatchable nuclear units. As a result, the
merged firm will not be able unilaterally to restrict output in an attempt
to increase prices.
23. Due to the very small generation entitlements of NEES and EUA affiliates in
New England, their commitment to divest these remaining entitlements, and
their lack of operational control over their generation resources, I
conclude that the proposed acquisition of EUA by NEES will not harm
competition in electric generation in New England. In particular, the
proposed acquisition will not enable the parties profitably to restrict
output or increase prices.
17
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24. New participants have joined the New England market recently by purchasing
divested generation resources. Exhibit HJK-3 provides information on
several of these firms. Purchasers of generation resources in New England
include affiliates of Baltimore Gas and Electric, FPL Group, Northern
States Power, PG&E, Sithe Energies, Southern Company, and Wisconsin Energy.
25. Many of these new market participants have announced the construction of
new generation facilities or the expansion of existing facilities. Examples
include:
o PG&E Corp. PG&E subsidiary Millennium Power Partners is constructing
the Millennium Power natural gas-fueled plant in Charlton,
Massachusetts. This facility will have a capacity of 360 MW.23 It is
expected to begin operation in the summer of 2000. PG&E affiliates are
also developing additional facilities in New England with a total of
over 2,000 MW of capacity.24
o Sithe Energies. Sithe Energy subsidiary Sithe New England has
announced plans to build 1,500 MW of new gas-fired units at the Mystic
site it acquired from Boston Edison. It has also announced plans to
build an additional 750 MW at Boston Edison's former Edgar site.25 In
addition, Sithe New England is developing the Medway and Everett
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23 USGen Affiliate Begins Construction of Millennium Power Plant," U.S.
Generating Company press release, June 24, 1998, http://www.usgen.com/
news/pr062498.html.
24 "U.S. Generating Co. Completes Acquisition of New England Electric's
Generating Facilities," U.S. Generating Company press release, September 1,
1998, http://www.usgen.com/news/pr090198.html.
25 "Sithe New England Construction Plans Include Building 2,250 MW of New
Plant," Northeast Power Report, July 17, 1998, at 10.
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gas-fired stations in Massachusetts. Both of these facilities will
have a capacity of 1,500 MW and are expected to be in service in
2001.26
o Southern Company. Southern Company affiliate Southern Energy has
announced plans to build a new 525 MW, gas-fired generating unit at
the site of the Canal generating station it recently acquired from
Commonwealth Energy and EUA.27 In addition, Southern Energy has
announced plans to upgrade the Kendall station it acquired from
Commonwealth Energy. The upgrade will include environmental
improvements in addition to increasing the plant's capacity from 110
MW to 270 MW.28
Additional merchant plant developers, such as Duke Energy Power Services,
have facilities in New England which are either under construction or have
regulatory approval.29
26. These examples demonstrate that actual entry into the generation business
by a number of firms is occurring in New England. New market participants
are not only purchasing existing generation facilities but are also
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26 "Merchant Plant Development Booms But Abandoned Projects Likely," The
Energy Report, February 1, 1999.
27 "SEI to Build New 525 MW Plant at Canal Site It Bought From
ComElectric/EUA," Northeast Power Report, January 15, 1999, at 1.
28 "Southern Energy Plans Environmental, Efficiency Upgrades for Kendall
Square Station Power Plant," Southern Company press release, August 19,
1998, http://newsinfo.southernco.com/article.asp?id=522&co=southernco.
29 1998 CELT Report at 31.
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increasing the capacity of existing plants, adding new units at existing
generation sites, and developing merchant plants at new locations. This
track record of entry and expansion shows that plant sites, fuel supplies,
and other inputs are available for new generation facilities. As a result,
gaining access to inputs is not a barrier to the development of new
facilities or the entry of new competitors. The actual, recent market
experience with entry and expansion by wholesale electric market
participants in New England further supports my conclusion that the
combination of the generation entitlements of affiliates of NEES and EUA
will not result in an anticompetitive reduction in electricity output or an
increase in wholesale electric prices.
27. In order to confirm my conclusions, I have analyzed several other market
power or "Appendix A" studies related to New England that have been filed
with the FERC in other dockets in the past few years. My analysis involved
considering the implications of the NEES/EUA transaction on these other
studies.
28. For example, in February 1999, BEC Energy and Commonwealth Energy Systems
filed an analysis of their proposed merger prepared by John Reed (Docket
No. EC99-33-000). Adjusting Mr. Reed's analysis to reflect recent
divestitures by Montaup and New England Power yields increases in HHIs
which are far below the FERC's merger screening thresholds. As discussed in
more detail in the Appendix, the HHI values that result for the seven
markets analyzed by Mr. Reed are in the moderately concentrated range, and
the increases in the HHIs due to the NEES/EUA transaction are all very
20
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small. In particular, the increases in the HHIs are all under six (6).
Under the FERC's Policy Statement on mergers and the Horizontal Merger
Guidelines, such small HHI increases indicate that the acquisition of EUA
by NEES is presumed unlikely to raise significant competitive concerns.
29. In September 1997, New England Power, the Narragansett Electric Company,
and USGen New England filed a market power analysis related to the
divestiture by New England Power and The Narragansett Electric Company of
substantially all of their non-nuclear generation resources to USGen New
England. This analysis, filed in Docket Nos. EC98-1-000 and ER98-6-000, was
prepared by Joe D. Pace. Dr. Pace considered a variety of total capacity
and total economic capacity HHIs in his analysis. After adjusting Dr.
Pace's analysis to reflect recent divestitures by EUA affiliates, I
calculated the increases in the total installed capacity and total economic
capacity HHIs due to the NEES/EUA transaction. These calculations yield
increases in total installed capacity and total economic capacity HHIs that
fall well within the FERC's safe harbor screens. In particular, the
increases in the total installed capacity HHIs are less than two (2), and
the increases in the total economic capacity HHIs are less than nine (9).
These calculations are discussed in more detail in the Appendix.
30. In February 1997, the NEPOOL Executive committee submitted a market power
analysis related to the restructuring of NEPOOL and the receipt of
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market-based rates by NEPOOL members. This analysis was filed in Docket
Nos. OA97-237-000 and ER97-1079-000 and was prepared by William
Hieronymous. His analysis studied seven relevant products under the
Restated NEPOOL Agreement: (1) Installed Capability, (2) Energy, (3)
Ten-Minute Spinning Reserve, (4) Ten-Minute Non-Spinning Reserve, (5)
30-Minute Operating Reserve, (6) Automatic Generation Control, and (7)
Operable Capability. Because Montaup's only remaining generation
entitlements will be in nuclear plants, its shares of generation resources
capable of supplying ten-minute spinning reserves, ten-minute non-spinning
reserves, 30-minute operating reserves, and automatic generation control
are all zero. Hence the HHI increases due to the NEES/EUA transaction are
zero for these products. To calculate increases in HHIs for the remaining
products, I adjusted NEES and EUA resources to reflect recent divestitures
by their affiliates. I then calculated increases in installed capability
and energy HHIs due to the NEES/EUA transaction for a range of time
periods. The increases in the total installed capability HHIs were all less
than two (2), and the increases in the energy HHI were all less than eight
(8). These HHI increases fall well within the FERC's safe harbor screens.
These calculations are discussed in more detail in the Appendix.
V. The Proposed Merger Will Not Harm Electric Transmission Competition.
31. Both NEES and EUA provide transmission services in New England through
affiliates. The merger of NEES and EUA, however, will not result in a
reduction in competition for the provision of transmission services.
22
<PAGE>
32. Individual entities in NEPOOL provide transmission services using both pool
transmission facilities ("PTF") and non-PTF facilities. Service using PTF
facilities is available using NEPOOL's open access transmission tariff.
Under the NEPOOL tariff, transmission services for delivery between
entities within NEPOOL are provided at a combination of license plate and
postage stamp rates. The use of a NEPOOL-wide rate is being phased in over
several years, and both firms have network service rates in their own open
access transmission tariffs that also may be used to provide service during
the phase-in of NEPOOL's rates. NEPOOL-wide rates that combine license
plate and postage stamp pricing will continue to be available after the
consummation of the NEES/EUA merger.
33. NEES and EUA affiliates do not "compete" for the sale of transmission
services using either PTF or other facilities. The EUA system is
interconnected with three transmission dependent utilities: Pascoag,
Middleboro, and Taunton. None of these entities is interconnected with the
NEES system. Consequently, these three entities cannot choose between
taking service from NEES and EUA. Neither NEES nor EUA has offered
discounts under its tariffs to win transmission customers or for any other
reason. As a result, the proposed merger will not result in a restriction
in the production of transmission services or otherwise reduce competition
in these services.
23
<PAGE>
VI. The Proposed Merger Will Not Harm Competition Due to Vertical Effects.
34. As a result of industry restructuring and the divestiture of generation,
both NEES and EUA have exited the generation business. Their operating
companies provide retail access to market suppliers under filed,
non-discriminatory transmission and distribution tariffs. These tariffs
include regulated rates and standards of conduct established by this
Commission and the relevant state commissions. All retail customers
serviced by the NEES and EUA operating companies have the right to purchase
electricity supplies from their provider of choice. Consequently, the NEES
and EUA companies no longer operate as vertically integrated concerns, and
their merger will not result in harm to competition due to vertical
effects.
35. Other than transmission and distribution services, neither NEES nor its
subsidiaries presently provides fuel supplies, fuel transportation
services, equipment, or other inputs used in the production or delivery of
electric products or services to EUA, its affiliates, or other utilities in
New England.30 As part of the NEES companies' divestiture of their
generating business, NEES affiliate New England Energy Incorporated sold
its oil and gas properties in February 1998.31 Similarly, the EUA companies
do not supply inputs (other than transmission and distribution services)
- ---------------
30 AllEnergy may occasionally make sales of natural gas at wholesale to other
utilities as part of its retail marketing business. These sales represent
an insignificant portion of the natural gas sales in New England.
31 New England Energy Inc. had been involved in domestic oil and gas explora
tion, development, and production.
24
<PAGE>
used in the production or delivery of electricity to NEES, its affiliates,
or others in New England. Consequently, this transaction will not create or
enhance incentives for the NEES or EUA companies adversely to affect prices
and output in downstream electricity markets. In particular, this
transaction will not create incentives for NEES and EUA affiliates to
restrict non-affiliate access to the transmission or distribution systems
of the NEES and EUA companies.
36. Furthermore, NEES and EUA affiliates provide transmission services to
electric generators and power marketers through FERC-approved open access
tariffs and will continue to do so after NEES completes its acquisition of
EUA. Similarly, NEES and EUA affiliates provide distribution services
through state-regulated distribution rates paid by the customer, not the
supplier.32 As a result, the acquisition will not affect the ability of
NEES or EUA affiliates to restrict access to their transmission or
distribution assets. I conclude that this transaction is not a vertical
merger and will not impact the incentive or ability of the NEES and EUA
companies adversely to affect competition through vertical effects such as
foreclosure, facilitating coordination, or regulatory evasion.33
- ---------------
32 Although NEES, through AllEnergy, markets electricity and natural gas at
retail, delivery service in the service territories of NEES and EUA is at
regulated rates and preferential service to affiliated marketers is
expressly prohibited.
33 My analysis is consistent with the FERC's current thinking on vertical
merger analysis. See Revised Filing Requirements Under part 33 of the
Commission's Regulations, April 16, 1998, Docket No. RM98-4-000, slip op.
at 46-50.
25
<PAGE>
VII. The Proposed Acquisition Will Generate Significant Efficiencies.
37. The acquisition of EUA by NEES is likely to result in significant
efficiencies. Following the merger of the NEES and EUA holding companies,
the parties are planning to merge related affiliates. For example, the
parties will combine their principal transmission affiliates, New England
Power and Montaup. Similarly, the Massachusetts distribution companies
(Massachusetts Electric Company and Eastern Edison Company) will merge, as
will the Rhode Island distribution companies (The Narragansett Electric
Company, Blackstone Valley Electric Company, and Newport Electric
Corporation). Other related affiliates, such as the service companies, will
merge as well. These combinations of companies with similar functions are
likely to result in significant cost reductions. These cost savings are not
likely to be achievable outside of the NEES/EUA merger because they are
derived from the elimination of the redundancies between affiliated
operating and service companies active in common lines of business. These
redundancies are in personnel, facilities, systems, and other areas.
38. Management consultants David J. Hoffman and Richard J. Levin from Mercer
Management Consulting have estimated the net merger efficiencies to be
approximately $30 million per year by the end of the distribution rate
freeze period.34,35 Messrs. Hoffman and Levin estimated these net savings
- ---------------
34 Direct Testimony of David J. Hoffman and Richard J. Levin before the
Massachusetts Department of Telecommunications and Energy ("Hoffman/Levin
Testimony"), April 30, 1999, at 7 and Exhibit DJH-2.
35 The parties have proposed a four year distribution rate freeze beyond the
distribution rate freeze in the Massachusetts Electric Company and Eastern
Edison Company Restructuring Settlements which expire on December 31, 2000.
See Direct Testimony of Michael E. Jesanis before the Massachusetts
Department of Telecommunications and Energy ("Jesanis Testimony"), April
30, 1999 at 9-14. Mr. Jesanis is presently Senior Vice president and Chief
Financial Officer of NEES and also Vice President of New England Power, The
Narragansett Electric Company, and New England Power Service Company. New
England Power Service Company provides administrative, engineering,
construction, legal, and financial services to NEES and its subsidiaries.
26
<PAGE>
from the regulated operations of NEES and EUA. Their estimates derive from
areas such as the elimination of duplication, cost avoidance, the adoption
of different management practices and policies, and the improved
utilization of assets and employees.36 They assumed that the financial,
accounting, human resources, external affairs, and corporate planning
functions of NEES and EUA will be fully combined. In addition, they assumed
that the information system data centers, call centers, central
transmission and distribution planning, engineering, and support functions,
and transmission field forces also will be integrated.37 Furthermore,
Michael E. Jesanis estimated that additional savings identified as part of
the integration process will increase annual savings to $35 million per
year in the first year after the rate freeze.38 Messrs. Hoffman and Levin
did not estimate efficiencies resulting from the non-regulated NEES and EUA
operations. Thus, they likely underestimate the total efficiencies arising
from the proposed merger.
39. Consumers will derive significant benefits from the proposed acquisition.
Because the likely cost savings found by Messrs. Hoffman, Levin and Jesanis
derive from the regulated operations of NEES and EUA, some of these cost
reductions will flow through the merged companies' regulated rates for
transmission and distribution service. End users will benefit directly from
reduced transmission and distribution charges.39 For example, the
consolidation of Eastern Edison and Massachusetts Electric rates and a
- ---------------
36 Hoffman/Levin Testimony at 8.
37 Hoffman/Levin Testimony at 10.
38 Jesanis Testimony at 16, 22, 24-26.
39 See Jesanis Testimony at 8-12, 16-17.
27
<PAGE>
following freeze in distribution rates is anticipated to save Eastern
Edison customers about $20 million in 2002 alone.40
40. The proposed acquisition and subsequent subsidiary combinations will likely
result in additional benefits for consumers by promoting competition in
retail electricity markets. In particular, the integration of the
distribution companies will likely make it easier for power marketers to
enter the retail market and gain customers. In the case of Rhode Island,
for example, three distribution companies will be merged into one. The
consolidation of the distribution companies will not harm competition in
distribution services because distribution is now and will remain a
regulated, natural monopoly service. The consolidation will, however,
reduce transaction costs for competitive retail electricity suppliers.
Power marketers will have to interface with fewer distribution company
support systems, simplifying procedures and reducing costs. Differing
distribution rates and availability clauses for providing distribution
services complicate the power supply business. Furthermore, the combination
of the distribution companies will enable marketers to use common
advertising and simplify marketing efforts. This is likely to reduce the
costs and enhance the effectiveness of their promotional activities. Though
these and other similar benefits may be difficult to quantify, consumers
clearly gain from actions that promote the development of a competitive
retail marketplace in electricity.
- ---------------
40 Jesanis Testimony at Exhibit MEJ-4, revised.
28
<PAGE>
VIII. Conclusion.
41. The proposed acquisition of EUA by NEES will not create or enhance market
power in electric generation or transmission or otherwise facilitate its
exercise. Both NEES and EUA are exiting the generation business. In
addition, many divested generation facilities in New England have been
acquired by out-of-market firms, resulting in new market participants.
These and other new participants are actively expanding the capacity of
current facilities, adding new units to existing generation locations, and
developing new generation sites. This activity is strongly procompetitive,
and it provides additional support to my conclusion that this transaction
will not result in harm to competition in wholesale electricity markets. In
addition, this transaction will not result in harm to competition in the
provision of transmission services or result in vertical competitive
effects. Furthermore, this merger will likely result in significant
benefits for consumers arising from both cost reduction efficiencies and
the promotion of competitive retail markets for electricity. Thus, I
conclude that the proposed acquisition of EUA by NEES will not adversely
impact competition but rather will advance consumer interests due to the
likely realization of significant efficiencies and the transaction's
potential to further the development of competitive retail markets.
I declare under penalty of perjury that the foregoing is true and correct.
/s/ Henry J. Kahwaty
----------------------------------------
Henry J. Kahwaty
Signed on this 5th day of May, 1999
29
<PAGE>
Appendix
Several market power studies related to New England have been
completed in the last few years. These studies have all relied, in part, on
market concentration calculations and the screening thresholds set out in the
Horizontal Merger Guidelines jointly issued by the U.S. Department of Justice
and the Federal Trade Commission. The concentration-based screening thresholds
contained in the Horizontal Merger Guidelines were adopted by the FERC in its
Policy Statement on mergers. In this Appendix, I describe the screening criteria
in the Horizontal Merger Guidelines and then consider the impact of the proposed
acquisition of EUA by NEES on the market concentration screens considered in
these studies. In all cases, the resulting changes in the HHI implied by the
NEES/EUA transaction are well within the Horizontal Merger Guidelines screening
thresholds, indicating that this proposed acquisition is not likely to create or
enhance market power or facilitate its exercise.
The Horizontal Merger Guidelines divides the range of potential HHI
values into three regions. If the post-merger HHI is below 1,000, the market is
deemed unconcentrated and an exercise of market power is presumed unlikely.
These markets "pass" the HHI screen and ordinarily require no further analysis.
If the post-merger HHI is between 1,000 and 1,800 the market is deemed to be
moderately concentrated. If, as a result of the merger, the HHI increases less
than 100 in a moderately concentrated market, the merger is presumed unlikely to
result in competitive effects. If the increase is over 100, however, the
Horizontal Merger Guidelines state that significant competitive concerns may
arise, and further analysis is required to determine whether harm to competition
is likely. Finally, if the post-merger HHI is above 1,800, the market is
1
<PAGE>
deemed "highly concentrated." A market with five firms of equal size has an HHI
of 2,000. Thus, the overall level of market concentration implicit in an HHI
value of 1,800 is similar to that of a market with approximately five
equally-sized competitors. If the HHI increase arising from a merger in a highly
concentrated market is less than 50, significant competitive effects are
presumed unlikely. If the increase is between 50 and 100, then the Horizontal
Merger Guidelines state that significant competitive concerns may arise, and
further analysis is required to determine whether harm to competition is likely.
Finally, if the increase is above 100, the Horizontal Merger Guidelines presume
that merger will be "likely to create or enhance market power or facilitate its
exercise."1 This presumption may be overcome if ease of entry or other
considerations make the exercise of market power unlikely.
John Reed prepared a Report assessing the competitive implications of
the proposed merger of BEC Energy and Commonwealth Energy Systems (the "Reed
Report"). The Reed Report, dated February 8, 1999, was filed in Docket No.
EC99-33-000. The Reed Report assess the competitive implications of the BEC
Energy and Commonwealth Energy Systems merger in part by completing an analysis
consistent with the FERC's Policy Statement on mergers. The Reed Report
identified several product markets relevant to the analysis of the BEC
Energy/Commonwealth Energy Systems merger. These product markets include:
o Total Summer Capacity,
o Total Winter Capacity,
o Total Shoulder Capacity,
o Summer Peak Economic Capacity,
- ---------------
1 Horizontal Merger Guidelines at section 1.51.
2
<PAGE>
o Summer Off-Peak Economic Capacity,
o Winter Peak Economic Capacity,
o Winter Off-Peak Economic Capacity,
o Shoulder Peak Economic Capacity,
o Shoulder Off-Peak Economic Capacity, and
o Super Peak Economic Capacity.
The relevant geographic market considered in the Reed Report is NEPOOL. As part
of its analysis, the Reed Report calculates HHIs for these product markets in
the NEPOOL geographic market.
I have used the information in the Reed Report to consider the
implications of the proposed acquisition of EUA by NEES. To complete my
analysis, I adjusted the data in the Reed Report in several ways. These
adjustments include the following:
o Reallocated generation resources from New England Power to USGen New
England. New England Power has completed the divestiture of its
generation resources to USGen New England with the exception of its
entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman 4.
All other resources for New England Power in the Reed Report have been
reallocated to USGen New England. New England Power's remaining
generation resources include approximately 400 MW of generation
capacity.
o Reallocated USGen New England's Ocean States Power entitlement to
TransCanada Power Marketing. Immediately after New England Power
transferred its entitlement from the Ocean States Power facility to
USGen New England, USGen New England transferred this entitlement to
TransCanada Power Marketing. I have reallocated this capacity to
TransCanada Power Marketing. This reallocation involved approximately
250 MW of capacity.
o Reallocated generation resources from EUA affiliates to other market
participants. Montaup has completed the sale of several of its
generation resources to other market participants and has additional
sale and transfer agreements pending. Outside of these agreements,
Montaup's only remaining generation resources are its entitlements in
Millstone 3, Vermont Yankee, and Pilgrim. I have reallocated resources
from EUA to Constellation Power Source, FPL Group, NRG Energy,
3
<PAGE>
TransCanada Power Marketing, Great Bay Power Corporation, and others
to reflect these divestitures.
After making these adjustments, I recalculated market HHI levels and
increases due to the NEES/EUA transaction for the ten capacity and economic
capacity markets listed above. In all ten cases, the HHI calculations indicated
that the market was moderately concentrated, having a post-merger HHI between
1,250 and 1,650. Furthermore, the increases in the HHIs due to the NEES/EUA
merger were all between one (1) and six (6). These are very small increases and
clearly fall within the safe harbors set out in the Horizontal Merger Guidelines
and the FERC's Policy Statement on mergers. Details of these HHI calculations
are provided in Workpaper HJK-1.
Joe D. Pace submitted a market power analysis on behalf of New
England Power, The Narragansett Electric Company, and USGen New England (the
"Pace Report"). The Pace Report was filed in Docket Nos. EC98-1-000 and
ER98-6-000 on September 30, 1997.2 The Pace Report analyzed the competitive
effects of New England Power's and The Narragansett Electric Company's
divestiture of substantially all of their generation resources to USGen New
England. The parties also requested market-based pricing authority for
themselves and for NEES affiliate AllEnergy.
- ---------------
2 Dr. Pace also submitted a supplemental analysis in these dockets dated
November 4, 1997. This analysis considered the sale by USGen New England
of an equity interest in the Ocean State Power and Ocean State Power II
project to subsidiaries of TransCanada Pipelines Limited and related agree
ments. USGen New England was to acquire this interest as part of its pur
chase of the generation business of New England Power and its affiliates.
4
<PAGE>
The Pace Report considers short run capacity and energy product
markets. Dr. Pace concludes that the relevant geographic market is at least as
broad as NEPOOL because of the structure of NEPOOL transmission rates and the
limited impact of transmission constraints in NEPOOL.3
The Pace Report considers short run capacity market conditions by
analyzing market shares and HHIs based on total installed capacity and on
uncommitted capacity. Both total installed capacity and uncommitted capacity are
analyzed for summer and winter in each of several years. Dr. Pace analyzes
energy market conditions by considering market shares and HHIs for total
economic capacity and available economic capacity for a range of load conditions
in each of the four seasons for both 1998 and 2000. Due to the progress made on
market restructuring in New England since Dr. Pace completed his analysis in
late 1997, I focus only on his study of total installed capacity and total
economic capacity.
I first considered Dr. Pace's analysis of total installed capacity.
All of Dr. Pace's total capacity HHIs are in the moderately concentrated range
of HHI values.4 With recent divestitures in New England, these HHIs have likely
fallen. To consider the impact of the NEES/EAU transaction on these HHIs, I
first adjusted EUA's capacity to reflect its pending and completed divestitures.
I then calculated the increases in the total installed capacity HHIs for both
- ---------------
3 Pace Report at 27-29.
4 Pace Report at Table JDP-4.
5
<PAGE>
winter and summer in 1999 and 2000.5 All four of the resulting HHI increases are
less than two (2), indicating that the NEES/EUA transaction comfortably meets
the safe harbor screening criteria of the Horizontal Merger Guidelines. These
calculations are detailed in Workpaper HJK-2.
Next, I consider Dr. Pace's analysis of total economic capacity in
1998 and 2000.6 His total economic capacity HHIs are all below 1,700, and some
are even below 1,000 (in the unconcentrated range of HHI values). These HHIs
have likely fallen due to recent divestitures. To consider the impact of the
NEES/EAU transaction on these HHIs, I first adjusted EUA's capacity to reflect
its pending and completed divestitures. I then calculated the increases in the
total economic capacity HHIs for both winter and summer in 1998 and 2000. I only
calculated HHI increases for Dr. Pace's lowest level of load - typically 8,000
MW. This is because most of New England Power's and all of Montaup's generation
resources are nuclear and hence are economic for these load levels. In addition,
to simplify my calculations, I also assumed that New England Power's economic
capacity includes its Wyman 4 entitlement, even at low load levels. This
assumption overestimates New England Power's share of total economic capacity
for these low load levels, and hence it overestimates the resulting HHI
increases. The largest HHI increase due to NEES/EUA transaction is under nine
(9). Furthermore, the shares of total economic capacity for New England Power
and Montaup fall as load levels increase, so the increases in the HHI for other
- ---------------
5 If Firms 1 and 2 have market shares of s1 and s2, respectively, then the
change in the HHI due to a merger of these two firms is two times the
product of the market shares of firms 1 and 2, or 2*s1*s2.
6 Pace Report at Table JDP-6.
6
<PAGE>
load levels must all be smaller than nine (9). Thus, the increases in total
economic capacity HHIs due to the NEES/EUA transaction are all well below safe
harbor screening thresholds. My calculations of the total economic capacity HHI
increases are detailed in Workpaper HJK-2.
William Hieronymous submitted a market power analysis on behalf of the
NEPOOL Executive Committee related to the restructuring of NEPOOL and the
receipt of market-based rates by NEPOOL members (the "Hieronymous Report"). The
Hieronymous Report was filed in Docket Nos. OA97-237-000 and ER97-1079-000 on
February 28, 1997.
The Hieronymous Report studied seven relevant products under the
Restated NEPOOL Agreement: (1) Installed Capability, (2) Energy, (3) Ten-Minute
spinning Reserve, (4) Ten-Minute Non-Spinning Reserve, (5) 30-Minute Operating
Reserve, (6) Automatic Generation Control, and (7) Operable Capability. He
concluded that, under ordinary conditions, the NEPOOL dispatch is essentially
unconstrained by transmission limitations. This, in combination with
postage-stamp transmission pricing, led him to conclude that the NEPOOL control
area was a relevant geographic market.7
The Hieronymous Report considers market power issues based upon two
alternative scenarios - the then present world with native load obligations and
a restructured world without native load obligations. Given the progress made on
- ---------------
7 Hieronymous Report at 19-20, 23.
7
<PAGE>
market restructuring since Dr. Hieronymous completed his analysis in early 1997,
I focus only on his study of restructured electricity markets without native
load obligations.
Dr. Hieronymous begins his analysis with a discussion of the installed
capability product market.8 His study includes monthly HHI calculations for this
market between July 1997 and December 1999. These HHIs range between 1,711 and
1,830, and have likely fallen recently due to divestitures. I altered Dr.
Hieronymous' data to represent completed and pending divestitures by New England
Power, Montaup, and their affiliates. I then calculated the resulting HHI
increases due to the NEES/EUA transaction. These increases are all below two
(2), well under the FERC's screening thresholds. Details of these calculations
are provided in Workpaper HJK-3. Due to the similarities between installed
capability and operable capability, I did not analyze operable capability.
Dr. Hieronymous also analyzes energy markets.9 He provides annual
energy HHIs for 1998, 1999, and July - December 1997 for all hours as well as
for on-peak hours, off-peak hours, and for six ranges related to the energy
clearing price.10 He finds HHIs that range between 1,647 and 2,004. I used 1996
and 1997 FERC Form 1 energy output data to determine energy output for the
facilities in which NEES and EUA affiliates continue to own entitlements to
calculate the increase in energy market HHIs for 1998 and 1999 due to the
NEES/EAU merger. These increases are both less than eight (8), again well within
- ---------------
8 Hieronymous Report at 40-41 and Exhibit No. WHH-12.
9 Hieronymous Report at 41 and Exhibit No. WHH-13.
10 These energy clearing price ("ECP") ranges are ECP<20, 20<=ECP<25,
25<=ECP<30, 30<=ECP35, 35<=ECP40, and ECP>=40.
8
<PAGE>
the Horizontal Merger Guidelines safe harbors. Details of these calculations are
provided in Workpaper HJK-3.
Dr. Hieronymous also analyzes Ten-Minute Spinning Reserve, Ten-Minute
Non-Spinning Reserve, 30-Minute Operating Reserve, and Automatic Generation
Control product markets.11 Because EUA affiliates will only have entitlements to
the output of nuclear facilities after completing pending divestitures, EUA
affiliates will have no resources that can supply these products. As a result,
EUA's shares in these markets are all zero. Hence there will be no change in the
HHIs for these markets due to NEES's acquisition of EUA.
- ----------------
11 Hieronymous Analysis at 41-42 and Exhibit Nos. WHH-14, WHH-15, WHH-16, and
WHH-18.
9
<PAGE>
[LECG Logo] New England Power Company, et al.
Docket No. EC99-______
Exhibit HJK-1
Page 1 of 4
HENRY J. KAHWATY
LECG
1600 M Street, N.W., Suite 700
Washington, D.C. 20036
Tel. (202) 466-4422
Fax (202) 466-4487
EDUCATION
Ph.D., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and
Sciences, Philadelphia, PA, 1991
Thesis Title: Essays on Vertical Relationships
Thesis Topic: Vertical Relationships with Asymmetric Information and
Incomplete Contracting
Specialty Areas: Industrial Organization, Public Economics, Monetary
Economics
M.A., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and
Sciences, Philadelphia, PA, 1988
B.A. magna cum laude and Phi Beta Kappa, Mathematics and Economics,
UNIVERSITY OF PENNSYLVANIA, College of Arts and Sciences, Philadelphia, PA,
1986
PRESENT POSITION
LECG, Washington, D.C.
Senior Managing Economist, 1997-present
Senior Economist, 1995-1996
o Analysis of antitrust market definition.
o Analysis of the competitive effects resulting from mergers.
o Monopolization analysis.
<PAGE>
[LECG Logo] New England Power Company, et al.
Docket No. EC99-______
Exhibit HJK-1
Page 2 of 4
o Analysis of competition issues in the electric utility industry,
including market-based pricing and deregulation proposals, mergers,
wholesale markets, and retail wheeling.
o Analysis of competition and other issues in telecommunications.
o Damage studies.
Consultant to Rational Software Corp. in proposed acquisition of Pure Atria
Corp., 1997.
Consultant to National Communications Association, Inc. in National
Communications Association, Inc. v. American Telephone and Telegraph
Company, 1997-1998.
Consultant to Public Service Enterprises of Pennsylvania, Inc. in
arbitration between Public Service Enterprises of Pennsylvania, Inc. and
AT&T Corporation, 1997-1998.
Consultant to Aptix Corporation in Aptix Corporation v. Quickturn Design
Systems, Inc., 1998.
Consultant to New England Electric System in proposed acquisition by
National Grid Group plc, 1999.
Consultant to New England Electric System in proposed acquisition of
Eastern Utilities Associates, 1999.
Experience with the following industries:
o Local and long distance telecommunications
o Computer software and software development tools
o Computer hardware, including microprocessors and modems
o Electricity
o Defense electronics
o Hardware emulation
2
<PAGE>
[LECG Logo] New England Power Company, et al.
Docket No. EC99-______
Exhibit HJK-1
Page 3 of 4
PROFESSIONAL EXPERIENCE
U.S. DEPARTMENT OF JUSTICE, Antitrust Division, Economic Litigation
Section, 1991-1995
Economist
o Prepared economic models and analysis for antitrust cases.
o Prepared antitrust investigation plans.
o Reviewed civil investigative demands, second requests, subpoenas,
complaints, affidavits, and other documents.
o Assisted attorneys with gathering evidence, including conducting
witness interviews and assisting with witness depositions.
o Recommended whether to institute enforcement actions.
o Specialized in computer software, defense, and banking industries.
TESTIMONY
Provided deposition and trial testimony in National Communications
Association, Inc. v. American Telephone and Telegraph Company, 92 Civ. 1735
(LAP), U.S. District Court for the Southern District of New York,
1997-1998.
Provided deposition testimony in Aptix Corporation v. Quickturn Design
Systems, Inc., C-96-20909 JF (EAI), U.S. District Court for the Northern
District of California, 1998.
SPEECHES
"Unregulated Affiliates and the Market Power Problem," Forum on Electric
Power Market Restructuring, Washington, D.C., February 19, 1999.
"Antitrust Damages," Litigation Services Subcommittee of the Greater
Washington Society of Certified Public Accountants, Washington, D.C.,
January 28, 1999.
3
<PAGE>
[LECG Logo] New England Power Company, et al.
Docket No. EC99-______
Exhibit HJK-1
Page 4 of 4
TEACHING EXPERIENCE
UNIVERSITY OF PENNSYLVANIA, Philadelphia, PA, 1988-1991
o Industrial Organization
o Topics in Microeconomics
o Topics in Macroeconomics
o Intermediate Microeconomics
o Introductory Microeconomics
o Introductory Macroeconomics
UNPUBLISHED RESEARCH
"The Analysis of Market Concentration, Market Power and the Competitive
Effects of Mergers in the Electric Industry," with Richard J. Gilbert, June
1997.
RESEARCH INTERESTS
Oligopoly models, network externalities and asymmetric information.
PROFESSIONAL ACTIVITIES
Member, American Economic Association
Member, European Association for Research in Industrial Economics
Citizenship: United States of America
4
<PAGE>
[LECG Logo] New England Power Company, et al.
Docket No. EC99-____
Exhibit HJK-2
Page 1 of 1
<TABLE>
<CAPTION>
Net Generation Entitlements for NEES Affiliates Post-Merger
Entitlement
Entitlement Capacity
Plant Share (%) (MW)
<S> <C> <C>
Millstone 3 16.22 185
Pilgrim 11.00 74
Seabrook 1 9.96 116
Vermont Yankee 20.23 101
Wyman 4 9.27 57
Total 533
</TABLE>
Source: Declaration at paras. 6 and 8.
<PAGE>
[LECG Logo] New England Power Company, et al.
Docket No. EC99-______
Exhibit HJK-3
Page 1 of 1
<TABLE>
<CAPTION>
Recent Acquirers of Generation Resources Divested by
New England Utilities
Corporate Affiliation of
Acquiring Company Acquiring Company Divesting Company Source
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
TransCanada Power Marketing TransCanada PipeLines Montaup 1
Great Bay Power Corporation BayCorp Holdings, Ltd. Montaup 1
Wabash Power Equipment Newport Electric 1
Pawtucket Generating Co. LLC Blackstone Valley Electric 1
Constellation Power Source Baltimore Gas and Electric Co. Montaup 1
Southern Energy Inc. Southern Company Montaup/Cambridge Electric Light Company, 1.2
Canal Electric Company, and Commonwealth
Electric Company
FPL Group/FPL Energy Maine FPL Group Montaup/Central Maine Power Co. 1.3
Sithe New England Sithe Energies Boston Edison Company 4
USGen New England PG&E Corporation New England Power 5
NRG Energy Northern States Power Company Montaup 6
PP & L Global, Inc. PP&L Resources, Inc. Bangor Hydro-Electric Co. 7
Consolidated Edison Energy Consolidated Edison, Inc. Western Massachusetts Electric Company 8
(affiliate of Northeast Utilities)
Entergy Nuclear Generating Co. Entergy Corporation Boston Edison Company 9
Wisvest Wisconsin Energy Corporation United Illuminating Company 10
- ----------------------------------------------------------------------------------------------------------------------------------
Sources: 1. http://www.eua.com/divestiturelinks.html
2. http://www.comenergy.com/news.htm#south
3. http://www.cmpco.com/news/older_releases/980106.html;
http://www.cmpco.com/news/older_releases/980618.html
4. http://www.bostonedison.com/NEWS/P_SITHE.HTM
5. http://www.nees.com/news/080697a.htm
6. http://www.nees.com/news/090198b.htm
7. http://www.pplresources.com/webre_dcd/owa/News_Releases.Show_Release?art_id=332&co_id=0
8. http://www.conedison.com/cone_ny/about/news/pr19990127.asp?from=hc
9. http://www.bedison.com/NEWWS/entergy.htm
10. http://www.unitilcorp.com/News/NewHaven.htm
</TABLE>
<PAGE>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-_____
Workpaper HJK-1
Page 1 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Legend
Symbol Company
BECO Boston Edison Company
BELD Braintree Electric Light Department
BHE Bangor Hydro-Electric Company
BPDI Berkshire Power Development, Inc.
CES Commonwealth Energy System Companies
CLNP Constellation Power Source
CMEES Connecticut Municipal Electric Energy Cooperative
CMLP Chicopee Municipal Lighting Plant
CMP Central Maine Power Company
CV Central Vermont Public Service Corporation
DPA Dighton Power Associates
DUKE Duke Power Company
ENT Entergy Nuclear Generating
EUA Eastern Utilities Associates
FGE Fitchburg Gas and Electric Department
FPL FPL Group
GBPC Great Bay Power Corporation
GMP Green Mountain Power Corporation
HGE Holyoke Gas and Electric Department
HLPD Hudson Light and Power Department
HMLP Hingham Municipal Lighting Plant
IMEL Indeck Maine Energy, LLC
IMLD Ipswich Municipal Light Department
IPPA Indeck-Pepperell Power Associates, Inc.
MGED Middleborough Gas and Electric Department
MMLD Marblehead Municipal Light Department
MMWEC Massachusetts Municipal Wholesale Electric Co.
MPLP Milford Power Limited Partnership
NAED North Attleborough Electric Department
NEP New England Electric System Operating Companies
NHCO New Hampshire Electric Cooperative
NRG NRG Energy
NU Northeast Utilities Companies
PMLD Princeton Municipal Light Department
PMLP Peabody Municipal Light Plant
SC Southern Company
SELP Shrewsbury Electric Light Plant
SITHE Sithe Energies, Inc.
TCPM TransCanada Power Marketing
TMLP Taunton Municipal Lighting Plant
UI The United Illuminating Company
UNITIL UNITIL Corp. NH Participant Companies
USG USGen New England
VTGP Vermont Group
WBSH Wabash Power Equipment
<PAGE>
<TABLE>
<CAPTION>
New England Power Company, et al.
Docket No. EC 99-_____
Workpaper HJK-1
Page 2 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Total Capacity Analysis, Summer
Pre-Merger Post-Merger
Total Total
Summer Share of Summer Share of
Capacity Summer Square of Capacity Summer Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 132.9 0.49% 0
NEP 2 409.1 1.51% 2 EUA/NEP 542.0 2.01% 4
BECO/CES 2034.3 7.53% 57 BECO/CES 2034.3 7.53% 57
BELD 73.8 0.27% 0 BELD 73.8 0.27% 0
BHE 176.0 0.65% 0 BHE 176.0 0.65% 0
BPDI 265.9 0.98% 1 BPDI 265.9 0.98% 1
CLNP 5 227.9 0.84% 1 CLNP 5 227.9 0.84% 1
CMEEC 192.3 0.71% 1 CMEEC 192.3 0.71% 1
CMLP 33.8 0.13% 0 CMLP 33.8 0.13% 0
CMP 1519.8 5.63% 32 CMP 1519.8 5.63% 32
CV 322.8 1.19% 1 CV 322.8 1.19% 1
DPA 168.0 0.62% 0 DPA 168.0 0.62% 0
DUKE 480.0 1.78% 3 DUKE 480.0 1.78% 3
FGE 71.3 0.26% 0 FGE 71.3 0.26% 0
FPL 5 16.2 0.06% 0 FPL 5 16.2 0.06% 0
GBPC 3 174.7 0.65% 0 GBPC 3 174.7 0.65% 0
GMP 301.4 1.12% 1 GMP 301.4 1.12% 1
HGE 31.6 0.12% 0 HGE 31.6 0.12% 0
HLPD 14.2 0.05% 0 HLPD 14.2 0.05% 0
HMLP 6.3 0.02% 0 HMLP 6.3 0.02% 0
IMEL 52.4 0.19% 0 IMEL 52.4 0.19% 0
IMLD 15.3 0.06% 0 IMLD 15.3 0.06% 0
IPPA 34.1 0.13% 0 IPPA 34.1 0.13% 0
MGED 2.8 0.01% 0 MGED 2.8 0.01% 0
MMLD 6.0 0.02% 0 MMLD 6.0 0.02% 0
MMWEC 677.7 2.51% 6 SITHE 677.7 2.51% 6
MPLP 149.0 0.55% 0 MPLP 149.0 0.55% 0
NAED 15.2 0.06% 0 NAED 15.2 0.06% 0
NHCO 25.3 0.09% 0 NHCO 25.3 0.09% 0
NRG 5 150.7 0.56% 0 NRG 5 150.7 0.56% 0
NU 7418.4 27.46% 754 NU 7418.4 27.46% 754
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0`
PMLP 55.3 0.20% 0 PMLP 55.3 0.20% 0
SC 581.5 2.15% 5 SC 581.5 2.15% 5
SELP 16.0 0.06% 0 SELP 16.0 0.06% 0
SITHE 1980.4 7.33% 54 SITHE 1980.4 7.33% 54`
TCPM 4, 5 387.6 1.43% 2 TCPM 4, 5 387.6 1.43% 2
TMLP 114.8 0.42% 0 TMLP 114.8 0.42% 0
UI 1467.1 5.43% 29 UI 1467.1 5.43% 29
UNITIL 32.8 0.12% 0 UNITIL 32.8 0.12% 0
USG 4 4597.7 17.02% 290 USG 4 4597.7 17.02% 290
VTGP 202.4 0.75% 1 VTGP 202.4 0.75% 1
NY 1675.0 6.20% 38 NY 1675.0 6.20% 38
NB 700.0 2.59% 7 NB 700.0 2.59% 7
WBSH 5 8.0 0.03% 0 WBSH 5 8.0 0.03% 0
- ---------------------------------------------------------------------------------------------------------------------------
Total 27018.1 100.00% Total 27018.1 100.00%
HHI 1286.61 HHI 1288.10
Change in HHI 1.49
Source: Reed Report at Table 10.
Notes:
1. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 3 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Total Capacity Analysis, Winter
Pre-Merger Post-Merger
Total Total
Summer Share of Summer Share of
Capacity Summer Square of Capacity Summer Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 133.5 0.47% 0
NEP 2 415.1 1.47% 2 EUA/NEP 548.6 1.94% 4
BECO/CES 2210.7 7.80% 61 BECO/CES 2210.7 7.80% 61
BELD 91.1 0.32% 0 BELD 91.1 0.32% 0
BHE 185.4 0.65% 0 BHE 185.4 0.65% 0
BPDI 295.0 1.04% 1 BPDI 295.0 1.04% 1
CMEEC 198.8 0.70% 0 CMEEC 198.8 0.70% 0
CLNP 5 234.7 0.83% 1 CLNP 5 234.7 0.83% 1
CMLP 33.9 0.12% 0 CMLP 33.9 0.12% 0
CMP 1577.8 5.57% 31 CMP 1577.8 5.57% 31
CV 312.0 1.10% 0 CV 312.0 1.10% 1
DPA 185.0 0.65% 0 DPA 185.0 0.65% 0
DUKE 520.0 1.84% 3 DUKE 520.0 1.84% 3
FGE 77.2 0.27% 0 FGE 77.2 .27% 0
FPL 5 16.3 0.06% 0 FPL 5 16.3 0.06% 0
GBPC 3 174.7 0.62% 0 GBPC 3 174.7 0.62% 0
GMP 325.4 1.15% 1 GMP 325.4 1.15% 1
HGE 29.9 0.11% 0 HGE 29.9 0.11% 0
HLPD 14.4 0.05% 0 HLPD 14.4 0.05% 0
HMLP 6.9 0.02% 0 HMLP 6.9 0.02% 0
IMEL 52.4 0.18% 0 IMEL 52.4 0.18% 0
IMLD 15.8 0.06% 0 IMLD 15.8 0.06% 0
IPPA 42.3 0.15% 0 IPPA 42.3 0.15% 0
MGED 2.9 0.01% 0 MGED 2.9 0.01% 0
MMLD 6.0 0.02% 0 MMLD 6.0 0.02% 0
MMWEC 800.4 2.83% 8 MMWEC 800.4 2.83% 8
MPLP 170.7 0.60% 0 MPLP 170.7 0.60% 0
NAED 16.5 0.06% 0 NAED 16.5 0.06% 0
NHCO 25.3 0.09% 0 NHCO 25.3 0.09% 0
NRG 5 163.3 0.58% 0 NRG 5 163.3 0.58% 0
NU 7724.3 27.27% 743 NU 7724.3 27.27% 743
TCPM 4, 5 445.1 1.57% 2 TCPM 4, 5 445.1 1.57% 2
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 76.7 0.27% 0 PMLP 76.7 0.27% 0
SC 591.6 2.09% 4 SC 591.6 2.09% 4
SELP 16.0 0.06% 0 SELP 16.0 0.06% 0
SITHE 2066.8 7.30% 53 SITHE 2066.8 7.30% 53
TMLP 118.0 0.42% 0 TMLP 118.0 0.42% 0
UI 1496.4 5.28% 28 UI 1496.4 5.28% 28
UNITIL 42.7 0.15% 0 UNITIL 42.7 0.15% 0
USG 4 4779.2 16.87% 285 USG 4 4779.2 16.87% 285
VTGP 257.0 0.91% 1 VTGP 257.0 0.91% 1
NY 1675.0 5.91% 35 NY 1675.0 5.91% 35
NB 700.0 2.47% 6 NB 700.0 2.47% 6
WBSH 5 8.0 0.03% 0 WBSH 5 8.0 0.03% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 28330.4 100.00% Total 28330.4 100.00%
HHI 1270.71 HHI 1272.09
Change in HHI 1.38
Source: Reed Report at Table 10.
Notes:
1. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 4 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Total Capacity Analysis, Shoulder
Pre-Merger Post-Merger
Total Total
Shoulder Share of Shoulder Share of
Capacity Shoulder Square of Capacity Shoulder Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 133.2 0.48% 0
NEP 2 412.1 1.49% 2 EUA/NEP 545.3 1.97% 4
BECO/CES 2122.3 7.67% 59 BECO/CES 2122.3 7.67% 59
BELD 82.4 0.30% 0 BELD 82.4 0.30% 0
BHE 180.7 0.65% 0 BHE 180.7 0.65% 0
BPDI 280.5 1.01% 1 BPDI 280.5 1.01% 1
CLNP 5 231.3 0.84% 1 CLNP 5 231.3 0.84% 1
CMEEC 195.5 0.71% 0 CMEEC 195.5 0.71% 0
CMLP 33.8 0.12% 0 CMLP 33.8 0.12% 0
CMP 1549.1 5.60% 31 CMP 1549.1 5.60% 31
CV 305.3 1.10% 1 CV 305.3 1.10% 1
DPA 176.5 0.64% 0 DPA 176.5 0.64% 0
DUKE 500.0 1.81% 3 DUKE 500.0 1.81% 3
FGE 74.3 0.27% 0 FGE 74.3 0.27% 0
FPL 5 16.2 0.06% 0 FPL 5 16.2 0.06% 0
GBPC 3 174.7 0.63% 0 GBPC 3 174.7 0.63% 0
GMP 314.5 1.14% 1 GMP 314.5 1.14% 1
HGE 30.8 0.11% 0 HGE 30.8 0.11% 0
HLPD 14.3 0.05% 0 HLPD 14.3 0.05% 0
HMLP 6.6 0.02% 0 HMLP 6.6 0.02% 0
IMEL 52.4 0.19% 0 IMEL 52.4 0.19% 0
IMLD 15.6 0.06% 0 IMLD 15.6 0.06% 0
IPPA 38.2 0.14% 0 IPPA 38.2 0.14% 0
MGED 2.9 0.01% 0 MGED 2.9 0.01% 0
MMLD 6.0 0.02% 0 MMLD 6.0 0.02% 0
MMWEC 750.1 2.71% 7 MMWEC 750.1 2.71% 7
MPLP 159.9 0.58% 0 MPLP 159.9 0.58% 0
NAED 15.8 0.06% 0 NAED 15.8 0.06% 0
NHCO 25.3 0.09% 0 NHCO 25.3 0.09% 0
NRG 5 157.0 0.57% 0 NRG 5 157.0 0.57% 0
NU 7567.9 27.34% 747 NU 7567.9 27.34% 747
TCPM 4, 5 409.5 1.48% 2 TCPM 4, 5 409.5 1.48% 2
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 66.0 0.24% 0 PMLP 66.0 0.24% 0
SC 586.6 2.12% 4 SC 586.6 2.12% 4
SELP 16.0 0.06% 0 SELP 16.0 0.06% 0
SITHE 2023.6 7.31% 53 SITHE 2023.6 7.31% 53
TMLP 116.4 0.42% 0 TMLP 116.4 0.42% 0
UI 1481.8 5.35% 29 UI 1481.8 5.35% 29
UNITIL 40.8 0.15% 0 UNITIL 40.8 0.15% 0
USG 4 4693.0 16.95% 287 USG 4 4693.0 16.95% 287
VTGP 239.1 0.86% 1 VTGP 239.1 0.86% 1
NY 1675.0 6.05% 37 NY 1675.0 6.05% 37
NB 700.0 2.53% 6 NB 700.0 2.53% 6
WBSH 5 8.0 0.03% 0 WBSH 5 8.0 0.03% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 27681.2 100.00% Total 27681.2 100.00%
HHI 1277.70 HHI 1279.13
Change in HHI 1.43
Source: Reed Report at Table 10.
Notes:
1. EUA has divested all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 5 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Summer Peak
Pre-Merger Post-Merger
Total Total
Summer Share of Summer Share of
Capacity Summer Square of Capacity Summer Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 132.9 0.78% 1
NEP 2 352.2 2.08% 4 EUA/NEP 485.1 2.86% 8
BECO/CES 1313.6 7.74% 60 BECO/CES 1313.6 7.74% 60
BELD 6.1 0.04% 0 BELD 6.1 0.04% 0
BHE 104.7 0.62% 0 BHE 104.7 0.62% 0
BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0
CLNP 5 196.6 1.16% 1 CLNP 5 196.6 1.16% 1
CMEEC 83.9 0.49% 0 CMEEC 83.9 0.49% 0
CMLP 25.5 0.15% 0 CMLP 25.5 0.15% 0
CMP 920.3 5.42% 29 CMP 920.3 5.42% 29
CV 278.5 1.64% 3 CV 278.5 1.64% 3
DPA 0.0 0.00% 0 DPA 0.0 0.00% 0
DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0
FGE 50.0 0.29% 0 FGE 50.0 0.29% 0
FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0
GBPC 3 174.7 1.03% 1 GBPC 3 174.7 1.03% 1
GMP 200.2 1.18% 1 GMP 200.2 1.18% 1
HGE 5.7 0.03% 0 HGE 5.7 0.03% 0
HLPD 7.3 0.04% 0 HLPD 7.3 0.04% 0
HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0
IMEL 52.4 0.31% 0 IMEL 52.4 0.31% 0
IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0
IPPA 34.1 0.20% 0 IPPA 34.1 0.20% 0
MGED 2.8 0.02% 0 MGED 2.8 0.02% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 274.9 1.62% 3 MMWEC 274.9 1.62% 3
MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0
NAED 1.5 0.01% 0 NAED 1.5 0.01% 0
NHCO 25.3 0.15% 0 NHCO 25.3 0.15% 0
NRG 5 111.0 0.65% 0 NRG 5 111.0 0.65% 0
NU 4664.0 27.49% 756 NU 4664.0 27.49% 756
TCPM 4,5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 10.7 0.06% 0 PMLP 10.7 0.06% 0
SC 0.0 0.00% 0 SC 0.0 0.00% 0
SELP 2.2 0.01% 0 SELP 2.2 0.01% 0
SITHE 388.0 2.29% 5 SITHE 388.0 2.29% 5
TMLP 15.3 0.09% 0 TMLP 15.3 0.09% 0
UI 1451.0 8.55% 73 UI 1451.0 8.55% 73
UNITIL 12.6 0.07% 0 UNITIL 12.6 0.07% 0
USG 4 3573.5 21.06% 444 USG 4 3573.5 21.06% 444
VTGP 119.3 0.70% 0 VTGP 119.3 0.70% 0
NY 1675.0 9.87% 97 NY 1675.0 9.87% 97
NB 700.0 4.13% 17 NB 700.0 4.13% 17
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 16967.7 100.00% Total 16967.7 100.00%
HHI 1497.17 HHI 1500.42
Change in HHI 3.25
Source: Reed Report at Table 7.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all
generation resources other than its entitlements in Millstone 3, Pilgrim and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 6 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Summer Off Peak
Pre-Merger Post-Merger
Total Total
Summer Share of Summer Share of
Capacity Summer Square of Capacity Summer Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 132.9 0.89% 1
NEP 2 352.2 2.35% 6 EUA/NEP 485.1 3.24% 11
BECO/CES 1313.6 8.78% 77 BECO/CES 1313.6 8.78% 77
BELD 6.1 0.04% 0 BELD 6.1 0.04% 0
BHE 104.7 0.70% 0 BHE 104.7 0.70% 0
BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0
CLNP 5 196.6 1.31% 2 CLNP 5 196.6 1.31% 2
CMEEC 75.6 0.51% 0 CMEEC 75.6 0.51% 0
CMLP 25.5 0.17% 0 CMLP 25.5 0.17% 0
CMP 804.3 5.38% 29 CMP 804.3 5.38% 29
CV 278.5 1.86% 3 CV 278.5 1.86% 3
DPA 0.0 0.00% 0 DPA 0.0 0.00% 0
DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0
FGE 50.0 0.33% 0 FGE 50.0 0.33% 0
FPL 5 0 0.00% 0 FPL 5 0.0 0.00% 0
GBPC 3 174.7 1.17% 1 GBPC 3 174.7 1.17% 1
GMP 200.2 1.34% 2 GMP 200.2 1.34% 2
HGE 5.7 0.04% 0 HGE 5.7 0.04% 0
HLPD 7.3 0.05% 0 HLPD 7.3 0.05% 0
HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0
IMEL 52.4 0.35% 0 IMEL 52.4 0.35% 0
IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0
IPPA 34.1 0.23% 0 IPPA 34.1 0.23% 0
MGED 2.8 0.02% 0 MGED 2.8 0.02% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 274.9 1.84% 3 MMWEC 274.9 1.84% 3
MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0
NAED 1.5 0.01% 0 NAED 1.5 0.01% 0
NHCO 25.3 0.17% 0 NHCO 25.3 0.17% 0
NRG 5 111.0 0.74% 1 NRG 5 111.0 0.74% 1
NU 4054.7 27.10% 734 NU 4054.7 27.10% 734
TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 10.7 0.07% 0 PMLP 10.7 0.07% 0
SC 0.0 0.00% 0 SC 0.0 0.00% 0
SELP 2.2 0.01% 0 SELP 2.2 0.01% 0
SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0
TMLP 15.3 0.10% 0 TMLP 15.3 0.10% 0
UI 1451.0 9.70% 94 UI 1451.0 9.70% 94
UNITIL 12.6 0.08% 0 UNITIL 12.6 0.08% 0
USG 4 2690.9 17.98% 323 USG 4 2690.9 17.98% 323
VTGP 119.3 0.80% 1 VTGP 119.3 0.80% 1
NY 1675.0 11.19% 125 NY 1675.0 11.19% 125
NB 700.0 4.68% 22 NB 700.0 4.68% 22
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 14963.5 100.00% Total 14963.5 100.00%
HHI 1425.18 HHI 1429.36%
Change in HHI 4.18
Source: Reed Report at Table 7.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all
generation resources other than its entitlements in Millstone 3, Pilgrim and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 7 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Winter Peak
Pre-Merger Post-Merger
Total Total
Winter Share of Winter Share of
Capacity Winter Square of Capacity Winter Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 133.5 0.83% 1
NEP 2 357.7 2.21% 5 EUA/NEP 491.1 3.04% 9
BECO/CES 1356.6 8.39% 70 BECO/CES 1356.6 8.39% 70
BELD 6.2 0.04% 0 BELD 6.2 0.04% 0
BHE 112.4 0.69% 0 BHE 112.4 0.69% 0
BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0
CLNP 5 56.8 0.35% 0 CLNP 5 56.8 0.35% 0
CMEEC 76.3 0.47% 0 CMEEC 76.3 0.47% 0
CMLP 25.7 0.16% 0 CMLP 25.7 0.16% 0
CMP 852.0 5.27% 28 CMP 852.0 5.27% 28
CV 258.7 1.60% 3 CV 258.7 1.60% 3
DPA 0.0 0.00% 0 DPA 0.0 0.00% 0
DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0
FGE 50.1 0.31% 0 FGE 50.1 0.31% 0
FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0
GBPC 3 174.7 1.08% 1 GBPC 3 174.7 1.08% 1
GMP 203.3 1.26% 2 GMP 203.3 1.26% 2
HGE 5.7 0.04% 0 HGE 5.7 0.04% 0
HLPD 7.3 0.05% 0 HLPD 7.3 0.05% 0
HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0
IMEL 52.4 0.32% 0 IMEL 52.4 0.32% 0
IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0
IPPA 42.3 0.26% 0 IPPA 42.3 0.26% 0
MGED 2.9 0.02% 0 MGED 2.9 0.02% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 300.1 1.86% 3 MMWEC 300.1 1.86% 3
MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0
NAED 1.5 0.1% 0 NAED 1.5 0.01% 0
NHCO 25.3 0.16% 0 NHCO 25.3 0.16% 0
NRG 5 115.3 0.71% 1 NRG 5 115.3 0.71% 1
NU 4841.6 29.93% 896 NU 4841.6 29.93% 896
TCPM 4, 5 0.0 0.00% 0 TCPM 4,5 0.0 0.00% 0
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 10.8 0.07% 0 PMLP 10.8 0.07% 0
SC 0.0 0.00% 0 SC 0.0 0.00% 0
SELP 2.2 0.01% 0 SELP 2.2 0.01% 0
SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0
TMLP 15.4 0.10% 0 TMLP 15.4 0.10% 0
UI 1475.9 9.12% 83 UI 1475.9 9.12% 83
UNITIL 18.7 0.12% 0 UNITIL 18.7 0.12% 0
USG 4 3060.8 18.92% 358 USG 4 3060.8 18.92% 358
VTGP 157.7 0.97% 1 VTGP 157.7 0.97% 1
NY 1675.0 10.35% 107 NY 1675.0 10.35% 107
NB 700.0 4.33% 19 NB 700.0 4.33% 19
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 16176.8 100.00% Total 16176.8 100.00%
HHI 1577.96 HHI 1581.61
Change in HHI 3.65
Source: Reed Report at Table 7.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all
generation resources other than its entitlements in Millstone 3, Pilgrim and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 8 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Winter Off Peak
Pre-Merger Post-Merger
Total Total
Winter Share of Winter Share of
Capacity Winter Square of Capacity Winter Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 133.5 0.94% 1
NEP 2 357.7 2.52% 6 EUA/NEP 491.1 3.46% 12
BECO/CES 1356.6 9.57% 92 BECO/CES 1356.6 9.57% 92
BELD 6.2 0.04% 0 BELD 6.2 0.04% 0
BHE 112.4 0.79% 1 BHE 112.4 0.79% 1
BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0
CLNP 5 56.8 0.40% 0 CLNP 5 56.8 0.40% 0
CMEEC 76.3 0.54% 0 CMEEC 76.3 0.54% 0
CMLP 25.7 0.18% 0 CMLP 25.7 0.18% 0
CMP 852.0 6.01% 36 CMP 852.0 6.01% 36
CV 258.7 1.82% 3 CV 258.7 1.82% 3
DPA 0.0 0.00% 0 DPA 0.0 0.00% 0
DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0
FGE 29.1 0.21% 0 FGE 29.1 0.21% 0
FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0
GBPC 3 174.7 1.23% 2 GBPC 3 174.7 1.23% 2
GMP 203.3 1.43% 2 GMP 203.3 1.43% 2
HGE 5.7 0.04% 0 HGE 5.7 0.04% 0
HLPD 7.3 0.05% 0 HLPD 7.3 0.05% 0
HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0
IMEL 52.4 0.37% 0 IMEL 52.4 0.37% 0
IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0
IPPA 42.3 0.30% 0 IPPA 42.3 0.30% 0
MGED 2.9 0.02% 0 MGED 2.9 0.02% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 291.7 2.06% 4 MMWEC 291.7 2.06% 4
MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0
NAED 1.5 0.01% 0 NAED 1.5 0.01% 0
NHCO 25.3 0.18% 0 NHCO 25.3 0.18% 0
NRG 5 115.3 0.81% 1 NRG 5 115.3 0.81% 1
NU 4279.6 30.18% 911 NU 4279.6 30.18% 911
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 10.8 0.08% 0 PMLP 10.8 0.08% 0
SC 0.0 0.00% 0 SC 0.0 0.00% 0
SELP 2.2 0.02% 0 SELP 2.2 0.02% 0
SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0
TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0
TMLP 15.4 0.11% 0 TMLP 15.4 0.11% 0
UI 384.2 2.71% 7 UI 384.2 2.71% 7
UNITIL 18.7 0.13% 0 UNITIL 18.7 0.13% 0
USG 4 2746.8 19.37% 375 USG 4 2746.8 19.37% 375
VTGP 157.7 1.11% 1 VTGP 157.7 1.11% 1
NY 1675.0 11.81% 140 NY 1675.0 11.81% 140
NB 700.0 4.94% 24 NB 700.0 4.94% 24
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 14179.7 100.00% Total 14179.7 100.00%
HHI 1606.77 HHI 1611.52
Change in HHI 4.75
Source: Reed Report at Table 10.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all
generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 9 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Shoulder Peak
Pre-Merger Post-Merger
Total Total
Shoulder Share of Shoulder Share of
Capacity Shoulder Square of Capacity Shoulder Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 133.2 0.80% 1
NEP 2 354.9 2.14% 5 EUA/NEP 488.1 2.94% 9
BECO/CES 1334.9 8.04% 65 BECO/CES 1334.9 8.04% 65
BELD 6.1 0.04% 0 BELD 6.1 0.04% 0
BHE 108.6 0.65% 0 BHE 108.6 0.65% 0
BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0
CLNP 5 56.8 0.34% 0 CLNP 5 56.8 0.34% 0
CMEEC 84.3 0.51% 0 CMEEC 84.3 0.51% 0
CMLP 25.6 0.15% 0 CMLP 25.6 0.15% 0
CMP 828.4 4.99% 25 CMP 828.4 4.99% 25
CV 256.5 1.54% 2 CV 256.5 1.54% 2
DPA 0.0 0.00% 0 DPA 0.0 0.00% 0
DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0
FGE 50.1 0.30% 0 FGE 50.1 0.30% 0
FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0
GBPC 3 174.7 1.05% 1 GBPC 3 174.7 1.05% 1
GMP 202.8 1.22% 1 GMP 202.8 1.22% 1
HGE 5.7 0.03% 0 HGE 5.7 0.03% 0
HLPD 7.3 0.04% 0 HLPD 7.3 0.04% 0
HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0
IMEL 52.4 0.32% 0 IMEL 52.4 0.32% 0
IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0
IPPA 38.2 0.23% 0 IPPA 38.2 0.23% 0
MGED 2.9 0.02% 0 MGED 2.9 0.02% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 298.6 1.80% 3 MMWEC 298.6 1.80% 3
MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0
NAED 1.5 0.01% 0 NAED 1.5 0.01% 0
NHCO 25.3 0.15% 0 NHCO 25.3 0.15% 0
NRG 5 115.3 0.69% 0 NRG 5 115.3 0.69% 0
NU 4984.6 30.02% 901 NU 4984.6 30.02% 901
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 10.8 0.07% 0 PMLP 10.8 0.07% 0
SC 0.0 0.00% 0 SC 0.0 0.00% 0
SELP 2.2 0.01% 0 SELP 2.2 0.01% 0
SITHE 388.1 2.34% 5 SITHE 388.1 2.34% 5
TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0
TMLP 15.4 0.09% 0 TMLP 15.4 0.09% 0
UI 1463.4 8.81% 78 UI 1463.4 8.81% 78
UNITIL 18.6 0.11% 0 UNITIL 18.6 0.11% 0
USG 4 3031.9 18.26% 333 USG 4 3031.9 18.26% 333
VTGP 147.9 0.89% 1 VTGP 147.9 0.89% 1
NY 1675.0 10.09% 102 NY 1675.0 10.09% 102
NB 700.0 4.22% 18 NB 700.0 4.22% 18
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 16604.0 100.00% Total 16604.0 100.00%
1542.70 1546.13
Change in HHI 3.43
Source: Reed Report at Table 7.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all
generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 10 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Shoulder Off Peak
Pre-Merger Post-Merger
Total Total
Shoulder Share of Shoulder Share of
Capacity Shoulder Square of Capacity Shoulder Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 133.2 1.07% 1
NEP 2 354.9 2.85% 8 EUA/NEP 488.1 3.92% 15
BECO/CES 1334.9 10.72% 115 BECO/CES 1334.9 10.72% 115
BELD 6.1 0.05% 0 BELD 6.1 0.05% 0
BHE 108.6 0.87% 1 BHE 108.6 0.87% 1
BPDI 0.0 0.00% 0 BPDI 0.0 0.00% 0
CLNP 5 56.8 0.46% 0 CLNP 5 56.8 0.46% 0
CMEEC 75.9 0.61% 0 CMEEC 75.9 0.61% 0
CMLP 25.6 0.21% 0 CMLP 25.6 0.21% 0
CMP 828.4 6.65% 44 CMP 828.4 6.65% 44
CV 256.5 2.06% 4 CV 256.5 2.06% 4
DPA 0.0 0.00% 0 DPA 0.0 0.00% 0
DUKE 0.0 0.00% 0 DUKE 0.0 0.00% 0
FGE 29.1 0.23% 0 FGE 29.1 0.23% 0
FPL 5 0.0 0.00% 0 FPL 5 0.0 0.00% 0
GBPC 3 174.7 1.40% 2 GBPC 3 174.7 1.40% 2
GMP 202.8 1.63% 3 GMP 202.8 1.63% 3
HGE 5.7 0.05% 0 HGE 5.7 0.05% 0
HLPD 7.3 0.06% 0 HLPD 7.3 0.06% 0
HMLP 1.7 0.01% 0 HMLP 1.7 0.01% 0
IMEL 52.4 0.42% 0 IMEL 52.4 0.42% 0
IMLD 0.0 0.00% 0 IMLD 0.0 0.00% 0
IPPA 38.2 0.31% 0 IPPA 38.2 0.31% 0
MGED 2.9 0.02% 0 MGED 2.9 0.02% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 290.2 2.33% 5 MMWEC 290.2 2.33% 5
MPLP 0.0 0.00% 0 MPLP 0.0 0.00% 0
NAED 1.5 0.01% 0 NAED 1.5 0.01% 0
NHCO 25.3 0.20% 0 NHCO 25.3 0.20% 0
NRG 5 115.3 0.91% 1 NRG 5 113.2 0.91% 1
NU 4220.0 33.88% 1148 NU 4220.0 33.88% 1148
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 10.8 0.09% 0 PMLP 10.8 0.09% 0
SC 0.0 0.00% 0 SC 0.0 0.00% 0
SELP 2.2 0.02% 0 SELP 2.2 0.02% 0
SITHE 0.0 0.00% 0 SITHE 0.0 0.00% 0
TCPM 4, 5 0.0 0.00% 0 TCPM 4, 5 0.0 0.00% 0
TMLP 15.4 0.12% 0 TMLP 15.4 0.12% 0
UI 383.8 3.08% 9 UI 383.8 3.08% 9
UNITIL 18.6 0.15% 0 UNITIL 18.6 0.15% 0
USG 4 1156.9 9.29% 86 USG 4 1156.9 9.29% 86
VTGP 147.9 1.19% 1 VTGP 147.9 1.19% 1
NY 1675.0 13.45% 181 NY 1675.0 13.45% 181
NB 700.0 5.62% 32 NB 700.0 5.62% 32
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 12456.7 100.00% Total 12456.7 100.00%
1642.46 1648.55
Change in HHI 6.09
Source: Reed Report at Table 10.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested all
generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-1
Page 11 of 11
Analysis of the Acquisition of EUA by NEES Based Upon the Reed Report
Economic Capacity Analysis, Super Peak
Pre-Merger Post-Merger
Total Total
Summer Share of Summer Share of
Capacity Summer Square of Capacity Summer Square of
Company Notes (MW) Capacity Share Company Notes (MW) Capacity Share
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
EUA 1 132.9 0.52% 0
NEP 2 409.1 1.60% 3 EUA/NEP 542.0 2.12% 4
BECO/CES 1938.2 7.58% 57 BECO/CES 1938.2 7.58% 57
BELD 70.0 0.27% 0 BELD 70.0 0.27% 0
BHE 155.9 0.61% 0 BHE 155.9 0.61% 0
BPDI 265.9 1.04% 1 BPDI 265.9 1.04% 1
CLNP 5 231.3 0.90% 1 CLNP 5 231.3 0.90% 1
CMEEC 159.4 0.62% 0 CMEEC 159.4 0.62% 0
CMLP 25.5 0.10% 0 CMLP 25.5 0.10% 0
CMP 1390.9 5.44% 30 CMP 1390.9 5.44% 30
CV 299.8 1.17% 1 CV 299.8 1.17% 1
DPA 168.0 0.66% 0 DPA 168.0 0.66% 0
DUKE 480.0 1.88% 4 DUKE 480.0 1.88% 4
FGE 51.1 0.20% 0 FGE 51.1 0.20% 0
FPL 5 16.2 0.06% 0 FPL 5 16.2 0.06% 0
GBPC 3 174.7 0.68% 0 GBPC 3 174.7 0.68% 0
GMP 241.0 0.94% 1 GMP 241.0 0.94% 1
HGE 31.6 0.12% 0 HGE 31.6 0.12% 0
HLPD 13.4 0.05% 0 HLPD 13.4 0.05% 0
HMLP 5.8 0.02% 0 HMLP 5.8 0.02% 0
IMEL 52.4 0.20% 0 IMEL 52.4 0.20% 0
IMLD 2.8 0.01% 0 IMLD 2.8 0.01% 0
IPPA 34.1 0.13% 0 IPPA 34.1 0.13% 0
MGED 2.8 0.01% 0 MGED 2.8 0.01% 0
MMLD 0.0 0.00% 0 MMLD 0.0 0.00% 0
MMWEC 547.7 2.14% 5 MMWEC 547.7 2.14% 5
MPLP 149.0 0.58% 0 MPLP 149.0 0.58% 0
NAED 13.5 0.05% 0 NAED 13.5 0.05% 0
NHCO 25.3 0.10% 0 NHCO 25.3 0.10% 0
NRG 5 113.2 0.44% 0 NRG 5 113.2 0.44% 0
NU 6961.9 27.23% 742 NU 6961.9 27.23% 742
PMLD 0.2 0.00% 0 PMLD 0.2 0.00% 0
PMLP 24.7 0.10% 0 PMLP 24.7 0.10% 0
SC 531.8 2.08% 4 SC 531.8 2.08% 4
SELP 2.2 0.01% 0 SELP 2.2 0.01% 0
SITHE 1776.2 6.95% 48 SITHE 1776.2 6.95% 48
TCPM 4, 5 373.9 1.46% 2 TCPM 4, 5 373.9 1.46% 2
TMLP 103.8 0.41% 0 TMLP 103.8 0.41% 0
UI 1451.0 5.68% 32 UI 1451.0 5.68% 32
UNITIL 32.8 0.13% 0 UNITIL 32.8 0.13% 0
USG 4 4563.7 17.85% 319 USG 4 4563.7 17.85% 319
VTGP 167.0 0.65% 0 VTGP 167.0 0.65% 0
NY 1675.0 6.55% 43 NY 1675.0 6.55% 43
NB 700.0 2.74% 7 NB 700.0 2.74% 7
WBSH 5 0.0 0.00% 0 WBSH 5 0.0 0.00% 0
- -----------------------------------------------------------------------------------------------------------------------------------
Total 25565.8 100.0% Total 25565.8 100.00%
1302.79 1304.45
Change in HHI 1.66
Source: Reed Report at Table 10.
Notes:
1. Reed Report uses 1998 CELT report capacity figures minus the divestiture of Canal 1 as EUA's capacity. EUA has divested
all generation resources other than its entitlements in Millstone 3, Pilgrim, and Vermont Yankee.
2. NEES has divested all generation resources other than its entitlements in Millstone 3, Seabrook 1, Vermont Yankee, and Wyman
4.
3. EUA divested 33.7 MW of generation capacity to GBPC.
4. NEP divested generation resources to USG, including its entitlements in Ocean State Power 1 and 2, which USG then transferred
to TCPM. After adjusting for the sale to TCPM, the difference between the capacity attributed by Reed to NEP and actual NEP
capacity is attributed to USG.
5. Company not included in the Reed Report. Resources attributed to this company were acquired from EUA.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-2
Page 1 of 2
Analysis of the Acquisition of EUA by NEES Based Upon Pace Report
Total Installed Capability
1999 - 2000
- ---------------------------------------------------------------------------------------------
Sum-1999 Win-1999 Sum-2000 Win-2000
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Total Capacity 25,660 26,022 25,681 26,022
New England Power Capacity (MW) 401.75 407.46 401.75 407.46
Montaup Capacity (MW) 130.1 131.3 130.1 131.3
New England Power Share 1.57% 1.57% 1.56% 1.57%
Montaup Share 0.51% 0.50% 0.51% 0.50%
Change in HHI* 1.59 1.58 1.59 1.58
Sources: Total Installed Capacity from Pace Report.
Capacity Figures from 1999 CELT Report.
Notes: *Change in HHI due to the NEES/EUA transaction is two times the product of the NEES
and EUA capability shares.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-3
Page 2 of 2
Analysis of the Acquisition of EUA by NEES Based Upon the Pace Report
Total Economic Capacity
1998 and 2000
- -----------------------------------------------------------------------------------------------------
Spr-98 Sum-98 Fal-98 Win-98 Spr-00 Sum-00 Fal-00 Win-00
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Economic 9174 9326 9373 9748 9226 9343 9389 9855
Capacity (MW)
New England Power (MW)* 252.79 341.67 323.73 318.79 252.47 341.61 323.61 319.19
Montaup (MW)* 85.22 114.31 107.75 106.18 85.12 114.3 107.71 106.3
New England Power Share 2.76% 3.66% 3.45% 3.27% 2.74% 3.66% 3.45% 3.24%
Montaup Share 0.93% 1.23% 1.15% 1.09% 0.92% 1.22% 1.15% 1.08%
Change in HHI** 5.12 8.98 7.94 7.12 5.05 8.95 7.91 6.99
Source: Pace Report.
Notes: * Assumes all entitlements for EUA and NEES are included in total economic capacity.
**Change in HHI due to the NEES/EUA transaction is two times the product of the NEES and
EUA total economic capacity shares.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-3
Page 1 of 2
Analysis of the Acquisition of EUA by NEES Based Upon the Hieronymous Report
Total Installed Capability
July 1997 - December 1999
- ----------------------------------------------------------------------------------------------------------------------------
Jul-97 Aug-97 Sep-97 Oct-97 Nov-97 Dec-97 Jan-98 Feb-98 Mar-98 Apr-98
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Total Installed Capability (MW) 26809 26809 26809 27255 26607 26607 26607 26607 26607 26607
New England Power Capability (MW)* 401.75 401.75 401.75 407.46 407.46 407.46 407.46 407.46 407.46 401.75
Montaup Capability (MW)* 130.1 130.1 130.1 131.3 131.3 131.3 131.3 131.3 131.3 130.1
New England Power Share 1.52% 1.52% 1.52% 1.49% 1.53% 1.53% 1.51% 1.51% 1.51% 1.51%
Montaup Share 0.49% 0.49% 0.49% 0.48% 0.49% 0.49% 0.49% 0.49% 0.49% 0.49%
Change in HHI** 1.13 1.13 1.13 1.08 1.16 1.16 1.11 1.11 1.11 1.11
- ----------------------------------------------------------------------------------------------------------------------------
May-98 Jun-98 Jul-98 Aug-98 Sep-98 Oct-98 Nov-98 Dec-98 Jan-99 Feb-99
- ----------------------------------------------------------------------------------------------------------------------------
Total Installed Capability (MW) 27255 26809 26809 26809 26809 27255 27255 27255 27255 27255
New England Power Capability (MW)* 401.75 401.75 401.75 401.75 401.75 407.46 407.46 407.46 407.46 407.46
Montaup Capability (MW)* 130.1 130.1 130.1 130.1 130.1 131.3 131.3 131.3 131.3 131.3
New England Power Share 1.47% 1.50% 1.52% 1.52% 1.52% 1.49% 1.49% 1.49% 1.49% 1.49%
Montaup Share 0.48% 0.49% 0.49% 0.49% 0.49% 0.48% 0.48% 0.48% 0.48% 0.48%
Change in HHI** 1.04 1.09 1.13 1.13 1.13 1.08 1.08 1.08 1.08 1.08
- ----------------------------------------------------------------------------------------------------------------------------
Mar-99 Apr-99 May-99 Jun-99 Jul-99 Aug-99 Sep-99 Oct-99 Nov-99 Dec-99
- ----------------------------------------------------------------------------------------------------------------------------
Total Installed Capability (MW) 27255 27255 27255 26809 26809 26809 26809 27255 27255 27255
New England Power Capability (MW)* 407.46 401.75 401.75 401.75 401.75 401.75 401.75 407.46 407.46 407.46
Montaup Capability (MW)* 131.3 130.1 130.1 130.1 130.1 130.1 130.1 131.3 131.3 131.3
New England Power Share 1.49% 1.49% 1.49% 1.50% 1.50% 1.50% 1.50% 1.49% 1.49% 1.49%
Montaup Share 0.48% 0.48% 0.48% 0.49% 0.49% 0.49% 0.49% 0.48% 0.48% 0.48%
Change in HHI** 1.08 1.04 1.04 1.09 1.09 1.09 1.09 1.08 1.08 1.08
Sources: New England Power and Montaup capabilities from 1999 CELT Report.
Total Installed capability from Hieronymous Report at WHH-12.
Notes: *Summer capabilities used for April - September. Winter capabilities used for October - March.
**Change in HHI due to the NEES/EUA transaction is two times the product of the NEES and EUA capability shares.
<PAGE>
<CAPTION>
[LECG Logo]
New England Power Company, et al.
Docket No. EC 99-____
Workpaper HJK-3
Page 2 of 2
Analysis of the Acquisition of EUA by NEES Based Upon the Hieronymous Report
Total Energy
1998-1999
Company Plant MWh
- --------------------------------------------------------------------------------
<S> <C> <C>
New England Power Millstone 31 302,413
New England Power Seabrook 12 791,206
New England Power Vermont Yankee 3 767,214*
New England Power Wyman 42 74,825
Montaup Millstone 31 99,300
Montaup Vermont Yankee3 95,998**
Montaup Pilgrim4 474,147***
- --------------------------------------------------------------------------------
1998 1999
- --------------------------------------------------------------------------------
Total Energy5 58,741,078 59,788,486
New England Power Energy (MWh) 1,935,658 1,935,658
Montaup Energy (MWh) 669,445 669,445
New England Power 3.30% 3.24%
Montaup 1.14% 1.12%
Change in HHI**** 7.51 7.25
</TABLE>
Source: 1. Milestone 3 MWh data from Montaup and New England Power's 1997
FERC Form 1.
2. Seabrook 1 and Wyman 4 MWh data from New England Power's 1998
FERC Form 1.
3. Vermont Yankee MWh data from Vermont Yankee Nuclear Power
Corporation 1998 FERC Form 1.
4. Pilgrim MWh from Boston Edison Company's 1998 FERC Form 1.
5. Total Energy from Hieronymous Report at WHH-13.
Notes: * Vermont Yankee's total production listed in the 1998 FERC Form 1
is 4,266,866 MWh. New England Power's Vermont Yankee entitlement
is 17.982% of plant capacity.
** Vermont Yankee's total production listed in the 1998 FERC Form 1
is 4,266,866 MWh. Montaup's Vermont Yankee entitlement is 2.25%
of plant capacity.
*** Pilgrim's total production listed in the 1998 FERC Form 1 is
4,310,431 MWh. Montaup's Pilgrim entitlement is 11% of plant
capacity.
**** Change in HHI due to the NEES/EUA transaction is two times the
product of the NEES and EUA energy shares.
<PAGE>
[LECG Logo] Attachment 2
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-_____
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
Declaration of Henry J. Kahwaty
I, Henry J. Kahwaty, declare:
1. My name is Henry J. Kahwaty. I am a Senior Managing Economist with LECG
(formerly Law & Economics Consulting Group, Inc.). LECG is a firm providing
management consulting and expert analysis in the areas of economics,
finance, and accounting. My business address is 1600 M. Street, N.W., Suite
700, Washington, D.C. 20036.
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
2. I received my Ph.D. in Economics from the University of Pennsylvania in
1991. My fields of specialization include industrial organization and
public economics. Industrial organization involves the study of competition
and regulation in individual markets. Prior to joining LECG, I worked for
nearly four years as an economist for the Antitrust Division of the U.S.
Department of Justice. I have analyzed the competitive implications of
numerous mergers, both during my employment with the Antitrust Division and
with LECG. I have worked on competition issues in electricity,
telecommunications, and other network industries, and I have broad
experience in applied microeconomics analysis. A copy of my curriculum
vitae is attached to this Declaration.
3. I submitted a Declaration analyzing the competitive implications of the
proposed acquisition of New England Electric System ("NEES") by the
National Grid Group plc ("National Grid") in Docket No. EC99-49-000 dated
March 8, 1999, and filed March 10, 1999. My analysis demonstrated that the
proposed acquisition of NEES by National Grid does not raise horizontal
competitive concerns because NEES and National Grid affiliates do not
provide competing products or services in any relevant geographic market.
In addition, the proposed acquisition of NEES by National Grid does not
2
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
raise vertical concerns because NEES and National Grid affiliates do not
provide inputs, such as fuel supplies, used in the production or delivery
of electric products or services in the region(s) served by the other.
4. I have been asked by counsel for New England Power Company ("New England
Power"), Montaup Electric Company ("Montaup"), and National Grid to
consider whether the acquisition of Eastern Utilities Associates ("EUA") by
NEES alters my analysis of the competitive implications of the proposed
acquisition of NEES by National Grid.1 This Declaration summarizes my
analysis of this question.
5. My conclusion, that the acquisition of NEES by National Grid will not harm
competition, is not altered by NEES's proposed acquisition of EUA. The NEES
and EUA systems are similar in that neither system provides competing
products or services in any relevant geographic market presently served by
National Grid or its affiliates. In addition, EUA's and National Grid's
affiliates do not provide inputs into the production or delivery of
electricity in the regions served by the other. Furthermore, NEES's and
EUA's affiliates will continue to provide transmission and distribution
service under open access tariffs after the completion of the EUA
acquisition. As a result, the acquisition of EUA by NEES does not alter my
conclusion that the acquisition of NEES by National Grid will not harm
competition.
6. EUA is a holding company whose affiliates own and operate electric
transmission and distribution assets in Massachusetts and Rhode Island. In
particular, EUA subsidiary Montaup owns transmission assets in
Massachusetts and leases transmission facilities from
- ---------------
1 New England Power is a subsidiary of NEES, and Montaup is a subsidiary of
EUA.
3
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
affiliates in both Massachusetts and Rhode Island. The EUA distribution
companies include Eastern Edison Company, Blackstone Valley Electric
Company, and Newport Electric Corporation. Eastern Edison Company provides
distribution service in Massachusetts, and both Blackstone Valley Electric
Company and Newport Electric Corporation provide distribution service in
Rhode Island. The EUA distribution companies do not provide transmission
services. EUA also owns several unregulated companies active in
energy-related businesses, including the energy management company, Cogenex
Corporation.
7. As with New England Power, Montaup has also sold or entered into agreements
to sell nearly all of its generation assets to other companies pursuant to
electric utility restructuring legislation and settlement agreements
approved by regulators in Rhode Island, Massachusetts, and at the Federal
Energy Regulatory Commission ("FERC"). Prior to its divestitures, Montaup
owned or held equity interest in approximately 570 MW of generation
capacity, all in New England, and held power purchase entitlements in an
additional 500 MW. Montaup, however, recently has sold or entered into
agreements to sell its fossil and hydroelectric generation capacity. It has
also signed agreements for the transfer of power purchase contracts and for
a buyout of its 11 percent power entitlement from the Pilgrim nuclear
generation station. Overall, Montaup has sold or agreed to sell or transfer
assets and rights to purchase power entitlements to Constellation Power
Source (an affiliate of Baltimore Gas and Electric Co.), NRG Energy (an
affiliate of Northern States Power), FPL
4
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
Group, BayCorp Holdings (an affiliate of Great Bay Power), Southern Energy
(an affiliate of Southern Company), TransCanada Power Marketing, and
others.2
8. Montaup's remaining generation resources are minority shares in three
nuclear generating stations. In particular, Montaup owns entitlements to
4.01 percent of the Millstone 3 and 2.25 percent of the Vermont Yankee
nuclear plants.3 In addition, Montaup has a purchased power agreement with
Entergy giving Montaup an entitlement to 11 percent of the output of the
Pilgrim nuclear station in 1999. This entitlement declines over time and
ends after 2004.4) These resources represent a total of approximately 131
MW of generation capacity currently, declining to 57 MW after 2004.
9. National Grid was formed in 1990 as part of the privatization of the
electric industry in England and Wales. National Grid and its subsidiaries
own and operate the transmission system in England and Wales and they also
operate the interconnections between this system and the transmission
systems in Scotland and France. In addition, National Grid, through its
- ---------------
2 These affiliates include New England Electric Transmission Corporation, New
England Hydro-Transmission Corporation, and New England Hydro- Transmission
Electric Company, Inc.
3 NEPOOL Forecast of Capacity, Energy, Loads and Transmission, April 1, 1999
at 15. Montaup owns 2.5 percent of Vermont Yankee, but it has resold a
portion to a group of municipals.
5
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
subsidiary, National Grid ("NGC") serves as a power market matching the
generation of electricity with demand on a real time basis. NGC also
facilitates the trading of power in the electricity market by managing the
daily bidding system for generators desiring to sell power, calculating
market prices and payments due by individual traders, and managing the
transfer of funds to settle electricity trades. Prior to 1996, the regional
electricity companies in England and Wales owned National Grid. In
December, 1995, however, National Grid was floated as a separate company on
the London Stock Exchange.
10. National Grid also owns and, through subsidiaries, operates transmission
assets outside of the U.K., including assets in Argentina and Zambia. In
particular, National Grid, through a subsidiary, owns 41.25 percent of
Transener, the main Argentine transmission company. National Grid also
jointly (with CINergy Global) owns 80 percent of the Power Division of
Zambia Consolidated Copper mines. National Grid has been selected to build
a transmission line in southern India as part of a joint venture with the
Karnataka Electricity Board. Neither National Grid nor any of its
subsidiaries owns or operates any transmission assets in the United States,
Canada, or Mexico.
11. Neither National Grid nor any of its subsidiaries provides transmission or
distribution services in any geographic area that overlaps with the areas
served by the EUA companies. EUA's affiliates provide transmission and
distribution services solely in the northeastern United States. National
Grid and its subsidiaries do not provide transmission or distribution
services in the northeastern United States or elsewhere in North America.
EUA's
- ---------------
4 Montaup presently has a life-of-unit purchase power agreement with Boston
Edison Company covering 11 percent of the energy generated by the Pilgrim
station. Boston Edison Company is selling Pilgrim to Entergy Nuclear
Generating Company, and Montaup has an agreement with Entergy Nuclear
Generating to purchase power from this unit. The purchase power agreement
entitles Montaup to the 11 percent of the output of the Pilgrim station in
1999, and this entitlement declines to 8.8 percent in 2002, 5.5 percent in
2003 and 2004, and ends thereafter.
6
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
transmission or distribution customers presently cannot turn to
National Grid or its subsidiaries as alternative providers of these
services.
12. With regard to electric generation services, the EUA companies do not
provide electric generation services in any geographic area that overlaps
with National Grid or its subsidiaries. Montaup has sold nearly all of its
generation assets and does not have operating control over the generation
plants in which it continues to hold entitlements. EUA's remaining
generation interests are located in New England. Neither National Grid nor
any of its present subsidiaries owns or controls any generation facilities
located in New England or elsewhere in North America.
13. The FERC has recognized that mergers involving firms serving no common
geographic markets typically do not raise competitive concerns. In its
Policy Statement on mergers, the FERC stated:
[I]t will not be necessary for the merger applicants to perform the
screen analysis or file data needed for the screen analysis in cases
where the merging firms do not have facilities or sell relevant
products in common geographic markets. In these cases, the proposed
merger will not have an adverse competitive impact (i.e., there can be
no increase in the applicants' market power unless they are selling
relevant products in the same geographic markets) so there is no need
for a detailed analysis.5
- ---------------
5 Inquiry Concerning the Commission's Merger Policy Under the Federal Power
Act: Policy Statement, [("Policy Statement")] Order No. 592, 77 FERC 61,263
(1996).
7
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
14. This is consistent with the Horizontal Merger Guidelines jointly issued by
the Department of Justice and the Federal Trade Commission.6 The Horizontal
Merger Guidelines is the statement of the horizontal merger enforcement
policy of these two agencies under the federal antitrust statutes.
Horizontal mergers are mergers involving companies that compete in one or
more markets. The Horizontal Merger Guidelines state:
A merger is unlikely to create or enhance market power or facilitate
its exercise unless it significantly increases concentration and
results in a concentrated market, properly defined and measured.
Mergers that either do not significantly increase concentration or do
not result in a concentrated market ordinarily require no further
analysis.7
Because National Grid, its subsidiaries, and the EUA companies do not
provide any products or services in any overlapping relevant markets, this
transaction is not a horizontal merger and will not result in the
elimination of a competitor in any market. As a result, I conclude that the
combination of EUA's assets with those of National Grid will not result in
competitive harm due to the creation or enhancement of market power.
15. Neither National Grid nor its subsidiaries presently provide fuel supplies,
fuel transportation services, equipment, or other inputs used in the
production or delivery of electric products or services in the region
served by the EUA companies - the northeastern United States. Similarly,
the EUA companies do not supply inputs used in the production or delivery
of
- ---------------
6 The Horizontal Merger Guidelines were issued April 2, 1992 and revised
April 8, 1997. www.usdoj.gov/atr/public/guidelines/horiz book/hmg1.html.
7 Horizontal Merger Guidelines at section 1.0.
8
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
electricity in regions currently served by National Grid or its
subsidiaries. Neither the EUA companies nor National Grid and its
subsidiaries generate or market electricity in the geographic areas served
by the other. As a result, the combination of EUA's assets with those of
National Grid will not create or enhance incentives for the EUA companies,
National Grid, or its subsidiaries adversely to affect prices and output in
downstream electricity markets. In particular, this combination will not
create incentives for EUA's affiliates to restrict the access of
non-affiliates to the transmission or distribution systems of the EUA
companies.
16. Furthermore, EUA affiliates currently provide transmission and distribution
service to electric generators and power marketers under open access
tariffs. These assets will continue to be available for use by others under
open access tariffs after the completion of National Grid's acquisition of
NEES and NEES's acquisition of EUA. As a result, these acquisitions will
not affect the ability of EUA, NEES, or National Grid affiliates to
restrict access to these transmission or distribution assets. I conclude
that the combination of EUA and its subsidiaries with National Grid is not
a vertical merger and will not impact the incentive or ability of the EUA
companies, the NEES companies, National Grid, or its subsidiaries adversely
to affect competition through vertical effects such as foreclosure,
facilitating coordination, or regulatory evasion.8
- ---------------
8 My analysis is consistent with the FERC's current thinking on vertical
merger analysis. See Revised Filing Requirements Under Part 33 of the
Commission's Regulations, April 16, 1998, Docket No. RM98-4-000, slip op.
at 46-50.
9
<PAGE>
[LECG Logo] Declaration of Henry J. Kahwaty
17. I conclude that the proposed acquisition of EUA by NEES has no impact on
the competitive implications of NEES's acquisition by National Grid. In
particular, the combination of the NEES, EUA, and National Grid assets will
not result in harm to competition. Neither the NEES nor the EUA companies
currently compete with National Grid or its subsidiaries in any relevant
market. As a result, there is no horizontal overlap between the EUA
companies and National Grid and its subsidiaries, and thus there is no
prospect for the combination of EUA and National Grid to result in any
horizontal competitive effects, adverse or otherwise. In addition, neither
the EUA companies nor National Grid and its subsidiaries currently supply
inputs used in the generation or delivery of electric products or services
in regions served by the other. Also, EUA's transmission and distribution
facilities will continue to be available for use under open access tariffs.
As a result, the ultimate combination of National Grid with NEES and EUA
will not result in anticompetitive effects arising from vertical concerns.
I declare under penalty of perjury that the foregoing is true and correct.
/s/ HENRY J. KAHWATY
----------------------------------------
Henry J. Kahwaty
Signed on this 5th day of May, 1999
<PAGE>
[LECG Logo]
HENRY J. KAHWATY
LECG
1600 M Street, N.W., Suite 700
Washington, D.C. 20036
Tel. (202) 466-4422
Fax (202) 466-4487
EDUCATION
Ph.D., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and
Sciences, Philadelphia, PA, 1991
Thesis Title: Essays on Vertical Relationships
Thesis Topic: Vertical Relationships with Asymmetric Information and
Incomplete Contracting
Specialty Areas: Industrial Organization, Public Economics, Monetary
Economics
M.A., Economics, UNIVERSITY OF PENNSYLVANIA, Graduate School of Arts and
Sciences, Philadelphia, PA, 1988
B.A. magna cum laude and Phi Beta Kappa, Mathematics and Economics,
UNIVERSITY OF PENNSYLVANIA, College of Arts and Sciences, Philadelphia, PA,
1986
PRESENT POSITION
LECG, Washington, D.C.
Senior Managing Economist, 1997-present
<PAGE>
[LECG Logo] Henry J. Kahwaty
Page 2
Senior Economist, 1995-1996
o Analysis of antitrust market definition.
o Analysis of the competitive effects resulting from mergers.
o Monopolization analysis.
o Analysis of competition issues in the electric utility industry,
including market-based pricing and deregulation proposals, mergers,
wholesale markets, and retail wheeling.
o Analysis of competition and other issues in telecommunications.
o Damage studies.
Consultant to Rational Software Corp. in proposed acquisition of Pure Atria
Corp., 1997.
Consultant to National Communications Association, Inc. in National
Communications Association, Inc. v. American Telephone and Telegraph
Company, 1997-1998.
<PAGE>
[LECG Logo] Henry J. Kahwaty
Page 2
Consultant to Public Service Enterprises of Pennsylvania, Inc. in
arbitration between Public Service Enterprises of Pennsylvania, Inc. and
AT&T Corporation, 1997-1998.
Consultant to Aptix Corporation in Aptix Corporation v. Quickturn Design
Systems, Inc., 1998.
Consultant to New England Electric System in proposed acquisition by
National Grid Group plc, 1999.
Consultant to New England Electric System in proposed acquisition of
Eastern Utilities Associates, 1999.
Experience with the following industries:
o Local and long distance telecommunications
o Computer software and software development tools
o Computer hardware, including microprocessors and modems
o Electricity
o Defense electronics
o Hardware emulation
<PAGE>
[LECG Logo] Henry J. Kahwaty
Page 3
PROFESSIONAL EXPERIENCE
U.S. DEPARTMENT OF JUSTICE, Antitrust Division, Economic Litigation
Section, 1991-1995
Economist
o Prepared economic models and analysis for antitrust cases.
o Prepared antitrust investigation plans.
o Reviewed civil investigative demands, second requests, subpoenas,
complaints, affidavits, and other documents.
o Assisted attorneys with gathering evidence, including conducting
witness interviews and assisting with witness depositions.
o Recommended whether to institute enforcement actions.
o Specialized in computer software, defense, and banking industries.
TESTIMONY
Provided deposition and trial testimony in National Communications
Association, Inc. v. American Telephone and Telegraph Company, 92 Civ. 1735
(LAP), U.S. District Court for the Southern District of New York, 1997-
1998.
Provided deposition testimony in Aptix Corporation v. Quickturn Design
Systems, Inc., C-96-20909 JF (EAI), U.S. District Court for the Northern
District of California, 1998.
SPEECHES
"Unregulated Affiliates and the Market Power Problem," Forum on Electric
Power Market Restructuring, Washington, D.C., February 19, 1999.
"Antitrust Damages," Litigation Services Subcommittee of the Greater
Washington Society of Certified Public Accountants, Washington, D.C.,
January 28, 1999.
<PAGE>
[LECG Logo] Henry J. Kahwaty
Page 4
TEACHING EXPERIENCE
UNIVERSITY OF PENNSYLVANIA, Philadelphia, PA, 1988-1991
o Industrial Organization
o Topics in Microeconomics
o Topics in Macroeconomics
o Intermediate Microeconomics
o Introductory Microeconomics
o Introductory Macroeconomics
UNPUBLISHED RESEARCH
"The Analysis of Market Concentration, Market Power and the Competitive
Effects of Mergers in the Electric Industry," with Richard J. Gilbert, June
1997.
RESEARCH INTERESTS
Oligopoly models, network externalities and asymmetric information.
PROFESSIONAL ACTIVITIES
Member, American Economic Association
Member, European Association for Research in Industrial Economics
Citizenship: United States of America April 1999
<PAGE>
Form of Notice
[FORM OF NOTICE]
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No.
NEW ENGLAND HYDRO-TRANSMISSION ) EC99-______
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
NOTICE OF FILING
Take notice that on May 5, 1999, New England Power Company ("NEP") and
its affiliates holding jurisdictional assets (Massachusetts Electric Company,
The Narragansett Electric Company, New England Electric Transmission
Corporation, New England Hydro-Transmission Corporation, New England
Hydro-Transmission Electric Company, Inc., and AllEnergy Marketing Company,
L.L.C.) (collectively, the "NEES Companies"), Montaup Electric Company and its
affiliates holding jurisdictional assets (Blackstone Valley Electric Company,
Eastern Edison Company, Newport Electric Corporation) (collectively, the "EUA
Companies"), and Research Drive LLC submitted for filing an application under
Section 203 of the Federal Power Act (16 U.S.C. section 824b) and Part 33 of the
Commission's Regulations (18 C.F.R. section 33.1 et seq. (1998)) seeking the
Commission's approval and related authorizations to effectuate a merger, the
result of which would be to merge New England Electric System ("NEES"), the
parent company of the NEES Companies, with the Eastern Utilities Associates
("EUA"), the parent company of the EUA Companies. Through the Merger, EUA will
<PAGE>
become a wholly-owned subsidiary of NEES, and will subsequently be consolidated
into NEES. In addition, the Application seeks the Commission's approval and
authorization for the subsequent mergers and consolidations of the complementary
operating companies of the two systems that hold jurisdictional assets. Finally,
the Application requests approval, if required, of the acquisition by The
National Grid Group plc ("National Grid") of the EUA Companies resulting from
the proposed merger of National Grid and NEES, approval of which has been sought
in Docket No. EC99-49-000.
The Application states that it (i) includes all the information and
exhibits required by Part 33 of the Commission's regulations and the
Commission's Merger Policy Statement with respect to the Merger; (ii)
incorporates by reference any additional materials required with respect to the
acquisition by National Grid of the EUA Companies; and (iii) easily satisfies
the criteria set forth in the Commission's Merger Policy Statement. The
Application requests that the Commission grant whatever waivers or
authorizations are needed and grant approval without condition, modification or
an evidentiary, trial-type hearing. The Application states that the parties are
seeking to close the Merger expeditiously and thus the Applicants have requested
Commission approval by July 31, 1999.
The Applicants have served copies of the filing on the state
commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island and
Vermont.
Any person desiring to be heard or to protest said application should
file a motion to intervene or protest with the Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426 in accordance with
Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 C.F.R.
385.211 and 18 C.F.R. 385.214). All such motions or protests should be filed on
or before __________. Protests will be considered by the Commission in
determining the appropriate action to be taken, but will not serve to make the
protestants parties to the proceeding. Any person wishing to become a party must
file a motion to intervene. Copies of this filing are on file with the
Commission and are available for public inspection.
2
<PAGE>
Verifications
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-_____
NEW ENGLAND HYDRO TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY LLC )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
VERIFICATION
Robert G. Powderly, being duly sworn upon oath, states that he is
Executive Vice-President of Montaup Electric Company, Blackstone Valley Electric
Company, Eastern Edison Company and Newport Electric Corporation and has read
the attached JOINT APPLICATION OF NEW ENGLAND POWER COMPANY et al. AND MONTAUP
ELECTRIC COMPANY et al. FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS; that
he knows the contents thereof; that the statements made therein are true and
correct to the best of his knowledge, information and belief; and that he has
full power and authority to sign this document on behalf of Montaup Electric
Company, Blackstone Valley Electric Company, Eastern Edison Company and Newport
Electric Corporation.
/s/ ROBERT G. POWDERLY
----------------------------------------
Robert G. Powderly
Executive Vice-President
Subscribed and sworn to before me this 26th day of April, 1999.
/s/ BARBRA L. DANTONO
----------------------------------------
Notary Public
My Commission expires March 30, 2001
--------------------
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-_____
NEW ENGLAND HYDRO TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY LLC )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
VERIFICATION
Michael E. Jesanis, being duly sworn upon oath, states that he is
Senior Vice President and Chief Financial Officer of New England Electric
System, and has read the attached JOINT APPLICATION OF NEW ENGLAND POWER COMPANY
et al. AND MONTAUP ELECTRIC COMPANY et al. FOR APPROVAL OF MERGER AND RELATED
AUTHORIZATIONS; that he knows the contents thereof; that the statements made
therein are true and correct to the best of his knowledge, information and
belief; and that he has full power and authority to sign this document on behalf
of the Applicants which are New England Electric System companies.
/s/ MICHAEL E. JESANIS
----------------------------------------
Michael E. Jesanis
Senior Vice President and
Chief Financial Officer
Subscribed and sworn to before me
this 28th day of April, 1999.
/s/ Sandra J. Brocher
- -----------------------------------
Notary Public
My Commission expires 8/19/2005
-------------
2
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-_____
NEW ENGLAND HYDRO TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY LLC )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
VERIFICATION
Jonathan M. G. Carlton, being duly sworn upon oath, states that he is
Business Development Manager, Regulation of The National Grid Group plc, and has
read the attached JOINT APPLICATION OF NEW ENGLAND POWER COMPANY et al. AND
MONTAUP ELECTRIC COMPANY et al. FOR APPROVAL OF MERGER AND RELATED
AUTHORIZATIONS; that he knows the contents thereof; that the statements made
therein are true and correct to the best of his knowledge, information and
belief; and that he has full power and authority to sign this document on behalf
of The National Grid Group plc.
/s/ JONATHAN M.G. CARLTON
----------------------------------------
Jonathan M.G. Carlton
Business Development Manager, Regulation
Subscribed and sworn to before me
this 28th day of April, 1999.
/s/ SANDRA J. BROCHER
- -----------------------------------
Notary Public
My Commission expires 8/19/2005
-------------
3
<PAGE>
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
AFFIDAVIT OF CHERYL A. LAFLEUR
I, Cheryl A. Lafleur, Secretary of New England Electric System which
is a business trust organized and existing under the laws of the Commonwealth of
Massachusetts, HEREBY CERTIFY that I have reviewed exhibits A, B, and G annexed
hereto and they are true and correct to the best of my knowledge.
IN WITNESS WHEREOF, I have hereunto subscribed my name this 27th day
of April, 1999.
/s/ CHERYL A. LAFLEUR
----------------------------------------
Cheryl A. LaFleur
Secretary
Subscribed and sworn to before me
this 27th day of April, 1999.
/s/ SANDRA J. BROCHER
- -----------------------------------
Notary Public
My Commission expires 8/19/2005
-------------
4
<PAGE>
UNITED STATES OF AMERICA
before the
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
AFFIDAVIT OF WILLIAM R. RICHER
I, William R. Richer, Manager of General Accounting of New England
Power Service Company, which provides accounting and other professional services
for the New England Electric System companies ("NEES companies") and which is a
corporation organized and existing under the laws of the Commonwealth of
Massachusetts, HEREBY CERTIFY that I have reviewed NEES companies' portions of
Exhibits C, D, E, and F annexed hereto and they are true and correct to the best
of my knowledge.
IN WITNESS WHEREOF, I have hereunto subscribed my name this 20th day
of April, 1999.
/s/ WILLIAM R. RICHER
----------------------------------------
William R. Richer
Manager of General Accounting
Subscribed and sworn to before me
this 20th day of April, 1999.
/s/ JOAN P. MORTIMER
- -----------------------------------
Notary Public
My Commission expires July 21, 2000
-----------------
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
AFFIDAVIT OF MICHAEL E. JESANIS
I, Michael E. Jesanis, Senior Vice President and Chief Financial
Officer of New England Electric System which is a business trust organized and
existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY
that I have reviewed Exhibit H annexed hereto and it is true and correct to the
best of my knowledge.
IN WITNESS WHEREOF, I have hereunto subscribed my name this 28th day
of April, 1999.
/s/ MICHAEL E. JESANIS
----------------------------------------
Michael E. Jesanis
Senior Vice President and
Chief Financial Officer
Subscribed and sworn to before me
this 28th day of April, 1999.
/s/ SANDRA J. BROCHER
- -----------------------------------
Notary Public
My Commission expires 8/19/2005
-------------
6
<PAGE>
UNITED STATES OF AMERICA
before the
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
AFFIDAVIT OF DOMENICO A. GUAETTA
I, Domenico A. Guaetta, Manager, Substation Design of New England
Power Service Company, which provides design and other professional services for
the New England Electric System companies and which is a corporation organized
and existing under the laws of the Commonwealth of Massachusetts, HEREBY CERTIFY
that I have reviewed Exhibit I annexed hereto and it is true and correct to the
best of my knowledge.
IN WITNESS WHEREOF, I have hereunto subscribed my name this 23rd day
of April, 1999.
/s/ DOMENICO A. GUAETTA
----------------------------------------
Domenico A. Guaetta
Manager, Substation Design
Subscribed and sworn to before me
this 23rd day of April, 1999.
/s/ DIANE J. CHAREST
- -----------------------------------
Notary Public
My commission expires April 23, 2004
------------------
7
<PAGE>
UNITED STATES OF AMERICA
before the
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
AFFIDAVIT OF
I, Clifford J. Hebert, Jr., Treasurer and Secretary of Eastern
Utilities Associates, which provides accounting and other professional services
for the Eastern Utilities Associates companies and which is a voluntary
association organized and existing under the laws of the Commonwealth of
Massachusetts, HEREBY CERTIFY that I have reviewed Exhibit(s) A-I annexed hereto
and they are true and correct to the best of my knowledge.
IN WITNESS WHEREOF, I have hereunto subscribed my name this 27th day
of April, 1999.
/s/ CLIFFORD J. HEBERT, JR.
----------------------------------------
Clifford J. Hebert, Jr.
Treasurer and Secretary
Subscribed and sworn to before me
this 27th day of April, 1999.
/s/ ROSE MARY ABRAMS
- -----------------------------------
Notary Public
My Commission expires May 6, 2005
---------------
8
<PAGE>
NEW ENGLAND ELECTRIC SYSTEM
Secretary's Certificate
The undersigned, the Secretary of New England Electric System, a
voluntary association created under the laws of The Commonwealth of
Massachusetts, DOES HEREBY CERTIFY, on behalf of the Association, that:
Attached hereto as Exhibit A is a true and correct copy of votes duly
adopted by The Board of Directors of the Association, and registered
with the Trustee, which Votes have not been revoked, modified,
amended, or rescinded and remain in full force and effect on the date
hereof, except as indicated therein.
IN WITNESS WHEREOF, the undersigned has executed and delivered this
certificate this 27th day of April, 1999.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ CHERYL A. LAFLEUR
-----------------------------------
Cheryl A. LaFleur
Secretary
Subscribed and sworn to before me
this 27th day of April, 1999.
/s/ SANDRA J. BROCHER
- -----------------------------------
Notary Public
My Commission expires 8/19/2005
-------------
9
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
Votes Adopted at
New England Electric System Board of Directors on January 30, 1999
VOTED: That Richard P. Sergel, President and Chief Executive Officer, and
Michael E. Jesanis, Senior Vice president and Chief Financial Officer,
are severally authorized to execute and deliver, in the name and on
behalf of the Company, The Agreement and Plan of Merger, by and among
Eastern Utilities Associates, a Merger Acquisition Subsidiary LLC of
the Company, and the Company (the Merger Agreement) specifying the
terms and conditions for the acquisition for cash of all the
outstanding common shares of Eastern Utilities Associates at a price
of $31.00 per share for an aggregate purchase price of up to $650
million, subject to adjustments as specified in the Merger Agreement;
said Merger Agreement to be substantially in the form presented to
this meeting, with such changes, additions, and modifications thereto
as the officer or officers executing the same shall approve, such
approval to be evidenced by the execution and delivery thereof.
That the officers of the Company are severally authorized, in the name
and on behalf of the Company, to form a Merger Acquisition Subsidiary
LLC as a Massachusetts limited liability company with the Company
having a ninety nine percent interest therein as a member (NEES
Global, Inc. having a one percent interest); said Merger acquisition
Subsidiary LLC being formed to execute and deliver the Merger
Agreement; and all acts done and taken in pursuance thereof are
authorized, approved, adopted, ratified, and confirmed.
10
<PAGE>
That the officers of the Company are severally authorized to execute
and deliver, in the name and on behalf of the Company, the Consent
Agreement between National Grid Group plc. and the Company, containing
the consent of National Grid Group plc to the Company's execution and
delivery of the Merger Agreement and with respect to certain actions
relating to the consummation of the transactions set forth therein;
said Consent Agreement to be substantially in the form presented to
this meeting, with such changes, additions, and modifications thereto
as the officer or officers executing the same shall approve, such
approval to be evidenced by the execution and delivery thereof.
11
<PAGE>
EASTERN UTILITIES ASSOCIATES
Secretary's Certificate
The undersigned, the Secretary of Eastern Utilities Associates, a
voluntary association created under the laws of The Commonwealth of
Massachusetts (the "Association"), DOES HEREBY CERTIFY, on behalf of the
Association, that:
Attached hereto as Exhibit A is a true and correct copy of votes
duly adopted by The Board of Trustees of the Association, which
Votes have not been revoked, modified, amended, or rescinded and
remain in full force and effect on the date hereof, except as
indicated therein.
IN WITNESS WHEREOF, the undersigned has executed and delivered this
certificate this 27th day of April, 1999.
EASTERN UTILITIES ASSOCIATES
By: /s/ CLIFFORD J. HEBERT, JR.
-----------------------------------
Clifford J. Hebert, Jr.
Secretary
Subscribed and sworn to before me
this 27th day of April, 1999.
/s/ ROSE MARY ABRAMS
- -----------------------------------
Notary Public
My Commission expires May 6, 2005
---------------
12
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Trustees' Authorization Resolutions
Votes Adopted by
Eastern Utilities Associates Board of Trustees on February 1, 1999
Attached
13
<PAGE>
SPECIAL MEETING OF TRUSTEES, FEBRUARY 1, 1999
Pursuant to the action taken at the January 31, 1999 Special Meeting
of the Trustees, a Special Meeting of the Trustees of Eastern Utilities
Associates was held at the office of the Association, One Liberty Square,
Boston, Massachusetts, on Monday, February 1, 1999 at 5:30 o'clock in the
forenoon.
There were present - Russell A. Boss (via conference telephone), Paul
J. Choquette, Jr. (via conference telephone), Peter S. Damon (via conference
telephone), Peter B. Freeman (via conference telephone), Larry A. Liebenow (via
conference telephone), Jacek Makowski (via conference telephone), Wesley W.
Marple, Jr. (via conference telephone) Donald G. Pardus, Margaret M. Stapleton
(via conference telephone), John R. Stevens and W. Nicholas Thorndike (via
conference telephone), being all of the Trustees.
Clifford J. Hebert, Jr., Treasurer and Secretary of the Association,
Henry A. Clark II (via conference telephone) and Robert N. Hoglund (via
conference telephone), Managing Directors, of Salomon Smith Barney, Inc.
("Salomon"); David P. Falck (via conference telephone) of Winthrop, Stimson,
Putnam & Roberts; and Arthur I. Anderson and David A. Fazzone (via conference
telephone) of McDermott, Will & Emery, Counsel for the Association, were also
present at the meeting.
Donald G. Pardus, Chairman, presided.
Arthur I. Anderson, Acting Secretary, kept the records of the meeting.
Mr. Pardus asked if there were any additional questions regarding the
proposed transaction with New England Electric System ("NEES"). A general
discussion then ensued with respect to several questions which were raised by
Trustees after review of the draft Merger Agreement.
14
<PAGE>
The representatives of Salomon indicated that they were prepared to
deliver their fairness opinion in connection with the NEES transaction as
contemplated by the Merger Agreement.
On motion duly made and seconded, the following votes were unanimously
adopted:
VOTED - that the form, terms and provisions of, and the transactions
contemplated by, that certain Agreement and Plan of Merger (the "Agreement") by
and among New England Electric System ("NEES"), Research Drive LLC ("LLC") and
the Association in the form presented to the Trustees, pursuant to which LLC
will be merged (the "Merger") into this Association and each Common Share of
this Association will be converted into and exchanged for $31 in cash, subject
to adjustment, be and it hereby is approved; and that the Chairman of the Board,
Donald G. Pardus, be, and he hereby is, acting singly, authorized and directed
to execute the Agreement and an acknowledgment of the Consent Agreement between
NEES and National Group PLC pertaining to the Merger on behalf of the
Association, with such changes, modifications and deletions as he so deems
necessary, the execution and delivery thereof to be conclusive evidence of his
authority so to act.
VOTED - that, in accordance with the terms and conditions of the
Agreement and the transactions contemplated thereby, the Chairman of the Board,
the Vice Chairman of the Board, the President, any Vice President, the
Treasurer, the Assistant Treasurer, the Secretary or any Assistant Secretary
(collectively, the "Authorized Officers") of the Association be, and each of
them hereby is, acting singly, authorized and directed to execute and file on
behalf of the Association, all necessary regulatory filings as may be required,
including, but not limited to, filings with the Department of Justice, the
Federal Trade Commission, the Federal Communications Commission, the Nuclear
Regulatory Commission, the Federal Energy Regulatory Commission, the Securities
and Exchange Commission (the "SEC") and any of the following states:
Massachusetts, New Hampshire, Maine, Connecticut, Vermont and Rhode Island, the
filing by such Authorized Officer or Authorized Officers to be conclusive
evidence of his or their authority so to act.
VOTED - that the Association cause a proxy statement (the "Proxy
Statement") to be prepared, in accordance with the requirements of the SEC,
setting forth the necessary information concerning the transactions contemplated
by the Agreement to obtain the required shareholder
15
<PAGE>
authorization for the consummation of the transactions contemplated by the
Agreement (including, without limitation, any required authorizations pursuant
to Article 37 of this Association's Declaration of Trust, as amended) and that
the Authorized Officers be, and each of them hereby is, acting singly,
authorized and directed, to file the Proxy Statement with the SEC, with such
provisions therein as the Authorized Officer or Authorized Officers filing the
Proxy Statement may deem necessary or desirable, the filing by such Authorized
Officer or Authorized Officers to be conclusive evidence of his or their
authority so to act.
VOTED - that the Trustees hereby declare that the Merger is advisable
and in the best interests of the Association and recommend to shareholders that
they approve the Merger.
VOTED - that the Authorized Officers of this Association be, and each
of them acting singly hereby is, authorized and empowered to do or cause to be
done all such acts or things and to sign and deliver, or cause to be signed and
delivered, all such documents, instruments and certificates (including, without
limitation, obtaining all required shareholder authorizations under Article 37
of this Association's Declaration of Trust, as amended) as such officer of this
Association may deem necessary, advisable or appropriate to effectuate or carry
out the purposes and intent of the foregoing votes and to perform the
obligations of this Association under the agreements and instruments referred to
therein.
16
<PAGE>
There being no further business to discuss, on motion duly made and
seconded, it was VOTED - to adjourn at 5:45 o'clock in the forenoon.
A true record.
Attest:
Acting Secretary
17
<PAGE>
National Grid Letterhead
The National Grid Group plc
IOSTA, Inc.
NGG Holdings LLC
Secretary's Certificate
The undersigned, Acting Secretary of The National Grid Group plc,
IOSTA, Inc., and NGG Holdings LLC, DO HEREBY CERTIFY on behalf of The National
Grid Group plc, IOSTA, Inc., and NGG Holdings LLC THAT:
Attached hereto as Exhibit A is a true and correct copy of Resolutions
duly adopted by the Boards of The National Grid Group plc, IOSTA,
Inc., and NGG Holdings LLC, which Resolutions have not been revoked,
modified, amended, or rescinded and remain in full force and effect on
the date hereof, except as indicated therein.
IN WITNESS WHEREOF, the undersigned has executed and delivered this
certificate this 28th day of April, 1999.
THE NATIONAL GRID GROUP plc
IOSTA, INC.
NGG HOLDINGS PLC
By: /s/ CLARE M. PHELAN
-----------------------------------
Clare M. Phelan
Acting Secretary
Signed and sworn to before me this
28th day of April, 1999.
/s/ SANDRA J. BROCHER
- -----------------------------------
Notary Public
My commission expires: 8/19/2005
-------------
18
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
Resolved at The National Grid Group plc Committee of the
Board of Directors Meeting on January 29, 1999
RESOLVED: Each of the Directors present confirmed that he had sufficiently
and carefully considered the terms of the Consent Agreement and,
accordingly, IT WAS RESOLVED that the Chairman or any one
Executive Director or Fiona Smith be and is hereby authorised to
agree any further amendments to and to execute and deliver on
behalf of the Company the Consent Agreement.
19
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Managers' Authorization Resolutions
Resolved at IOSTA, Inc. Meeting of the Managers on January 29, 1999
RESOLVED: It was noted that the Acquisition would be entered into by NEES
as soon as reasonably practicable after the date hereof AND IT
WAS ACCORDINGLY RESOLVED that subject to being satisfied as to
valuation and price, The National Grid Group plc be and is hereby
authorised to give consent to NEES to the entering into of the
Acquisition by way of entering into a Consent Agreement with
NEES.
20
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
Resolved at NGG Holdings LLC
Meeting of the Managers on January 29, 1999
RESOLVED: It was noted that the Acquisition would be entered into by NEES
as soon as reasonably practicable after the date hereof AND IT
WAS ACCORDINGLY RESOLVED that subject to being satisfied as to
valuation and price, The National Grid Group plc be and is hereby
authorised to give consent to NEES to the entering into of the
Acquisition by way of entering into a Consent Agreement with
NEES.
21
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70-000
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, et al.
AND MONTAUP ELECTRIC COMPANY, et al.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBITS
Edward Berlin, Esq. David A. Fazzone, Esq. of
Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and
Scott P. Klurfeld, Esq. McDermott, Will & Emery
Swidler Berlin Shereff Friedman, LLP 28 State Street
3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-4000
Washington, D.C. 20007-5116 (617) 535-4016
(202) 424-7500 Attorneys for Montaup Electric Company
and Affiliated Applicants
Thomas G. Robinson, Esq.
New England Power Company
25 Research Drive
Westborough, MA 01582
(508) 389-2877
Attorneys for New England Power
Company and Affiliated Applicants
May, 1999
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
<PAGE>
NEW ENGLAND ELECTRIC SYSTEM
Secretary's Certificate
The undersigned, the Secretary of New England Electric System, a
voluntary association created under the laws of The Commonwealth of
Massachusetts, DOES HEREBY CERTIFY, on behalf of the Association, that:
Attached hereto as Exhibit A is a true and correct copy of votes duly
adopted by The Board of Directors of the Association, and registered
with the Trustee, which Votes have not been revoked, modified,
amended, or rescinded and remain in full force and effect on the date
hereof, except as indicated therein.
IN WITNESS WHEREOF, the undersigned has executed and delivered this
certificate this 27th day of April, 1999.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Cheryl A. LaFleur
-----------------------------------
Cheryl A. LaFleur
Secretary
Signed and sworn to before me this
27th day of April, 1999.
/s/ Sandra J. Brochu
- -----------------------------------
Notary Public
My commission expires: 8/19/2005
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
Votes Adopted at
New England Electric System Board of Directors on January 30, 1999
VOTED: That Richard P. Sergel, President and Chief Executive Officer, and
Michael E. Jesanis, Senior Vice President and Chief Financial Officer,
are severally authorized to execute and deliver, in the name and on
behalf of the Company, The Agreement and Plan of Merger, by and among
Eastern Utilities Associates, a Merger Acquisition Subsidiary LLC of
the Company, and the Company (the Merger Agreement) specifying the
terms and conditions for the acquisition for cash of all the
outstanding common shares of Eastern Utilities Associates at a price
of $31.00 per share for an aggregate purchase price of up to $650
million, subject to adjustments as specified in the Merger Agreement;
said Merger Agreement to be substantially in the form presented to
this meeting, with such changes, additions, and modifications thereto
as the officer or officers executing the same shall approve, such
approval to be evidenced by the execution and delivery thereof.
That the officers of the Company are severally authorized, in the name
and on behalf of the Company, to form a Merger Acquisition Subsidiary
LLC as a Massachusetts limited liability company with the Company
having a ninety-nine percent interest therein as a member (NEES
Global, Inc. having a one percent interest); said Merger Acquisition
Subsidiary LLC being formed to execute and deliver the Merger
Agreement; and all acts done and taken in pursuance thereof are
authorized, approved, adopted, ratified, and confirmed.
<PAGE>
-2-
That the officers of the Company are severally authorized to execute
and deliver, in the name and on behalf of the Company, the Consent
Agreement between National Grid Group plc. and the Company, containing
the consent of National Grid Group plc to the Company's execution and
delivery of the Merger Agreement and with respect to certain actions
relating to the consummation of the transactions set forth therein;
said Consent Agreement to be substantially in the form presented to
this meeting, with such changes, additions, and modifications thereto
as the officer or officers executing the same shall approve, such
approval to be evidenced by the execution and delivery thereof.
<PAGE>
EASTERN UTILITIES ASSOCIATES
Secretary's Certificate
The undersigned, the Secretary of Eastern Utilities Associates, a
voluntary association created under the laws of The Commonwealth of
Massachusetts (the "Association"), DOES HEREBY CERTIFY, on behalf of the
Association, that:
Attached hereto as Exhibit A is a true and correct copy of votes
duly adopted by The Board of Trustees of the Association, which
Votes have not been revoked, modified, amended, or rescinded and
remain in full force and effect on the date hereof, except as
indicated therein.
IN WITNESS WHEREOF, the undersigned has executed and delivered this
certificate this 27th day of April, 1999.
EASTERN UTILITIES ASSOCIATES
By: /s/ Clifford J. Hebert, Jr.
-----------------------------------
Clifford J. Hebert, Jr.
Secretary
Signed and sworn to before me this
27th day of April, 1999.
/s/ Rose Mary Abrams
- -----------------------------------
Notary Public
My commission expires: May 6, 2005
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
Votes Adopted by
Eastern Utilities Associates Board of Trustees on February 1, 1999
Attached
<PAGE>
SPECIAL MEETING OF TRUSTEES, FEBRUARY 1, 1999
Pursuant to the action taken at the January 31, 1999 Special Meeting
of the Trustees, a Special Meeting of the Trustees of Eastern Utilities
Associates was held at the office of the Association, One Liberty Square,
Boston, Massachusetts, on Monday, February 1, 1999 at 5:30 o'clock in the
forenoon.
There were present - Russell A. Boss (via conference telephone), Paul
J. Choquette, Jr. (via conference telephone), Peter S. Damon (via conference
telephone), Peter B. Freeman (via conference telephone), Larry A. Liebenow (via
conference telephone), Jacek Makowski (via conference telephone), Wesley W.
Marple, Jr. (via conference telephone), Donald G. Pardus, Margaret M. Stapleton
(via conference telephone), John R. Stevens and W. Nicholas Thorndike (via
conference telephone), being all of the Trustees.
Clifford J. Hebert, Jr., Treasurer and Secretary of the Association,
Henry A. Clark II (via conference telephone) and Robert N. Hoglund (via
conference telephone), Managing Directors, of Salomon Smith Barney, Inc.
("Salomon"); David P. Falck (via conference telephone) of Winthrop, Stimson,
Putnam & Roberts; and Arthur I. Anderson and David A. Fazzone (via conference
telephone) of McDermott, Will & Emery, Counsel for the Association, were also
present at the meeting.
Donald G. Pardus, Chairman, presided.
Arthur I. Anderson, Acting Secretary, kept the records of the meeting.
Mr. Pardus asked if there were any additional questions regarding the
proposed transaction with New England Electric System ("NEES"). A general
<PAGE>
discussion then ensued with respect to several questions which were raised by
Trustees after review of the draft Merger Agreement.
The representatives of Salomon indicated that they were prepared to
deliver their fairness opinion in connection with the NEES transaction as
contemplated by the Merger Agreement.
On motion duly made and seconded, the following votes were unanimously
adopted:
VOTED - that the form, terms and provisions of, and the transactions
contemplated by, that certain Agreement and Plan of Merger (the "Agreement") by
and among New England Electric System ("NEES"), Research Drive LLC ("LLC") and
the Association in the form presented to the Trustees, pursuant to which LLC
will be merged (the "Merger") into this Association and each Common Share of
this Association will be converted into and exchanged for $31 in cash, subject
to adjustment, be and it hereby is approved; and that the Chairman of the Board,
Donald G. Pardus, be, and he hereby is, acting singly, authorized and directed
to execute the Agreement and an acknowledgment of the Consent Agreement between
NEES and National Group PLC pertaining to the Merger on behalf of the
Association, with such changes, modifications and deletions as he so deems
necessary, the execution and delivery thereof to be conclusive evidence of his
authority so to act.
VOTED - that, in accordance with the terms and conditions of the
Agreement and the transactions contemplated thereby, the Chairman of the Board,
the Vice Chairman of the Board, the President, any vice President, the
Treasurer, the Assistant Treasurer, the Secretary or any Assistant Secretary
(collectively, the "Authorized Officers") of the Association be, and each of
them hereby is, acting singly, authorized and directed to execute and file on
behalf of the Association, all necessary regulatory filings as may be required
including, but not limited to, filings with the Department of Justice, the
2
<PAGE>
Federal Trade Commission, the Federal Communications Commission, the Nuclear
Regulatory Commission, the Federal Energy Regulatory Commission, the Securities
and Exchange Commission (the "SEC") and any of the following states:
Massachusetts, New Hampshire, Maine, Connecticut, Vermont and Rhode Island, the
filing by such Authorized Officer or Authorized Officers to be conclusive
evidence of his or their authority so to act.
VOTED - that the Association cause a proxy statement (the "Proxy
Statement") to be prepared, in accordance with the requirements of the SEC,
setting forth the necessary information concerning the transactions contemplated
by the Agreement to obtain the required shareholder authorization for the
consummation of the transactions contemplated by the Agreement (including,
without limitation, any required authorizations pursuant to Article 37 of this
Association's Declaration of Trust, as amended) and that the Authorized Officers
be, and each of them hereby is, acting singly, authorized and directed, to file
the Proxy Statement with the SEC, with such provisions therein as the Authorized
Officer or Authorized Officers filing the Proxy Statement may deem necessary or
desirable, the filing by such Authorized Officer or Authorized Officers to be
conclusive evidence of his or their authority so to act.
VOTED - that the Trustees hereby declare that the Merger is advisable
and in the best interests of the Association and recommend to shareholders that
they approve the Merger.
VOTED - that the Authorized Officers of this Association be, and each
of them acting singly hereby is, authorized and empowered to do or cause to be
done all such acts or things and to sign and deliver, or cause to be signed and
delivered, all such documents, instruments and certificates (including, without
limitation, obtaining all required shareholder authorizations under Article 37
3
<PAGE>
of this Association's Declaration of Trust, as amended) as such officer of this
Association may deem necessary advisable or appropriate to effectuate or carry
out the purposes and intent of the foregoing votes and to perform the
obligations of this Association under the agreements and instruments referred to
therein.
There being no further business to discuss, on motion duly made and
seconded, it was
VOTED - to adjourn at 5:45 o'clock in the forenoon.
A true record.
Attest:
Acting Secretary
4
<PAGE>
The National Grid Group plc
IOSTA, Inc.
NGG Holdings LLC
Secretary's Certificate
The undersigned, Acting Secretary of The National Grid Group plc,
IOSTA, Inc., and NGG Holdings LLC, DO HEREBY CERTIFY on behalf of The National
Grid Group plc, IOSTA, Inc., and NGG Holginds LLC that:
Attached hereto as Exhibit A is a true and correct copy of Resolutions
duly adopted by the Boards of The National Grid Group plc, IOSTA,
Inc., and NGG Holdings LLC, which Resolutions have not been revoked,
modified, amended, or rescinded and remain in full force and effect on
the date hereof, except as indicated therein.
IN WITNESS WHEREOF, the undersigned has executed and delivered this
certificate this 28th day of April, 1999.
THE NATIONAL GRID GROUP plc
IOSTA, INC.
NGG HOLDINGS PLC
By: /s/ Clare M. Phelan
-----------------------------------
Clare M. Phelan
Acting Secretary
Signed and sworn to before me this
28th day of April, 1999.
/s/ Sandra J. Brochu
- -----------------------------------
Notary Public
My commission expires: 8/19/2005
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Directors' Authorization Resolutions
Resolved at The National Grid Group plc Committee of the
Board of Directors Meeting on January 29, 1999
RESOLVED: Each of the Directors present confirmed that he had sufficiently
and carefully considered the terms of the consent Agreement and,
accordingly, IT WAS RESOLVED that the Chairman or any one
Executive Director or Fiona Smith be and is hereby authorised to
agree any further amendments to and to execute and deliver on
behalf of the Company the Consent Agreement.
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Managers' Authorization Resolutions
Resolved at IOSTA, Inc. Meeting of the Managers on January 29, 1999
RESOLVED: It was noted that the Acquisition would be entered into by NEES
as soon as reasonably practicable after the date hereof AND IT
WAS ACCORDINGLY RESOLVED that subject to being satisfied as to
valuation and price, The National Grid Group plc be and is hereby
authorised to give consent to NEES to the entering into of the
Acquisition by way of entering into a Consent Agreement with
NEES.
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT A
Board of Managers' Authorization Resolutions
Resolved at NGG Holdings LLC
Meeting of the Managers on January 29, 1999
RESOLVED: It was noted that the Acquisition would be entered into by NEES
as soon as reasonably practicable after the date hereof AND IT
WAS ACCORDINGLY RESOLVED that subject to being satisfied as to
valuation and price, The National Grid Group plc be and is hereby
authorised to give consent to NEES to the entering into of the
Acquisition by way of entering into a Consent Agreement with
NEES.
<PAGE>
NEW ENGLAND POWER COMPANY
MASSACHUSETTS ELECTRIC COMPANY
THE NARRAGANSETT ELECTRIC COMPANY
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION CORPORATION
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
ALLENERGY MARKETING COMPANY, L.L.C.
MONTAUP ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
EASTERN EDISON COMPANY
NEWPORT ELECTRIC CORPORATION
RESEARCH DRIVE LLC
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT B
Statement of Control of Ownership
<PAGE>
Exhibit B
Page 1 of 12
New England Power Company
No ownership or control is exercised by or over New England Power
Company as to any bank, trust company, banking association, or firm that is
authorized to underwrite or participate in the marketing of securities of a
public utility, or any company supplying electric equipment to such companies.
The NEES Companies parent, however, does have certain directors who are
directors of commercial banks or of companies which have subsidiaries authorized
to underwrite or participate in the marketing of securities. In any event, a
minority of directors who also serve on boards of commercial banks or companies
who have subsidiaries authorized to underwrite securities are not likely to
exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
<PAGE>
Exhibit B
Page 2 of 12
Massachusetts Electric Company
No ownership or control is exercised by or over Massachusetts Electric
Company as to any bank, trust company, banking association, or firm that is
authorized to underwrite or participate in the marketing of securities of a
public utility, or any company supplying electric equipment to such companies.
The NEES Companies parent, however, does have certain directors who are
directors of commercial banks or of companies which have subsidiaries authorized
to underwrite or participate in the marketing of securities. In any event, a
minority of directors who also serve on boards of commercial banks or companies
who have subsidiaries authorized to underwrite securities are not likely to
exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
<PAGE>
Exhibit B
Page 3 of 12
The Narragansett Electric Company
No ownership or control is exercised by or over The Narragansett
Electric Company as to any bank, trust company, banking association, or firm
that is authorized to underwrite or participate in the marketing of securities
of a public utility, or any company supplying electric equipment to such
companies. The NEES Companies parent, however, does have certain directors who
are directors of commercial banks or of companies which have subsidiaries
authorized to underwrite or participate in the marketing of securities. In any
event, a minority of directors who also serve on boards of commercial banks or
companies who have subsidiaries authorized to underwrite securities are not
likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
<PAGE>
Exhibit B
Page 4 of 12
New England Electric Transmission Corporation
No ownership or control is exercised by or over New England Electric
Transmission Corporation as to any bank, trust company, banking association, or
firm that is authorized to underwrite or participate in the marketing of
securities of a public utility, or any company supplying electric equipment to
such companies. The NEES Companies parent, however, does have certain directors
who are directors of commercial banks or of companies which have subsidiaries
authorized to underwrite or participate in the marketing of securities. In any
event, a minority of directors who also serve on boards of commercial banks or
companies who have subsidiaries authorized to underwrite securities are not
likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
<PAGE>
Exhibit B
Page 5 of 12
New England Hydro-Transmission Corporation
No ownership or control is exercised by or over New England
Hydro-Transmission Corporation as to any bank, trust company, banking
association, or firm that is authorized to underwrite or participate in the
marketing of securities of a public utility, or any company supplying electric
equipment to such companies. The NEES Companies parent, however, does have
certain directors who are directors of commercial banks or of companies which
have subsidiaries authorized to underwrite or participate in the marketing of
securities. In any event, a minority of directors who also serve on boards of
commercial banks or companies who have subsidiaries authorized to underwrite
securities are not likely to exercise "control" as the term is used in 18 C.F.R.
33.3, Exhibit B.
<PAGE>
Exhibit B
Page 6 of 12
New England Hydro-Transmission Electric Company, Inc.
No ownership or control is exercised by or over New England
Hydro-Transmission Electric Company, Inc. as to any bank, trust company, banking
association, or firm that is authorized to underwrite or participate in the
marketing of securities of a public utility, or any company supplying electric
equipment to such companies. The NEES Companies parent, however, does have
certain directors who are directors of commercial banks or of companies which
have subsidiaries authorized to underwrite or participate in the marketing of
securities. In any event, a minority of directors who also serve on boards of
commercial banks or companies who have subsidiaries authorized to underwrite
securities are not likely to exercise "control" as the term is used in 18 C.F.R.
33.3, Exhibit B.
<PAGE>
Exhibit B
Page 7 of 12
AllEnergy Marketing Company, L.L.C.
No ownership or control is exercised by or over AllEnergy Marketing
Company, L.L.C. as to any bank, trust company, banking association, or firm that
is authorized to underwrite or participate in the marketing of securities of a
public utility, or any company supplying electric equipment to such companies.
The NEES Companies parent, however, does have certain directors who are
directors of commercial banks or of companies which have subsidiaries authorized
to underwrite or participate in the marketing of securities. In any event, a
minority of directors who also serve on boards of commercial banks or companies
who have subsidiaries authorized to underwrite securities are not likely to
exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
<PAGE>
Exhibit B
Page 8 of 12
Montaup Electric Company
Montaup Electric Company is a wholly owned subsidiary of Eastern
Edison Company, which is a public utility company and an indirect subsidiary of
Eastern Utilities Associates ("EUA"), a public utility holding company. No
ownership or control is exercised by or over Montaup Electric Company as to any
bank, trust company, banking association, or firm that is authorized to
underwrite or participate in the marketing of securities of a public utility, or
any company supplying electric equipment to such companies.
Certain of the EUA trustees, representing a minority of the EUA Board
of Trustees, also serve as directors of commercial banks or of companies which
have subsidiaries authorized to underwrite or participate in the marketing of
securities. A minority of trustees who also serve on boards of commercial banks
or companies who have subsidiaries authorized to underwrite securities are not
likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
Montaup Electric Company has officers and directors in common with
Blackstone Valley Electric Company, Eastern Edison Company, Newport Electric
Corporation and EUA.
<PAGE>
Exhibit B
Page 9 of 12
Blackstone Valley Electric Company
Blackstone Valley Electric Company is a wholly owned subsidiary of
EUA, a public utility holding company. No ownership or control is exercised by
or over Blackstone Valley Electric Company as to any public utility or bank,
trust company, banking association, or firm that is authorized to underwrite or
participate in the marketing of securities of a public utility, or any company
supplying electric equipment to such companies.
Certain of the EUA trustees, representing a minority of the EUA Board
of Trustees, also serve as directors of commercial banks or of companies which
have subsidiaries authorized to underwrite or participate in the marketing of
securities. A minority of trustees who also serve on boards of commercial banks
or companies who have subsidiaries authorized to underwrite securities are not
likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
Blackstone Valley Electric Company has officers and directors in
common with Montaup Electric Company, Eastern Edison Company, Newport Electric
Corporation and EUA.
<PAGE>
Exhibit B
Page 10 of 12
Eastern Edison Company
Eastern Edison Company is a wholly owned subsidiary of EUA, a public
utility holding company. Eastern Edison Company owns all of the issued and
outstanding common stock of Montaup Electric Company, a public utility company.
No ownership or control is exercised by or over Eastern Edison Company as to any
bank, trust company, banking association, or firm that is authorized to
underwrite or participate in the marketing of securities of a public utility, or
any company supplying electric equipment to such companies.
Certain of the EUA trustees, representing a minority of the EUA Board
of Trustees, also serve as directors of commercial banks or of companies which
have subsidiaries authorized to underwrite or participate in the marketing of
securities. A minority of trustees who also serve on boards of commercial banks
or companies who have subsidiaries authorized to underwrite securities are not
likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
Eastern Edison Company has officers and directors in common with Blackstone
Valley Electric Company, Montaup Electric Company, Newport Electric Corporation
and EUA.
<PAGE>
Exhibit B
Page 11 of 12
Newport Electric Corporation
Newport Electric Corporation is a wholly owned subsidiary of EUA, a
public utility holding company. No ownership or control is exercised by or over
Newport Electric Corporation as to any public utility or bank, trust company,
banking association, or firm that is authorized to underwrite or participate in
the marketing of securities of a public utility, or any company supplying
electric equipment to such companies.
Certain of the EUA trustees, representing a minority of the EUA Board
of Trustees, also serve as directors of commercial banks or of companies which
have subsidiaries authorized to underwrite or participate in the marketing of
securities. A minority of trustees who also serve on boards of commercial banks
or companies who have subsidiaries authorized to underwrite securities are not
likely to exercise "control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
Newport Electric Corporation has officers and directors in common with
Montaup Electric Company, Eastern Edison Company, Blackstone Valley Electric
Company and EUA.
<PAGE>
Exhibit B
Page 12 of 12
Research Drive LLC
No ownership or control is exercised by or over Research Drive LLC as
to any bank, trust company, banking association, or firm that is authorized to
underwrite or participate in the marketing of securities of a public utility, or
any company supplying electric equipment to such companies. The NEES Companies
parent, however, does have certain directors who are directors of commercial
banks or of companies which have subsidiaries authorized to underwrite or
participate in the marketing of securities. In any event, a minority of
directors who also serve on boards of commercial banks or companies who have
subsidiaries authorized to underwrite securities are not likely to exercise
"control" as the term is used in 18 C.F.R. 33.3, Exhibit B.
<PAGE>
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, ET AL.
AND MONTAUP ELECTRIC COMPANY, ET AL.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT C-1 New England Power Company
EXHIBIT C-2 Massachusetts Electric Company
EXHIBIT C-3 The Narragansett Electric Company
EXHIBIT C-4 New England Electric Transmission Corporation
EXHIBIT C-5 New England Hydro Transmission Corporation
EXHIBIT C-6 New England Hydro-Transmission Electric Company, Inc.
EXHIBIT C-7 Montaup Electric Company
EXHIBIT C-8 Blackstone Valley Electric Company
EXHIBIT C-9 Eastern Edison Company
EXHIBIT C-10 Newport Electric Corporation
ACTUAL AND PRO FORMA
BALANCE SHEETS
AND PLANT SCHEDULES
SEPTEMBER 30, 1998
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. C-1
Page 1 of 5
Name of Respondent
New England Power Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 1,510,284,010 1,510,284,010
3 Construction Work in Progress (107) 28,179,703 28,179,703
4 TOTAL UTILITY PLANT
(Enter Total of lines 2 and 3) 1,538,463,713 1,538,463,713
5 (Less) Accum. Prov. for Depr.
Amort. Depl. (108, 111, 115) 1,100,830,086 1,100,830,086
6 Net Utility Plant (Enter total of line 4 less 5) 437,633,627 437,633,627
7 Nuclear fuel (120.1-120.4, 120.6) 72,825,922 72,825,922
8 (Less) Accum. Prov. for Amort. of Nucl. 59,232,721 59,232,721
Assemblies (120.5)
9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 13,593,201 13,593,201
10 Net Utility Plant (Enter Total of lines 6 and 9) 451,226,828 451,226,828
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121) 6,345,708 6,345,708
15 (Less) Accum. Prov. for Depr. and Amort. (122) 10,287 10,287
16 Investments in Associated Companies (123) 48,202,681 48,202,681
17 Investment in Subsidiary Companies (123.1)
18 (For Cost of Account 123.1, See Footnote Page
224, Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124) 233,566 233,566
21 Special Funds (125-128) 27,740,101 27,740,101
22 TOTAL Other Property and Investments (Total of 82,511,769 82,511,769
lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 74,602 74,602
25 Special Deposits (132-134) 2,001,662 2,001,662
26 Working Fund (135) 46,030 46,030
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 20,362,387 20,362,387
30 Other Accounts Receivable (143) 13,345,437 13,345,437
31 (Less) Accum. Prov. for Uncollectible
Acct.-Credit (144)
32 Notes Receivable from Associated Companies (145) 147,200,000 147,200,000
33 Accounts Receivable from Assoc. Companies (146) 149,982,908 149,982,908
34 Fuel Stock (151) 510,793 510,793
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 9,177,832 9,177,832
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 3,477,340 3,477,340
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171) 2,755,846 2,755,846
49 Rents Receivable (172)
50 Accrued Utility Revenues (173)
51 Miscellaneous Current and Accrued Assets (174) 25,201 25,201
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-1
Page 2 of 5
Name of Respondent
New England Power Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
52 TOTAL Current and Accrued Assets
(Enter Total of lines 24 thru 51) 348,960,038 348,960,038
53 DEFERRED DEBITS
54 Unamortized Debt Expenses (181) 3,039,869 3,039,869
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs
(182.2)
57 Other Regulatory Assets (182.3) 1,576,719,353 1,576,719,353
58 Prelim. Survey and Investigation Charges 132,814 132,814
(Electric) (183)
59 Prelim. Sur. And Invest. Charges (Gas) (183.1,
183.2)
60 Clearing Accounts (184) 182,213 182,213
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 35,068,645 35,068,645
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189)
66 Accumulated Deferred Income Taxes (190) 127,606,257 127,606,257
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits 1,742,749,151 1,742,749,151
(Enter Total of Lines 54 thru 67)
69 TOTAL Assets and other Debits (Enter Total of 2,625,447,786 2,625,447,786
lines 10, 11, 12, 22, 52 and 68)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-1
Page 3 of 5
Name of Respondent
New England Power Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS )
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201) 74,997,920 74,997,920
3 Preferred Stock Issued (204) 10,574,500 10,574,500
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 50,395,347 50,395,347
7 Other Paid-in Capital (208-211) 190,721,846 190,721,846
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 172,101,567 172,101,567
12 Unappropriated Undistributed Subsidiary Earnings 14,252,922 14,252,922
(216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital
(Enter Total of Lines 2 thru 13) 513,044,102 513,044,102
15 LONG-TERM DEBT
16 Bonds (221) 371,850,000 371,850,000
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224)
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term 86,585 86,585
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 371,763,415 371,763,415
thru 21)
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227)
25 Accumulated Provision for Property Insurance
(228.1)
26 Accumulated Provision for Injuries and Damages
(228.2)
27 Accumulated Provision for Pensions and Benefits
(228.3)
28 Accumulated Miscellaneous Operating Provisions 1,916,764 1,916,764
(228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total 1,916,764 1,916,764
of lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Notes Payable (231)
33 Accounts Payable (232) 68,409,221 68,409,221
34 Notes Payable to Associated Companies (233)
35 Accounts Payable to Associated Companies (234) 11,542,824 11,542,824
36 Customer Deposits (235)
37 Taxes Accrued (236) 24,674,915 24,674,915
38 Interest Accrued (237) 266,558 266,558
39 Dividends Declared (238) 141,340 141,340
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241) 27,396 27,396
43 Miscellaneous Current and Accrued Liabilities 134,184,483 134,184,483
(242)
44 Obligations Under Capital Leases - Current (243)
45 TOTAL Current and Accrued Liabilities (Enter 239,246,737 239,246,737
Total of lines 32 thru 44)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-1
Page 4 of 5
Name of Respondent
New England Power Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS )
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
46 DEFERRED CREDITS
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 30,648,837 30,648,837
49 Deferred Gains from Disposition of Utility Plant
(256)
50 Other Deferred Credits (253) 1,134,673,476 1,134,673,476
51 Other Regulatory Liabilities (254) 36,341,946 36,341,946
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 297,812,509 297,812,509
54 TOTAL Deferred Credits (Enter Total of Lines 47 1,499,476,768 1,499,476,768
thru 53)
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits
(Enter Total of Lines 14, 22, 30, 45 and 54) 2,625,447,786 2,625,447,786
<PAGE>
<CAPTION>
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified) 1,393,566,319 1,393,566,319
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified 108,238,451 108,238,451
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 1,501,804,770 1,501,804,770
9 Leased to Others
10 Held for Future Use 8,479,240 8,479,240
11 Construction Work in Progress 28,179,703 28,179,703
12 Acquisition Adjustments
13 Total Utility Plant
(Enter total of lines 8 thru 12) 1,538,463,713 1,538,463,713
14 Accum. Prov. for Depr., Amort., and Depl. 1,100,830,086 1,100,830,086
15 Net Utility Plant
(Enter Total of line 13 less 14) 437,633,627 437,633,627
16 DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION, AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 762,764,185 762,764,185
18 Amort. and Depl. of Producing
Natural Gas & Land Rights
20 Amort. of Underground Storage
Land and Land Rights
21 Amort. of Other Utility Plant 338,065,901 338,065,901
22 TOTAL In Service
(Enter Total of lines 18 thru 21) 1,100,830,086 1,100,830,086
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others
(Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use
(Enter Total of lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions
(Should agree with line 14 above) 1,100,830,086 1,100,830,086
(Enter Total of lines 22,
26, 30, 31 and 32)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. C-2
Page 1 of 5
Name of Respondent
Massachusetts Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
52 TOTAL Current and Accrued Assets (Enter Total of 348,960,038 348,960,038
1 UTILITY PLANT
2 Utility Plant (101-106, 114) 1,603,921,360 1,603,921,360
3 Construction Work in Progress (107) 18,932,439 18,932,439
4 TOTAL UTILITY PLANT (Enter total of lines 2 1,622,853,799 1,622,853,799
and 3)
5 (Less) Accum. Prov. for Depr. Amort. Depl. 487,714,629 487,714,629
(108, 111, 115)
6 Net Utility Plant (enter total of line 4 Less 1,135,139,170 1,135,139,170
5)
7 Nuclear Fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl.
Assemblies (120.5)
9 Net Nuclear Fuel (Enter Total of line 7 Less
8)
10 Net Utility Plant (Enter Total of lines 6 and 1,135,139,170 1,135,139,170
9)
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121) 12,719,532 12,719,532
15 (Less) Accum. Prov. for Depr. and Amort. (122) 856,183 856,183
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1)
18 (For Cost of Account 123.1, See Footnote Page
224, Line 42)
19 Noncurrent Portion of Allowance
20 Other Investments (124) 360,594 360,594
21 Special funds (125-128) 1,974,098 1,974,098
22 TOTAL Other Property and Investments (Total 14,198,041 14,198,041
of lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 7,157,257 7,157,257
25 Special Deposits (132-134) 1,149,887 1,149,887
26 Working Fund (135) 107,738 107,738
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 174,776,613 174,776,613
30 Other Accounts Receivable (143) 546,204 546,204
31 (Less) Accum. Prov. for Uncollectible 14,889,674 14,889,674
Acct-Credit (144)
32 Notes Receivable from Associated Companies
(145)
33 Accounts Receivable from Assoc. Companies 33,795,614 33,795,614
(146)
34 Fuel Stock (151)
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 9,274,158 9,274,158
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held
for Processing (164.2-164.3)
46 Prepayments (165) 13,947,353 13,947,353
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171)
49 Rents Receivable (172)
50 Accrued Utility Revenues (173) 52,702,000 52,702,000
51 Miscellaneous Current and Accrued Assets (174) 821,036 821,036
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-2
Page 2 of 5
Name of Respondent
Massachusetts Electric Company At September 30, 1998
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
52 TOTAL Current and Accrued Assets (Enter Total 279,388,186 279,388,186
of lines 24 thru 51)
53 DEFERRED DEBITS
54 Unamortized Debt Expenses (181) 613,887 613,887
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs
(182.2)
57 Other Regulatory Assets (182.3) 32,633,218 32,633,218
58 Prelim. Survey and Investigation Charges 78,698 78,698
(Electric) (183)
59 Prelim. Sur. and Invest. Charges (Gas)
(183.1, 183.2)
60 Clearing Accounts (184) (148,654) (148,654)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 6,942,267 6,942,267
63 Def. Losses from Disposition of Utility Plt.
(187)
64 Research, Devel. and Demonstration Expend.
(188)
65 Unamortized Loss on Reacquired Debt (189)
66 Accumulated Deferred Income Taxes (190) 60,657,945 60,657,945
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of lines 100,777,361 100,777,361
54 thru 67)
69 TOTAL Assets and Other Debits (Enter Total of 1,529,502,758 1,529,502,758
lines 10, 11, 12, 22, 52, and 68)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-2
Page 3 of 5
Name of Respondent
Massachusetts Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
52 TOTAL Current and Accrued Assets (Enter Total of 348,960,038 348,960,038
1 PROPRIETARY CAPITAL
2 Common Stock issued (201) 59,952,775 59,952,775
3 Preferred Stock issued (204) 15,738,525 15,738,525
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 45,945,427 45,945,427
7 Other Paid-in Capital (208-211) 193,498,180 192,498,180
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 196,579,054 196,579,054
12 Unappropriated Undistributed
Subsidiary Earnings (216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital
(Enter Total of Lines 2 thru 13) 511,713,961 511,713,961
15 LONG-TERM DEBT
16 Bonds (221)
17 (Less) Reacquired bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224) 355,000,000 355,000,000
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-term 1,561,996 1,561,996
Debt-Debit (226)
22 TOTAL Long-Term Debt 353,438,004 353,438,004
(Enter Total of Lines 16 thru 21)
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227) 651,829 651,829
25 Accumulated Provision for Property Insurance
(228.1)
26 Accumulated Provision for Injuries and Damages
(228.2)
27 Accumulated provision for Pensions and Benefits
(228.3)
28 Accumulated Miscellaneous Operating Provisions
(228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities 651,829 651,829
(enter Total of lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Notes Payable (231)
33 Accounts Payable (232) 83,868,192 83,868,192
34 Notes Payable to Associated Companies (233) 52,950,000 52,950,000
35 Accounts Payable to Associated Companies (234) 112,820,067 112,820,067
36 Customer Deposits (235) 4,639,484 4,639,484
37 Taxes Accrued (236) 1,893,091 1,893,091
38 Interest Accrued (237) 7,774,998 7,774,998
39 Dividends Declared (238) 240,149 240,149
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241) 504,125 504,125
43 Miscellaneous Current and
Accrued Liabilities (242) 64,739,809 64,739,809
44 Obligations Under Capital
leases - Current (243) 192,534 192,534
45 TOTAL Current and Accrued Liabilities 329,622,449 329,622,449
(Enter Total of lines 32 thru 44)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-2
Page 4 of 5
Name of Respondent
Massachusetts Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
46 DEFERRED CREDITS
47 Customer Advances for Construction (252) 292,673 292,673
48 Accumulated Deferred
Investment Tax Credits (255) 14,648,573 14,648,573
49 Deferred Gains from Disposition
of Utility Plant (256)
50 Other Deferred Credits (253) 53,264,732 53,264,732
51 Other Regulatory Liabilities (254) 20,212,371 20,212,371
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 245,658,166 245,658,166
54 TOTAL Deferred Credits
(Enter Total of Lines 47 thru 53) 334,076,515 334,076,515
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other credits
(Enter Total of Lines 14, 22, 30, 45 and 54) 1,529,502,758 1,529,502,758
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-2
Page 5 of 5
Name of Respondent
Massachusetts Electric Company At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION At September 30, 1998
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified) 1,413,389,021 1,413,389,021
4 Property Under Capital Leases 844,364 844,364
5 Plant Purchased or Sold
6 Completed Construction not Classified 188,904,329 188,904,329
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 1,603,137,714 1,603,137,714
9 Leased to Others
10 Held for Future Use 783,646 783,646
11 Construction Work in Progress 18,932,439 18,932,439
12 Acquisition Adjustments
13 Total Utility Plant
(Enter total of lines 8 thru 12) 1,622,853,799 1,622,853,799
14 Accum. Prov. for Depr. Amort. And Depl. 487,714,629 487,714,629
15 Net Utility Plant
(Enter Total of line 13 less 14) 1,135,139,170 1,135,139,170
16 DETAIL OF ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17 In Service:
18 Depreciation 487,714,629 487,714,629
19 Amort. and Depl. Of Producing
Natural Gas & Land Rights
20 Amort. of Underground Storage
Land and Land Rights
21 Amort. of Other Utility Plant
22 TOTAL in Service (Enter Total of
lines 18 thru 21) 487,714,629 487,714,629
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others
(Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use
(Enter Total of Lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions
(Should agree with line 14 above)
(Enter Total of lines 22, 26, 30,
31 and 32) 487,714,629 487,714,629
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. C-3
Page 1 of 5
Name of Respondent
Narragansett Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 726,338,509 726,338,509
3 Construction Work in Progress (107) 2,717,852 2,717,852
4 TOTAL UTILITY PLANT (Enter Tota of lines 2 and 3) 729,056,361 729,056,361
5 (Less) Accum. Prov. for Depr. Amort. Depl. 203,908,243 203,908,243
(108, 111, 115)
6 Net Utility Plant (Enter Total of line 4 Less 5) 525,148,118 525,148,118
7 Nuclear Fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl.
Assemblies (120.5)
9 Net Nuclear Fuel (Enter Total of line 7 Less 8)
10 Net Utility Plant (enter Total of lines 6 and 9) 525,148,118 525,148,118
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121) 2,492,201 2,492,201
15 (Less) Accum. Prov. for Depr. and Amort. (122) 4,511 4,511
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1)
18 (For Cost of Account 123.1. See Footnote Page
224, Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124) 565,541 565,541
21 Special Funds (125-128) 1,548,940 1,548,940
22 TOTAL Other Property and Investments (Total of 4,602,171 4,602,171
lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 3,181,620 3,181,620
25 Special Deposits (132-134) 213,011 213,011
26 Working Fund (135) 26,607 26,607
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 50,680,661 50,680,661
30 Other Accounts Receivable (143) 2,712,633 2,712,633
31 (Less) Accum. Prov. for Uncollectible 5,002,071 5,002,071
Acct.-Credit (144)
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146) 20,580,742 20,580,742
34 Fuel Stock (151) 61,948 61,948
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 3,501,637 3,501,637
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 9,798,341 9,798,341
47 Advances for Gas (166-167)
48 Interest and Dividends receivable (171) 8,363 8,363
49 Rents Receivable (172)
50 Accrued Utility Revenues (173) 19,536,000 19,536,000
51 Miscellaneous Current and Accrued Assets (174) 181,394 181,394
52 TOTAL Current and Accrued Assets (Enter Total 105,480,886 105,480,886
of lines 24 thru 51)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-3
Page 2 of 5
Name of Respondent
Narragansett Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
53 DEFERRED DEBITS
<S> <C> <C> <C>
54 Unamortized Debt Expenses (181) 709,785 709,785
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs
(182.2)
57 Other Regulatory Assets (182.3) 41,696,083 41,696,083
58 Prelim. Survey and Investigation Charges 319,376 319,376
(Electric) (183)
59 Prelim. Sur. and Invest. Charges (Gas) (183.1,
183.2)
60 Clearing Accounts (184) 142,669 142,669
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 12,616,238 12,616,238
63 Def. Losses from Disposition of Utility Plt.
(187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189)
66 Accumulated Deferred Income taxes (190) 16,312,823 16,312,823
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of lines 54 71,796,974 71,796,974
thru 67)
69 TOTAL Assets and other Debits (Enter Total of 707,028,149 707,028,149
lines 10,11,12,22,52, and 68)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-3
Page 3 of 5
Name of Respondent
Narragansett Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock Issued (201) 56,624,350 56,624,350
3 Preferred Stock Issued (204) 7,601,300 7,601,300
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 80,161 80,161
7 Other Paid-in Capital (208-211) 105,713,572 105,713,572
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 83,524,686 83,524,686
12 Unappropriated Undistributed Subsidiary
Earnings (216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of 253,544,069 253,544,069
Lines 2 thru 13)
15 LONG-TERM DEBT
16 Bonds (221) 179,700,000 179,700,000
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224)
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term 1,041,937 1,041,937
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 178,658,063 178,658,063
thru 21)
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent
(227)
25 Accumulated Provision for Property Insurance
(228.1)
26 Accumulated Provision for Injuries and
Damages (228.2)
27 Accumulated Provision for Pensions and
Benefits (228.3)
28 Accumulated Miscellaneous Operating
Provisions (228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter
Total of lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Notes Payable (231)
33 Accounts Payable (232) 17,029,894 17,029,894
34 Notes Payable to Associated Companies (233) 40,750,000 40,750,000
35 Accounts Payable to Associated Companies (234) 34,355,863 34,355,863
36 Customer Deposits (235) 6,165,541 6,165,541
37 Taxes Accrued (236) 3,357,327 3,357,327
38 Interest Accrued (237) 3,121,364 3,121,364
39 Dividends Declared (238) 99,326 99,326
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241) 948,630 948,630
43 Miscellaneous Current and Accrued Liabilities 37,943,157 37,943,157
(242)
44 Obligations Under Capital Leases - Current
(243)
45 TOTAL Current and Accrued Liabilities (Enter 143,771,102 143,771,102
Total of lines 32 thru 44)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-3
Page 4 of 5
Name of Respondent
Narragansett Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252) (10,133) (10,133)
48 Accumulated Deferred Investment Tax Credits 6,655,589 6,655,589
(255)
49 Deferred Gains from Disposition of Utility
Plant (256)
50 Other Deferred Credits (253) 14,029,220 14,029,220
51 Other Regulatory Liabilities (254) 8,846,730 8,846,730
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 101,533,509 101,533,509
54 TOTAL Deferred Credits (Enter Total of Lines 131,054,915 131,054,915
47 thru 53)
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter 707,028,149 707,028,149
Total of Lines 14, 22, 30, 45, and 54)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-3
Page 5 of 5
Name of Respondent
Narragansett Electric Company At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
2 In Service
<S> <C> <C> <C>
3 Plant in Service (Classified) 593,280,225 593,280,225
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified 120,410,883 120,410,883
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 713,691,108 713,691,108
9 Leased to Others
10 Held for Future Use 12,647,401 12,647,401
11 Construction Work in Progress 2,717,852 2,717,852
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of lines 8 thru 12) 729,056,361 729,056,361
14 Accum. Prov. for Depr., Amort., and Depl. 203,908,243 203,908,243
15 Net Utility Plant (Enter Total of line 13 less 14) 525,148,118 525,148,118
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 203,908,243 203,908,243
19 Amort. and Depl. of Producing Natural Gas & Land Rights
20 Amort. of Underground Storage Land and Land Rights
21 Amort. of Other Utility Plant
22 TOTAL in Service (Enter Total of lines 18 thru 21) 203,908,243 203,908,243
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of
lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree with 203,908,243 203,908,243
line 14 above)(Enter Total of lines 22, 26, 30,
31 and 32)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. C-4
Page 1 of 5
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 91,168,193 91,168,193
3 Construction Work in Progress (107)
4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 91,168,193 91,168,193
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 55,614,132 55,614,132
111, 115)
6 Net Utility Plant (Enter total of line 4 less 5) 35,554,061 35,554,061
7 Nuclear fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl.
Assemblies (120.5)
9 Net Nuclear Fuel (Enter Total of line 7 Less 8)
10 Net Utility Plant (Enter Total of lines 6 and 9) 35,554,061 35,554,061
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121)
15 (Less) Accum. Prov. for Depr. and Amort. (122)
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1)
18 (For Cost of Account 123.1, See Footnote Page
224, Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124)
21 Special Funds (125-128)
22 TOTAL Other Property and Investments (Total of
lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 21,763 21,763
25 Special Deposits (132-134)
26 Working Fund (135)
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142)
30 Other Accounts Receivable (143) (239) (239)
31 (Less) Accum. Prov. for Uncollectible
Acct.-Credit (144)
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146) 13,940 13,940
34 Fuel Stock (151)
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 87,007 87,007
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 8,732 8,732
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171) 23 23
49 Rents Receivable (172)
50 Accrued Utility Revenues (173)
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-4
Page 2 of 5
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
51 Miscellaneous Current and Accrued Assets (174)
52 TOTAL Current and Accrued Assets (Enter Total of
lines 24 thru 51) 131,226 131,226
53 DEFERRED DEBITS
54 Unamortized Debt Expenses (181) 310,736 310,736
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs
(182.2)
57 Other Regulatory Assets (182.3) 1,522,900 1,522,900
58 Prelim. Survey and Investigation Charges
(Electric) (183)
59 Prelim. Sur. and Invest. Charges (Gas) (183.1,
183.2)
60 Clearing Accounts (184)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186)
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189)
66 Accumulated Deferred Income Taxes (190) 3,027,920 3,027,920
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of Lines 54 4,861,556 4,861,556
thru 67)
69 TOTAL Assets and other Debits (Enter Total of 40,546,843 40,546,843
lines 10, 11, 12, 22, 52 and 68)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-4
Page 3 of 5
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock Issued (201) 450 450
3 Preferred Stock Issued (204)
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 89,550 89,550
7 Other Paid-In Capital (208-211) 2,160,000 2,160,000
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 127,400 127,400
12 Unappropriated Undistributed Subsidiary Earnings
(216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of Lines 2 2,377,400 2,377,400
thru 13)
15 LONG-TERM DEBT
16 Bonds (221)
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224) 17,392,000 17,392,000
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 17,392,000 17,392,000
21)
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227)
25 Accumulated Provision for Property Insurance
(228.1)
26 Accumulated Provision for Injuries and Damages
(228.2)
27 Accumulated Provision for Pensions and Benefits
(228.3)
28 Accumulated Miscellaneous Operating Provisions
(228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total of
lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Notes Payable (231)
33 Accounts Payable (232) 67,228 67,228
34 Notes Payable to Associated Companies (233) 3,500,000 3,500,000
35 Accounts Payable to Associated Companies (234) 75,031 75,031
36 Customer Deposits (235)
37 Taxes Accrued (236) (41,734) (41,734)
38 Interest Accrued (237) 80,361 80,361
39 Dividends Declared (238)
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241) 445 445
43 Miscellaneous Current and Accrued Liabilities (242) 91,666 91,666
44 Obligations Under Capital Leases - Current (243)
45 TOTAL Current and Accrued Liabilities (Enter Total 3,772,997 3,772,997
of lines 32 thru 44)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-4
Page 4 of 5
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 3,082,234 3,082,234
49 Deferred Gains from Disposition of Utility Plant
(256)
50 Other Deferred Credits (253)
51 Other Regulatory Liabilities (254) 2,448,249 2,448,249
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 11,473,963 11,473,963
54 TOTAL Deferred Credits (Enter Total of Lines 47 17,004,446 17,004,446
thru 53)
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter Total 40,546,843 40,546,843
of Lines 14, 22, 30, 45 and 54)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-4
Page 5 of 5
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Balance at Pro-Forma Balance at
No. Item 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
2 In Service
<S> <C> <C> <C>
3 Plant in Service (Classified) 91,168,193 91,168,193
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 91,168,193 91,168,193
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of
lines 8 thru 12) 91,168,193 91,168,193
14 Accum. Prov. for Depr., Amort., and Depl. 55,614,132 55,614,132
15 Net Utility Plant (Enter Total of line 13 less 14) 35,554,061 35,554,061
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 55,573,632 55,573,632
18 Amort. and Depl. of Producing Natural Gas & Land
Rights
20 Amort. of Underground Storage Land and Land Rights
21 Amort. of Other Utility Plant 40,500 40,500
22 TOTAL In Service (Enter Total of lines 18 thru 21) 55,614,132 55,614,132
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24
and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of lines 28
and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree with
line 14 above) (Enter Total of lines 22, 26, 30, 31
and 32) 55,614,132 55,614,132
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 1 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 173,245,669 173,245,669
3 Construction Work in Progress (107)
4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 173,245,669 173,245,669
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 45,222,278 45,222,278
111, 115)
6 Net Utility Plant (Enter total of line 4 less 5) 128,023,391 128,023,391
7 Nuclear fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies
(120.5)
9 Net Nuclear Fuel (Enter Total of line 7 Less 8)
10 Net Utility Plant (Enter Total of lines 6 and 9) 128,023,391 128,023,391
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121)
15 (Less) Accum. Prov. for Depr. and Amort. (122)
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1) 5,000 5,000
18 (For Cost of Account 123.1, See Footnote Page 224,
Line 42)
19 Noncurrent Portion of Allowance
20 Other Investments (124)
21 Special Funds (125-128)
22 TOTAL Other Property and Investments (Total of 5,000 5,000
lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 19,583 19,583
25 Special Deposits (132-134)
26 Working Fund (135)
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142)
30 Other Accounts Receivable (143) (28,653) (28,653)
31 (Less) Accum. Prov. for Uncollectible Acct.-Credit
(144)
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146)
34 Fuel Stock (151)
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 86,804 86,804
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 6,360 6,360
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171) 181 181
49 Rents Receivable (172)
50 Accrued Utility Revenues (173)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 2 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
51 Miscellaneous Current and Accrued Assets (174)
52 TOTAL Current and Accrued Assets (Enter Total of 84,275 84,275
lines 24 thru 51)
53 DEFERRED DEBITS
54 Unamortized Debt Expenses (181) 484,827 484,827
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs
(182.2)
57 Other Regulatory Assets (182.3) 9,526,405 9,526,405
58 Prelim. Survey and Investigation Charges
(Electric) (183)
59 Prelim. Sur. and Invest. Charges (Gas) (183.1,
183.2)
60 Clearing Accounts (184)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186)
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189)
66 Accumulated Deferred Income Taxes (190) 7,334,675 7,334,675
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of Lines 54 17,345,907 17,345,907
thru 67)
69 TOTAL Assets and other Debits (Enter Total of 145,458,573 145,458,573
lines 10, 11, 12, 22, 52 and 68)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 3 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS )
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock Issued (201) 82,500 82,500
3 Preferred Stock Issued (204)
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 16,417,499 16,417,499
7 Other Paid-In Capital (208-211) 13,593,689 13,593,689
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 90,276 90,276
12 Unappropriated Undistributed Subsidiary Earnings
(216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of Lines 30,183,964 30,183,964
2 thru 13)
15 LONG-TERM DEBT
16 Bonds (221)
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223) 48,500,000 48,500,000
19 Other Long-Term Debt (224)
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 48,500,000 48,500,000
thru 21)
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227) 26,559,367 26,559,367
25 Accumulated Provision for Property Insurance
(228.1)
26 Accumulated Provision for Injuries and Damages
(228.2)
27 Accumulated Provision for Pensions and Benefits
(228.3)
28 Accumulated Miscellaneous Operating Provisions
(228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total 26,559,367 26,559,367
of lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Notes Payable (231)
33 Accounts Payable (232) 35,002 35,002
34 Notes Payable to Associated Companies (233) 1,700,000 1,700,000
35 Accounts Payable to Associated Companies (234) 580,708 580,708
36 Customer Deposits (235)
37 Taxes Accrued (236) 856,767 856,767
38 Interest Accrued (237) 190,392 190,392
39 Dividends Declared (238)
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241)
43 Miscellaneous Current and Accrued Liabilities 112,006 112,006
(242)
44 Obligations Under Capital Leases - Current (243) 1,577,784 1,577,784
45 TOTAL Current and Accrued Liabilities (Enter 5,052,659 5,052,659
Total of lines 32 thru 44)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 4 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 4,636,578 4,636,578
49 Deferred Gains from Disposition of Utility Plant
(256)
50 Other Deferred Credits (253)
51 Other Regulatory Liabilities (254) 5,061,420 5,061,420
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 25,464,585 25,464,585
54 TOTAL Deferred Credits (Enter Total of Lines 47
thru 53) 35,162,583 35,162,583
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter Total 145,458,573 145,458,573
of Lines 14, 22, 30, 45, and 54)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 5 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Balance at Pro-Forma Balance at
No. Item 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
2 In Service
<S> <C> <C> <C>
3 Plant in Service (Classified) 134,048,639 134,048,639
4 Property Under Capital Leases 28,137,151 28,137,151
5 Plant Purchased or Sold
6 Completed Construction not Classified 11,059,879 11,059,879
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 173,245,669 173,245,669
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of
lines 8 thru 12) 173,245,669 173,245,669
14 Accum. Prov. for Depr., Amort., and Depl. 45,222,278 45,222,278
15 Net Utility Plant (Enter Total of line 13
less 14) 128,023,391 128,023,391
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND
DEPLETION
17 In service:
18 Depreciation 45,222,278 45,222,278
18 Amort. and Depl. of Producing Natural Gas & Land
Rights
20 Amort. of Underground Storage Land and Land
Rights
21 Amort. of Other Utility Plant
22 TOTAL In Service (Enter Total of lines 18
thru 21) 45,222,278 45,222,278
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree
with line 14 above) (Enter Total of lines 22,
26, 30, 31 and 32) 45,222,278 45,222,278
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 6 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 220,637,167 220,637,167
3 Construction Work In Progress (107)
4 TOTAL UTILITY PLANT (Enter Total of lines
2 and 3) 220,637,167 220,637,167
5 (Less) Accum. Prov. for Depr. Amort.
Depl. (108, 111, 115) 68,342,093 68,342,093
6 Net Utility Plant (enter Total of Line 4
Less 5) 152,295,074 152,295,074
7 Nuclear Fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl.
Assemblies (120.5)
9 Net Nuclear Fuel (Enter Total of line 7
Less 8)
10 Net Utility Plan (Enter Total of lines 6
and 9) 152,295,074 152,295,074
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121)
15 (Less) Accum. Prov. for Depr. and Amort.
(122)
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1) 5,000 5,000
18 (For Cost of Account 123.1, See Footnote
Page 224, Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124)
21 Special Funds (125-128)
22 TOTAL Other Property and Investments
(Total of lines 14-17, 19-21) 5,000 5,000
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 17,360 17,360
25 Special Deposits (132-134)
26 Working Fund (135)
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142)
30 Other Accounts Receivable (143) (20,450) (20,450)
31 (Less) Accum. Prov. for Uncollectible
Acct.-Credit (144)
32 Notes Receivable from Associated
Companies (145) 4,675,000 4,675,000
33 Accounts Receivable from Assoc. Companies
(146) 3,582 3,582
34 Fuel Stock (151)
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products
(153)
37 Plant Materials and Operating Supplies (154) 1,919,818 1,919,818
38 Merchandise (155)
39 Other Materials Held for Sale (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 40,624 40,624
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171) 24,188 24,188
49 Rents Receivable (172)
50 Accrued Utility Revenues (173)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 7 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
51 Miscellaneous Current and Accrued Assets
(174) 4,607 4,607
52 TOTAL Current and Accrued Assets (Enter
Total of lines 24 thru 51) 6,664,729 6,664,729
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 8 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
53 DEFERRED DEBITS
<S> <C> <C> <C>
54 Unamortized Debt Expenses (181) 728,307 728,307
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs
(182.1)
57 Other Regulatory Assets (182.3) 10,655,530 10,655,530
58 Prelim. Survey and Investigation Charges
(Electric) (183)
59 Prelim Sur. and Invest. Charges (Gas)
(183.1, 183.2)
60 Cleaning Accounts (184)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186)
63 Def. Losses from Disposition of Utility Pit.
(187)
64 Research, Devel. and Demonstration Expend.
(188)
65 Unamortized Loss on Reacquired Debt (189)
66 Accumulated Deferred Income Taxes (190) 11,839,622 11,839,622
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter total of lines 23,223,459 23,223,459
54 thru 67)
69 TOTAL Assets and other Debits (Enter Total
of lines 10, 11, 12, 22, 52, and 68) 182,188,262 182,188,262
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 9 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock Issued (201) 3,700,014 3,700,014
3 Preferred Stock Issued (204)
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 33,300,130 33,200,130
7 Other Paid-in Capital (208-211) 15,155,770 15,155,770
8 Installments Received on Capital Stock
(212)
9 (Less) Discount on Captial Stock (213)
10 (Less) Capital Stock expense (214)
11 Retained Earnings (215, 215.1, 216) 96,398 96,398
12 Unappropriated Undistributed Subsidiary
Earnings (216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of
Lines 2 thru 13) 52,252,312 52,252,312
15 LONG-TERM DEBT
16 Bonds (221)
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223) 79,350,000 79,350,000
19 Other Long-Term (224)
20 Unamortized Premium on Long-Term Debt
(225)
21 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of 79,350,000 79,350,000
Lines 16 thru 21
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital
Leases-Noncurrent (227)
25 Accumulated Provision for Property
Insurance (228.1)
26 Accumulated Provision for Injuries and
Damages (228.2)
27 Accumulated Provision for Pensions and
Benefits (228.3)
28 Accumulated Miscellaneous Operating
Provisions (228.4)
29 Accumulated Provision for Rate Refunds
(229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total of lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Notes Payable (231)
33 Accounts Payable (232) 456,426 456,426
34 Notes Payable to Associated Companies (233)
35 Accounts Payable to Associated Companies 76,152 76,152
(234)
36 Customer Deposits (235)
37 Taxes Accrued (236) 602,704 602,704
38 Interest Accrued (237) 304,689 304,689
39 Dividends Declared (238)
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241) 3,690 3,690
43 Miscellaneous Current and Accrued
Liabilities (242) 438,813 438,813
44 Obligations Under Capital Leases -
Current (243)
45 TOTAL Current and Accrued Liabilities
(Enter Total of lines 32 thru 44) 1,882,474 1,882,474
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-5
Page 10 of 11
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Balance at Pro-Forma Balance at
No. Title of Account 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 7,991,098 7,991,098
49 Deferred Gains from Disposition of Utility
Plant (256)
50 Other Deferred Credits (253)
51 Other Regulatory Liabilities (254) 7,334,350 7,334,350
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 33,378,028 33,378,028
54 TOTAL Deferred Credits (Enter Total of
Lines 47 thru 53) 48,703,476 48,703,476
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter
Total of Lines 14,22,30,45, and 54) 182,188,262 182,188,262
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. C-6
Page 11 of 11
Name of Respondent
New England Hydro Transmission Electric Company
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION At September 30, 1998
Adjusted
Line Balance at Pro-Forma Balance at
No. Item 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified 220,637,167 220,637,167
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 220,637,167 220,637,167
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of lines
8 thru 12) 220,637,167 220,637,167
14 Accum. Prov. for Depr. Amort., and Depl. 68,342,093 68,342,093
15 Net Utility Plant (Enter Total of line 13 220,637,167 220,637,167
less 14) 220,637,167 220,637,167
16 DETAIL OF ACCUMULATED PROVISIONS FOR
DEPRECIATION, AMORTIZATION AND DEPLETION
17 In Service:
18 Depreciation 68,123,593 68,123,593
19 Amort. and Depl. of Producing Natural Gas &
Land Rights
20 Amort. of Underground Storage Land and Land
Rights
21 Amort. of Other Utility Plant 218,500 218,500
22 TOTAL In Service (Enter Total of lines 18
thru 12) 68,342,093 68,342,093
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of
lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree
with line 14 above) (Enter total of lines 22, 26,
30, 31 and 32) 68,342,093 68,342,093
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. C-7
Page 1 of 5
Name of Respondent
Montaup ElectricCompany At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 571,772,660 571,772,660
3 Construction Work in Progress (107) 3,683,654 3,683,654
4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 575,456,314 575,456,314
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108,
111, 115) 202,785,329 202,785,329
6 Net Utility Plant (Enter Total of line 4 Less 5) 372,670,985 372,670,985
7 Nuclear Fuel (120.1-120.4, 120.6) 10,322,443 10,322,443
8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies
(120.5) 5,988,016 5,988,016
9 Net Nuclear Fuel (Enter Total of line 7 Less 8) 4,334,427 4,334,427
10 Net Utility Plant (Enter Total of lines 6 and 9) 377,005,412 377,055,412
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121) 2,446,513 2,446,513
15 (Less) Accum. Prov. for Depr. and Amort. (122)
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1) 13,129,910 13,129,910
18 (for Cost of Account 123.1, See footnote Page 224,
Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124)
21 Special Funds (125-128) 7,726,838 7,726,838
22 TOTAL Other Property and Investments (Total of
lines 14-17, 19-21) 23,303,261 23,303,261
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 193,458 193,458
25 Special Deposits (132-134)
26 Working Fund (135) 5,800 5,800
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 3,117,329 3,117,329
30 Other Accounts Receivable (143) 428,048 428,048
31 (Less) Accum. Prov. for Uncollectible Acct-Credit (144)
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146) 60,613,693 60,613,693
34 Fuel Stock (151) 5,156,045 5,156,045
35 Fuel Stock Expenses Undistributed (152) 102,418 102,418
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 1,918,242 1,918,242
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2) 18,050 18,050
42 (Less) Noncurrent Potion of Allowances
43 Stores Expense Undistributed (163) 70,258 70,258
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 2,855,763 2,855,763
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171)
49 Rents Receivable (172) 65,548 65,548
50 Accrued Utility Revenues (173)
51 Miscellaneous Current and Accrued Assets (174) 97,458 97,458
52 TOTAL Current and Accrued Assets (Enter Total of 74,642,110 74,642,110
lines 24 thru 51)
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-7
Page 2 of 5
Name of Respondent
Montaup Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
53 DEFERRED DEBITS
54 Unamoritzed Debt Expenses (181) 22,321 22,321
55 Extraordinary Property Losses (182.2)
56 Unrecovered Plant and Regulatory Study Costs (182.2) 60,672,177 60,672,177
57 Other Regulatory Assets (182.3) 77,096,573 77,096,573
58 Prelim. Survey and Investigation Charges (Electric (183) (550,692) (550,692)
59 Prelim Sur. and Invest. Charges (Gas) (183.1, 183.2)
60 Clearing Accounts (184)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 9,752,754 9,752,754
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189) 9,998,437 9,998,437
66 Accumulated Deferred Income Taxes (190) 7,908,353 7,908,353
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter total of lines 54 thru 67) 164,899,923 164,899,923
69 TOTAL Assets and other Debits (Enter Total of
lines 10,11,22,52, and 68) 639,850,706 639,850,706
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-7
Page 3 of 5
Name of Respondent
Montaup ElectricCompany At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock issued (201) 58,600,000 58,600,000
3 Preferred Stock Issued (204) 1,500,000 1,500,000
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207)
7 Other Paid-in Capital (208-211) 29,528,000 29,528,000
8 Installments Received on Capital Stock (212)
9 (Less) discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 69,730,306 69,730,306
12 Unappropriated Undistributed Subsidiary Earnings (216.1) 4,059,386 4,059,386
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of
Lines 2 thru 13) 163,417,692 163,417,692
15 LONG-TERM DEBT
16 Bonds (221) 172,913,929 172,913,929
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-term Debt (224)
20 Unamortized Premium on Long-Term Debt (226)
21 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 172,913,929 172,913,929
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227)
25 Accumulated Provision for Property Insurance (228.1)
26 Accumulated Provision for Injuries and Damages (228.2)
27 Accumulated Provision for Pensions and Benefits (228.3) 542,945 542,945
28 Accumulated Miscellaneous Operating Provisions (228.4) 431,750 431,750
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total of
lines 24 thru 29) 974,695 974,695
31 CURRENT AND ACCRUED LIABILITIES 32 Notes Payable (231)
33 Accounts Payable (232) 23,632,257 23,632,257
34 Notes Payable to Associated Companies (233)
35 Accounts Payable to Associated Companies (234) 13,549,498 13,549,498
36 Customer Deposits (235)
37 Taxes Accrued (236) 2,154,094 2,154,094
38 Interest Accrued (237) 5,745,563 5,745,563
39 Dividends Declared (238)
40 Matured Long-Term Debt (239)
41 Matured Interests (240)
42 Tax Collections Payable (241) 8,225 8,225
43 Miscellaneous Current and Accrued Liabilities (242) 1,644,957 1,644,957
44 Obligations Under Capital Leases - Current (243)
45 TOTAL Current and Accrued Liabilities (Enter Total
of lines 32 thru 44) 46,734,594 46,734,594
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-7
Page 4 of 5
Name of Respondent
Montaup Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 11,605,710 11,605,710
49 Deferred Gains from Disposition of Utility Plant (256)
50 Other Deferred Credits (253) 77,065,660 77,065,660
51 Other Regulatory Liabilities (2540 36,757,546 36,757,546
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 130,380,880 130,380,880
54 TOTAL Deferred Credits (Enter Total of
Lines 47 thru 53) 255,809,796 255,809,796
55
56
57
58
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter Total of 639,850,706 639,850,706
Lines 14, 22, 30, 45, and 54)
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-7
Page 5 of 5
Name of Respondent
Montaup Electric Company At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
2 In Service
<S> <C> <C> <C>
3 Plant in Service (Classified) 566,134,233 566,134,233
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 566,134,233 566,134,233
9 Leased to Others
10 Held for Future Use 5,638,427 5,638,427
11 Construction Work in Progress 3,683,654 3,683,654
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of
lines 8 thru 12) 575,456,314 575,456,314
14 Accum. Prov. for Depr., Amort., and Depl.
15 Net Utility Plant (Enter Total of line 13
less 14) 575,456,314 575,456,314
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 195,038,776 195,038,776
19 Amort. and Depl. of Producing Natural Gas & Land
Rights
20 Amort. of Underground Storage Land and Land Rights
21 Amort. of Other Utility Plant 64,099 64,099
22 TOTAL In Service (Enter Total of lines 18
thru 21) 195,102,875 195,102,875
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree
with line 14 above (Enter Total of lines 22, 26,
30, 31 and 32) 195,102,875 195,102,875
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. C-8
Page 1 of 5
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 142,289,834 142,289,834
3 Construction Work in Progress (107) 3,022,539 3,022,539
4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 145,312,373 145,312,373
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 59,929,466 59,929,466
111, 115)
6 Net Utility Plant (Enter Total of line 4 Less 5) 85,382,907 85,382,907
7 Nuclear Fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies
(120.5)
9 Net Nuclear Fuel (Enter Total of line 7 less 8)
10 Net Utility Plant (Enter Total of lines 6 and 9) 85,382,907 85,382,907
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121) 70,206 70,206
15 (Less) Accum. Prov. For Depr. and Amort. (122) 26,248 26,248
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1)
18 (For Cost of Account 123.1, See Footnote Page 224,
Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124)
21 Special Funds (125-128) 7,325,402 7,325,402
22 TOTAL Other Property and Investments (Total of 7,369,360 7,369,360
lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 730,073 730,073
25 Special Deposits (132-134)
26 Working Fund (135) 22,700 22,700
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 11,149,804 11,149,804
30 Other Accounts Receivable (143) 4,517,229 4,517,229
31 (Less) Accum. Prov. Uncollectible Acct.-Credit (144) 150,333 150,333
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146) 436,116 436,116
34 Fuel Stock (151)
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec.) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 833,765 833,765
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163) (27,692) (27,692)
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 159,800 159,800
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171)
49 Rents Receivable (172)
50 Accrued Utility Revenues (173) 2,584,848 2,584,848
51 Miscellaneous Current and Accrued Assets (174) 132,130 132,130
52 TOTAL Current and Accrued Assets ( Enter Total of
lines 24 thru 51) 20,388,440 20,388,440
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-8
Page 2 of 5
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
53 DEFERRED DEBITS
<S> <C> <C> <C>
54 Unamortized Debt Expenses (181) 548,775 548,775
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs (182.2)
57 Other Regulatory Assets (182.3) 13,582,789 13,582,789
58 Prelim. Survey and Investigation Charges (Electric)(183)
59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2)
60 Clearing Accounts (184) (365) (365)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 7,331,798 7,331,798
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189) 371,387 371,387
66 Accumulated Deferred Income Taxes (190) 2,767,376 2,767,376
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of lines 54 thru 67) 24,601,760 24,601,760
69 TOTAL Assets and other Debits (Enter Total of lines
10, 11, 12, 22, 52, and 68) 137,742,467 137,742,467
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-8
Page 3 of 5
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock Issued (201) 9,203,100 9,203,100
3 Preferred Stock Issued (204) 6,000,000 6,000,000
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 737,430 737,430
7 Other Paid-in Capital (208-211) 17,300,000 17,300,000
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214)
11 Retained Earnings (215, 215.1, 216) 13,679,581 13,679,581
12 Unappropriated Undistributed Subsidiary Earnings (216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of Lines 2
thru 13) 46,920,111 42,920,111
15 LONG-TERM DEBT
16 Bonds (221) 33,500,000 33,500,00
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224)
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 33,500,000 33,500,000
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227)
25 Accumulated Provision for Property Insurance (228.1)
26 Accumulated Provision for Injuries and Damages (228.2)
27 Accumulated Provision for Pensions and Benefits (228.3) 3,818,586 3,818,586
28 Accumulated Miscellaneous Operating Provisions (228.4) 7,325,403 7,325,403
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total of
lines 24 thru 29) 11,143,989 11,143,989
31 CURRENT AND ACCRUED LIABILITIES
32 Note Payable (231) 2,350,000 2,350,000
33 Accounts Payable (232) 376,329 376,329
34 Notes Payable to Associated Companies (233)
35 Accounts Payable to Associated Companies (234) 12,570,244 12,570,244
36 Customer Deposits (235) 970,789 970,789
37 Taxes Accrued (236) 1,468,909 1,468,909
38 Interest Accrued (237) 1,039,448 1,039,448
39 Dividends Declared (238) 72,188 72,188
40 Matured Long-Term Debt (239)
41 Matured Interest (240)
42 Tax Collections Payable (241) 195,296 195,296
43 Miscellaneous Current and Accrued Liabilities (242) 4,863,514 4,863,514
44 Obligations Under Capital Leases - Current (243)
45 TOTAL Current and Accrued Liabilities (Enter Total
of lines 32 thru 44) 23,906,717 23,906,717
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-8
Page 4 of 5
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 2,246,686 2,246,686
49 Deferred Gains from Disposition of Utility Plant (256)
50 Other Deferred Credits (253) 337,205 337,205
51 Other Regulatory Liabilities (254) 3,747,169 3,747,169
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 15,940,590 15,940,590
54 TOTAL Deferred Credits (Enter Total of Lines 47 thru
53) 22,271,650 22,271,650
55
56
57
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter Total of 137,742,467 137,742,467
Lines 14, 22,30,45, and 54)
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-8
Page 5 of 5
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION Page 1 of 5
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
2 In Service
<S> <C> <C> <C>
3 Plant in Service (Classified) 142,289,834 142,289,834
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 142,289,834 142,289,834
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress 3,022,539 3,022,539
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of lines 8
thru 12) 145,312,373 145,312,373
14 Accum. Prov. for Depr., Amort., and Depl. 59,929,466 59,929,466
15 Net Utility Plant (Enter Total of line 13
less 14) 85,382,907 85,382,907
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 59,929,466 59,929,466
19 Amort. and Depl. of Producing Natural Gas & Land
Rights
20 Amort. of Underground Storage Land and Land
Rights
21 Amort. of Other Utility Plant
22 TOTAL In Service (Enter Total of lines 18
thru 21) 59,929,466 59,929,466
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree
with line 14 above) (Enter Total of lines 22, 26,
30, 31 and 32) 59,929,466 59,929,466
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. C-9
Page 1 of 5
Name of Respondent
Eastern Edison Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 Utility Plant (101-106, 114) 239,866,645 239,866,645
3 Construction Work in Progress (107) 6,724,868 6,724,868
4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 246,591,513 246,591,513
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108,
111, 115) 95,357,566 95,357,566
6 Net Utility Plant (Enter Total of line 4 Less 5) 151,233,947 151,233,947
7 Nuclear Fuel (120.1-142.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies
(120.5)
9 Net Nuclear Fuel (Enter Total of line 7 less 8)
10 Net Utility Plant (Enter Total of lines 6 and 9) 151,233,947 151,233,947
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121) 105,734 105,734
15 (Less) Accum. Prov. For Depr. and Amort. (122) 9,697 9,697
16 Investments in Associated Companies (123) 306,803,621 306,803,621
17 Investment in Subsidiary Companies (123.1) 29,528,000 29,528,000
18 (For Cost of Account 123.1, See Footnote Page 224,
Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124) 10,405 10,405
21 Special Funds (125-128)
22 TOTAL Other Property and Investments (Total of
lines 14-17, 19-21) 336,438,063 336,438,063
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 92,204 92,204
25 Special Deposits (132-134)
26 Working Fund (135) 13,200 13,200
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 24,582,138 24,582,138
30 Other Accounts Receivable (143) 7,458,318 7,458,318
31 (Less) Accum. Prov. Uncollectible Acct.-Credit (144)
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146) 16,702,455 16,702,455
34 Fuel Stock (151)
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 1,955,186 1,955,186
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163) 82,313 82,313
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 431,655 431,655
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171)
49 Rents Receivable (172)
50 Accrued Utility Revenues (173) 5,552,427 5,552,427
51 Miscellaneous Current and Accrued Assets (174) 256,505 256,505
52 TOTAL Current and Accrued Assets ( Enter Total of
lines 24 thru 51) 57,126,401 57,126,401
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-9
Page 2 of 5
Name of Respondent
Eastern Edison Company At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
53 DEFERRED DEBITS
<S> <C> <C> <C>
54 Unamortized Debt Expenses (181) 1,841,761 1,841,761
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs (182.2)
57 Other Regulatory Assets (182.3) 7,121,375 7,121,375
58 Prelim. Survey and Investigation Charges (Electric)(183)
59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2)
60 Clearing Accounts (184) 3,175 3,175
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 9,678,602 9,678,602
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189) 572,909 572,909
66 Accumulated Deferred Income Taxes (190) 6,051,869 6,051,869
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of
lines 54 thru 67) 25,269,691 25,269,691
69 TOTAL Assets and other Debits (Enter Total of lines
10, 11, 12, 22, 52, and 68) 570,068,102 570,068,102
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-9
Page 3 of 5
Name of Respondent
Eastern Edison Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 PROPRIETARY CAPITAL
<S> <C> <C> <C>
2 Common Stock Issued (201) 72,283,925 72,283,925
3 Preferred Stock Issued (204) 30,000,000 30,000,000
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207) 5,824,633 5,824,633
7 Other Paid-in Capital (208-211) 39,663,601 39,663,601
8 Installments Received on Capital Stock (212)
9 (Less) discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214) 379,410 379,410
11 Retained Earnings (215, 215.1, 216) 25,671,690 25,671,690
12 Unappropriated Undistributed Subsidiary Earnings
(216.1) 73,789,692 73,789,692
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of Lines 2
thru 13) 246,854,131 246,854,131
15 LONG-TERM DEBT
16 Bonds (221) 163,000,000 163,000,000
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224)
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term 458,781 458,781
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 162,541,219 162,541,219
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227)
25 Accumulated Provision for Property Insurance (228.1)
26 Accumulated Provision for Injuries and Damages (228.2)
27 Accumulated Provision for Pensions and Benefits (228.3) 5,208,566 5,208,566
28 Accumulated Miscellaneous Operating Provisions (228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total of
lines 24 thru 29) 5,208,566 5,208,566
31 CURRENT AND ACCRUED LIABILITIES
32 Note Payable (231) 52,195,000 52,195,000
33 Accounts Payable (232) 1,030,631 1,030,631
34 Notes Payable to Associated Companies (233)
35 Accounts Payable to Associated Companies (234) 52,383,867 52,383,867
36 Customer Deposits (235) 1,431,214 1,431,214
37 Taxes Accrued (236) (771,961) (771,961)
38 Interest Accrued (237) 3,876,191 3,876,191
39 Dividends Declared (238)
40 Matured Long-Term Debt (239)
41 Matured Interest (240)
42 Tax Collections Payable (241) 287,954 287,954
43 Miscellaneous Current and Accrued Liabilities (242) 9,525,902 9,525,902
44 Obligations Under Capital Leases - Current (243)
45 TOTAL Current and Accrued Liabilities (Enter Total
of lines 32 thru 44) 119,958,798 119,958,798
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-9
Page 4 of 5
Name of Respondent
Eastern Edison Company At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
46 DEFERRED CREDITS
<S> <C> <C> <C>
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 3,385,727 3,385,727
49 Deferred Gains from Disposition of Utility Plant (256)
50 Other Deferred Credits (253) 1,094,191 1,094,191
51 Other Regulatory Liabilities (254) 6,202,507 6,202,507
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 24,822,963 24,822,963
54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 35,505,388 35,505,388
53)
55
56
57
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter Total of 570,068,102 570,068,102
Lines 14, 22,30,45, and 54)
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-9
Page 5 of 5
Name of Respondent
Eastern Edison Company At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
1 UTILITY PLANT
<S> <C> <C> <C>
2 In Service
3 Plant in Service (Classified) 239,866,645 239,866,645
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 239,866,645 239,866,645
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress 6,724,868 6,724,868
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of lines 8
thru 12) 246,591,513 246,591,513
14 Accum. Prov. for Depr., Amort., and Depl. 95,357,566 95,357,566
15 Net Utility Plant (Enter Total of line 13
less 14) 151,233,947 151,233,947
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 95,357,566 95,357,566
19 Amort. and Depl. of Producing Natural Gas & Land
Rights
20 Amort. of Underground Storage Land and Land
Rights
21 Amort. of Other Utility Plant
22 TOTAL In Service (Enter Total of lines 18
thru 21) 95,357,566 95,357,566
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree
with line 14 above) (Enter Total of lines 22, 26,
30, 31 and 32) 95,357,566 95,357,566
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. C-10
Page 1 of 5
Name of Respondent
Newport Electric Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY PLANT
2 Utility Plant (101-106, 114) 82,995,307 82,995,307
3 Construction Work in Progress (107) 1,353,158 1,353,158
4 TOTAL UTILITY PLANT (Enter Total of lines 2 and 3) 84,348,465 84,348,465
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108,
111, 115) 29,066,441 29,066,441
6 Net Utility Plant (Enter Total of line 4 Less 5) 55,282,024 55,282,024
7 Nuclear Fuel (120.1-120.4, 120.6)
8 (Less) Accum. Prov. for Amort. of Nucl. Assemblies (120.5)
9 Net Nuclear Fuel (Enter Total of line 7 less 8)
10 Net Utility Plant (Enter Total of lines 6 and 9) 55,282,024 55,282,024
11 Utility Plant Adjustments (116)
12 Gas Stored Underground-Noncurrent (117)
13 OTHER PROPERTY AND INVESTMENTS
14 Nonutility Property (121)
15 (Less) Accum. Prov. for Depr. and Amort. (122)
16 Investments in Associated Companies (123)
17 Investment in Subsidiary Companies (123.1)
18 (For Cost of Account 123.1, See Footnote Page 224, Line 42)
19 Noncurrent Portion of Allowances
20 Other Investments (124)
21 Special Funds (125-128)
22 TOTAL Other Property and Investments (Total of
lines 14-17, 19-21)
23 CURRENT AND ACCRUED ASSETS
24 Cash (131) 269,892 269,892
25 Special Deposits (132-134)
26 Working Fund (135) 4,740 4,740
27 Temporary Cash Investments (136)
28 Notes Receivable (141)
29 Customer Accounts Receivable (142) 4,885,295 4,885,295
30 Other Accounts Receivable (143) 2,719,166 2,719,166
31 (Less) Accum. Prov. Uncollectible Acct.-Credit (144) 100,768 100,768
32 Notes Receivable from Associated Companies (145)
33 Accounts Receivable from Assoc. Companies (146) 261,182 261,182
34 Fuel Stock (151) 53,017 53,017
35 Fuel Stock Expenses Undistributed (152)
36 Residuals (Elec) and Extracted Products (153)
37 Plant Materials and Operating Supplies (154) 795,183 795,183
38 Merchandise (155)
39 Other Materials and Supplies (156)
40 Nuclear Materials Held for Sale (157)
41 Allowances (158.1 and 158.2)
42 (Less) Noncurrent Portion of Allowances
43 Stores Expense Undistributed (163) 57,108 57,108
44 Gas Stored Underground-Current (164.1)
45 Liquefied Natural Gas Stored and Held for
Processing (164.2-164.3)
46 Prepayments (165) 111,097 111,097
47 Advances for Gas (166-167)
48 Interest and Dividends Receivable (171)
49 Rents Receivable (172)
50 Accrued Utility Revenues (173) 1,245,890 1,245,890
51 Miscellaneous Current and Accrued Assets (174) 134,354 134,354
52 TOTAL Current and Accrued Assets ( Enter Total of
lines 24 thru 51) 10,436,156 10,436,156
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-10
Page 2 of 5
Name of Respondent
Newport Electric Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
53 DEFERRED DEBITS
54 Unamortized Debt Expenses (181) 371,814 371,814
55 Extraordinary Property Losses (182.1)
56 Unrecovered Plant and Regulatory Study Costs (182.2)
57 Other Regulatory Assets (182.3) 4,109,449 4,109,449
58 Prelim. Survey and Investigation Charges (Electric) (183)
59 Prelim. Sur. and Invest. Charges (Gas) (183.1, 183.2)
60 Clearing Accounts (184) (465) (465)
61 Temporary Facilities (185)
62 Miscellaneous Deferred Debits (186) 1,022,224 1,022,224
63 Def. Losses from Disposition of Utility Plt. (187)
64 Research, Devel. and Demonstration Expend. (188)
65 Unamortized Loss on Reacquired Debt (189) 285,162 285,162
66 Accumulated Deferred Income Taxes (190) 714,543 714,543
67 Unrecovered Purchased Gas Costs (191)
68 TOTAL Deferred Debits (Enter Total of lines 54 thru 67) 6,502,727 6,502,727
69 TOTAL Assets and other Debits (Enter Total of lines
10, 11, 12, 22, 52, and 68) 72,220,907 72,220,907
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-10
Page 3 of 5
Name of Respondent
Newport Electric Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201) 11,368,779 11,368,779
3 Preferred Stock Issued (204) 768,900 768,900
4 Capital Stock Subscribed (202, 205)
5 Stock Liability for Conversion (203, 206)
6 Premium on Capital Stock (207)
7 Other Paid-in Capital (208-211) 9,002,150 9,002,150
8 Installments Received on Capital Stock (212)
9 (Less) Discount on Capital Stock (213)
10 (Less) Capital Stock Expense (214) 742,214 742,214
11 Retained Earnings (215, 215.1, 216) 3,248,396 3,248,396
12 Unappropriated Undistributed Subsidiary Earnings (216.1)
13 (Less) Reacquired Capital Stock (217)
14 TOTAL Proprietary Capital (Enter Total of Lines 2
thru 13) 23,646,011 23,646,011
15 LONG-TERM DEBT
16 Bonds (221) 19,816,516 19,816,516
17 (Less) Reacquired Bonds (222)
18 Advances from Associated Companies (223)
19 Other Long-Term Debt (224)
20 Unamortized Premium on Long-Term Debt (225)
21 (Less) Unamortized Discount on Long-Term
Debt-Debit (226)
22 TOTAL Long-Term Debt (Enter Total of Lines 16 thru 21) 19,816,516 19,816,516
23 OTHER NONCURRENT LIABILITIES
24 Obligations Under Capital Leases-Noncurrent (227)
25 Accumulated Provision for Property Insurance (228.1)
26 Accumulated Provision for Injuries and Damages (228.2)
27 Accumulated Provision for Pensions and Benefits (228.3)
28 Accumulated Miscellaneous Operating Provisions (228.4)
29 Accumulated Provision for Rate Refunds (229)
30 TOTAL OTHER Noncurrent Liabilities (Enter Total of
lines 24 thru 29)
31 CURRENT AND ACCRUED LIABILITIES
32 Note Payable (231) 5,120,000 5,120,000
33 Accounts Payable (232) 127,057 127,057
34 Notes Payable to Associated Companies (233)
35 Accounts Payable to Associated Companies (234) 7,019,840 7,019,840
36 Customer Deposits (235) 577,209 577,209
37 Taxes Accrued (236) 586,675 586,675
38 Interest Accrued (237) 218,317 218,317
39 Dividends Declared (238) 7,208 7,208
40 Matured Long-Term Debt (239)
41 Matured Interest (240)
42 Tax Collections Payable (241) 121,652 121,652
43 Miscellaneous Current and Accrued Liabilities (242) 951,242 951,242
44 Obligations Under Capital Leases - Current (243)
45 TOTAL Current and Accrued Liabilities (Enter Total
of lines 32 thru 44) 14,729,200 14,729,200
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-10
Page 4 of 5
Name of Respondent
Newport Electric Corporation At September 30, 1998
COMPARATIVE BALANCE SHEET (LIABILITIES AND CREDITS) (Continued)
Adjusted
Line Title of Account Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
46 DEFERRED CREDITS
47 Customer Advances for Construction (252)
48 Accumulated Deferred Investment Tax Credits (255) 1,060,284 1,060,284
49 Deferred Gains from Disposition of Utility Plant (256)
50 Other Deferred Credits (253) 1,524,300 1,524,300
51 Other Regulatory Liabilities (254) 1,268,555 1,268,555
52 Unamortized Gain on Reacquired Debt (257)
53 Accumulated Deferred Income Taxes (281-283) 10,176,041 10,176,041
54 TOTAL Deferred Credits (Enter Total of Lines 47 thru 53) 14,029,180 14,029,180
55
56
57
59
60
61
62
63
64
65
66
67
68 Total Liabilities and Other Credits (Enter Total of 72,220,907 72,220,907
Lines 14, 22,30,45, and 54)
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. C-10
Page 5 of 5
Name of Respondent
Newport Electric Corporation At September 30, 1998
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISION
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY PLANT
2 In Service
3 Plant in Service (Classified) 82,779,252 82,779,252
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Enter Total of lines 3 thru 7) 82,779,252 82,779,252
9 Leased to Others
10 Held for Future Use 216,055 216,055
11 Construction Work in Progress 1,353,158 1,353,158
12 Acquisition Adjustments
13 Total Utility Plant (Enter total of lines 8
thru 12) 84,348,465 84,348,465
14 Accum. Prov. for Depr., Amort., and Depl. 29,066,441 29,066,441
15 Net Utility Plant (Enter Total of line 13
less 14) 55,282,024 55,282,024
16 DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION,
AMORTIZATION AND DEPLETION
17 In service:
18 Depreciation 28,721,895 28,721,895
19 Amort. and Depl. of Producing Natural Gas & Land
Rights
20 Amort. of Underground Storage Land and Land
Rights
21 Amort. of Other Utility Plant 344,546 344,546
22 TOTAL In Service (Enter Total of lines 18 thru 21) 29,066,441 29,066,441
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 TOTAL Leased to Others (Enter Total of lines 24 and 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (Enter Total of
lines 28 and 29)
31 Abandonment of Leases (Natural Gas)
32 Amort. of Plant Acquisition Adj.
33 Total Accumulated Provisions (Should agree
with line 14 above) (Enter Total of lines 22, 26,
30, 31 and 32) 29,066,441 29,066,441
</TABLE>
<PAGE>
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, et al.
AND MONTAUP ELECTRIC COMPANY, et al.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT D-1 New England Power Company
EXHIBIT D-2 Massachusetts Electric Company
EXHIBIT D-3 The Narragansett Electric Company
EXHIBIT D-4 New England Electric Transmission Corporation
EXHIBIT D-5 New England Hydro Transmission Corporation
EXHIBIT D-6 New England Hydro - Transmission Electric Company, Inc.
EXHIBIT D-7 Montaup Electric Company
EXHIBIT D-8 Blackstone Valley Electric Company
EXHIBIT D-9 Eastern Edison Company
EXHIBIT D-10 Newport Electric Corporation
Statement of all Known Contingent Liabilities
<PAGE>
EXHIBIT D-1 Page 1 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note A - Hazardous Waste
- ------------------------
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict, joint
and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in
its operations a range of potentially hazardous products and by-products. New
England Power Company (the Company) currently has in place an internal
environmental audit program and an external waste disposal vendor audit and
qualification program intended to enhance compliance with existing federal,
state, and local requirements regarding the handling of potentially hazardous
products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the United States Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for six sites at which hazardous waste is
alleged to have been disposed. Private parties have also contacted or initiated
legal proceedings against the Company regarding hazardous waste cleanup. The
Company is currently aware of other possible hazardous waste sites, and may in
the future become aware of additional sites, that it may be held responsible for
remediating.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant uncertainties
as to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by the Company. The
New England Electric System (NEES) companies have recovered amounts from certain
insurers and other third parties, and, where appropriate, the Company intends to
seek recovery from other insurers and from other PRPs, but it is uncertain
whether, and to what extent, such efforts will be successful. The Company
believes that hazardous waste liabilities for all sites of which it is aware are
not material to its financial position.
<PAGE>
EXHIBIT D-1 Page 2 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note B - Nuclear Units
- ----------------------
Yankee Nuclear Power Companies (Yankees)
A summary of combined results of operations, assets and liabilities of
the four Yankee Nuclear Power Companies in which the Company has investments is
as follows:
<TABLE>
<CAPTION>
Twelve Months Ended
September 30,
----------------------------
1998 1997
---- ----
(In Thousands)
<S> <C> <C>
Operating revenue $480,305 $767,441
-------- --------
Net Income $ 29,194 $ 29,594
-------- --------
Company's equity in
net income $ 5,467 $ 4,898
-------- --------
September 30, September 30,
1998 1997
---- ----
(In Thousands)
Net plant $ 177,372 $ 420,918
Other assets 2,958,662 2,225,214
Liabilities and debt (2,875,214) (2,374,643)
------------ ------------
Net assets $ 260,820 $ 271,489
------------ ------------
Company's equity in $ 48,203 $ 50,370
net assets ------------ ------------
</TABLE>
At September 30, 1998, $14,259,000 of undistributed earnings of the
nuclear power companies were included in the Company's retained earnings.
<PAGE>
EXHIBIT D-1 Page 3 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note B - Nuclear Units - continued
- ----------------------
Nuclear Units Permanently Shut Down
Three regional nuclear generating companies in which the Company has a
minority interest own nuclear generating units which have been permanently shut
down. These three units are as follows:
<TABLE>
<CAPTION>
NEP's Investment Future Estimated
Unit Percent Amount($) Date Retired Billings to NEP($)
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
<S> <C> <C> <C> <C>
Yankee Atomic 30 6 million Feb 1992 33 million
Connecticut Yankee 15 15 million Dec 1996 83 million
Maine Yankee 20 16 million Aug 1997 145 million
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
</TABLE>
In the case of each of these units, the Company has recorded an
estimate of the total future payment obligation as a liability and an offsetting
regulatory asset, reflecting estimated future billings from the companies. In a
1993 decision, the FERC allowed Yankee Atomic to recover its undepreciated
investment in the plant as well as unfunded nuclear decommissioning costs and
other costs. The Company's industry restructuring settlements allow it to
recover all costs that the FERC allows these Yankee companies to bill to the
Company. Connecticut Yankee and Maine Yankee have both filed similar requests
with the FERC. Several parties have intervened in opposition to both filings. On
August 31, 1998, a FERC Administrative Law Judge (ALJ) issued an initial
decision which would allow for full recovery of Connecticut Yankee's unrecovered
investment, but precluded a return on that investment. The ALJ's initial
decision is subject to review and approval by the FERC. Connecticut Yankee, the
Company, and other parties have filed exceptions to the ALJ's decision with the
FERC. Should the FERC uphold the ALJ's initial decision in its current form, the
Company's share of the loss of the return component would total approximately
$12 million to $15 million before taxes.
The Citizen's Awareness Network and Nuclear Information and Resource
Service have indicated their intention to file a request with the Nuclear
Regulatory commission (NRC) designed to overturn a current NRC rule on
decommissioning. The Company cannot predict what impact, if any, these
activities, if successful, would have on the cost of decommissioning the plants.
<PAGE>
EXHIBIT D-1 Page 4 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note B - Nuclear Units - continued
- ----------------------
At Main Yankee, the NRC issued a notice of violation on October 8,
1998 for issues identified prior to the shut down of the plant in August 1997.
The NRC did not assess any civil penalties related to the notice of violation.
In the 1970s, the Company and several other shareholders (Sponsors) of
Maine Yankee entered into 27 contracts (Secondary Purchase Agreements) under
which they sold portions of their entitlements to Maine Yankee power output
through 2002 to various entities, primarily municipal and cooperative systems in
New England (Secondary Purchasers). Virtually all of the Secondary Purchasers
have ceased making payments under the Secondary Purchase Agreements and have
demanded arbitration, claiming that such agreements excuse further payments upon
plant shutdown. The motion of the Secondary Purchasers to compel arbitration was
denied by the Maine Superior Court on the grounds that the FERC has
jurisdiction. The Secondary Purchasers are appealing this decision to the Maine
Supreme Judicial Court. The Company has asked the FERC to enforce the Company's
rights under the agreements. In the event that no further payments are
forthcoming from Secondary Purchasers, the Company, as a primary obligor to
Maine Yankee, would be required to pay an additional $7 million of future
shutdown costs. These costs are not included in the $145 million estimate
disclosed in the table above. Shutdown costs are recoverable from customers
under the industry restructuring settlements.
A Maine statute provides that if both Maine Yankee and its
decommissioning trust fund have insufficient assets to pay for the plant
decommissioning, the owners of Maine Yankee are jointly and severally liable for
the shortfall.
Operating Nuclear Units
The Company has minority interests in three other nuclear generating
units, Vermont Yankee, Millstone 3, and Seabrook 1. Uncertainties regarding the
future of nuclear generating stations, particularly older units, such as Vermont
Yankee, are increasing rapidly and could adversely affect their service lives,
availability, and costs. These uncertainties stem from a combination of factors,
including the acceleration of competitive pressures in the power generation
industry and increased NRC scrutiny. The company performs periodic economic
viability reviews of operating nuclear units in which it holds ownership
interests.
<PAGE>
EXHIBIT D-1 Page 5 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note B - Nuclear Units - continued
- ----------------------
Millstone 3
In April 1996, the NRC ordered Millstone 3, which had experienced
numerous technical and nontechnical problems, to shut down pending verification
that the unit's operations were in accordance with NRC regulations and the
unit's operating license. In July 1998, Millstone 3 returned to full operation.
Millstone 3 remains on the NRC "Watch List," signifying that it continues to
warrant increased NRC attention. Millstone 3 is operated by a subsidiary of
Northeast Utilities (NU). The Company is not an owner of the Millstone 2 nuclear
generating unit, which is temporarily shut down under NRC orders, or the
Millstone 1 nuclear generating unit, which has been permanently shut down.
During the Millstone 3 outage, the Company incurred an estimated $45
million in incremental replacement power costs. Through February 1998, when most
of the Company's power sales were subject to a fuel clause, the Company
recovered its incremental replacement power costs from customers through its
fuel clause. Starting in March 1998, most of the Company's power sales are at a
stated rate which is not subject to a fuel clause. However, certain true-up
mechanisms exist in lieu of the fuel clause, which cover most of these costs.
Several criminal investigations related to Millstone 3 are ongoing. In
December 1997, the NRC assessed civil penalties totaling $2.1 million for
numerous violations at the three Millstone units. The Company's share of this
fine was less than $100,000. On September 24, 1998, NU, the Connecticut
Department of Environmental Protection and the Connecticut Attorney General
reached a stipulated agreement for alleged wastewater discharge violations at
the Millstone units. As part of the agreement, NU will pay a civil penalty of
$700,000, and an additional $500,000 to fund three environmental projects. The
Company's share of this fine will be immaterial.
<PAGE>
EXHIBIT D-1 Page 6 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note B - Nuclear Units - continued
- ----------------------
In August 1997, the Company sued NU in Massachusetts Superior Court
for damages resulting from the tortious conduct of NU that caused the shutdown
of Millstone 3. The Company's damages include the costs of replacement power
during the outage and costs necessary to return Millstone 3 to safe operation.
The Company also seeks punitive damages. The Company also sent a demand for
arbitration to Connecticut Light & Power Company (CL&P) and Western
Massachusetts Electric Company (WMEC), both subsidiaries of NU, seeking damages
resulting from their breach of obligations under an agreement with the Company
and others regarding the operation and ownership of Millstone 3. The arbitration
is scheduled for October 1999. NU moved to dismiss the Company's suit, or, in
the alternative, stay the suit pending arbitration of the Company's claims
against CL&P and WMEC. NU also moved to consolidate the Company's suit with
suits filed by other joint owners in Massachusetts Superior Court. On July 3,
1998, the court denied NU's motion to dismiss and its motion to stay pending
arbitration. On July 21, 1998, the Company amended its complaint by, among other
things, adding NU's Trustees as defendants. The Worcester Superior Court granted
the Company's motion for a trial in June 1999, subject to revision if the cases
are consolidated. No ruling has been made on NU's motion to consolidate.
Nuclear Decommissioning
In New Hampshire, legislation was recently enacted which makes owners
of Seabrook 1, of which the Company owns a 10 percent interest, proportional
guarantors for decommissioning costs in the event that an owner without a
franchise service territory fails to fund its share of decommissioning costs.
Currently, a single owner of an approximate 12 percent share of Seabrook 1 has
no franchise service territory. For more information on nuclear decommissioning,
refer to the Company's Annual Report on Form 10-K for 1997.
The New Hampshire Nuclear Decommissioning Finance Committee is
reviewing Seabrook Station's decommissioning estimate and associated annual
funding levels. Among the items being considered is the imposition of joint and
several liability among the Seabrook joint owners for decommissioning funding.
The Company cannot predict what additional liability, if any, may be imposed on
it.
<PAGE>
EXHIBIT D-1 Page 7 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note B - Nuclear Units - continued
- ----------------------
The Nuclear Waste Policy Act of 1982 establishes that the federal
government (through the Department of Energy (DOE)) is responsible for the
disposal of spent nuclear fuel. The federal government requires the Company to
pay a fee based on its share of the net generation from the Millstone 3 and
Seabrook 1 nuclear units. Through February 1998, the company recovered this fee
through its fuel clause. Subsequently, most of these costs are recovered through
the Company's restructuring settlement in lieu of the fuel clause. Similar costs
are incurred by the Vermont Yankee nuclear generating unit. These costs are
billed to the Company and also recovered from customers through the same
mechanism. In November 1997, ruling on a lawsuit brought against the DOE by
numerous utilities and state regulatory commissions, the Court of Appeals for
the District of Columbia (the Appeals Court) held that the DOE was obligated to
begin disposing of utilities' spent nuclear fuel by January 31, 1998. The DOE
failed to meet this deadline, and is not scheduled to have a temporary or
permanent repository for spent nuclear fuel for several years. In February 1998,
Maine Yankee petitioned the Appeals Court to compel the DOE to remove Maine
Yankee's spent fuel from the site. In May 1998, the Appeals Court rejected the
petitions of Maine Yankee and the other utilities and state regulatory
commissions stating that the issue of damages was a contractual matter. The
operators of the units in which the Company has an obligation, including Maine
Yankee, Connecticut Yankee, and Yankee Atomic, continue to pursue damage claims
against the DOE in the Federal Court of Claims (Claims Court). On October 30,
1998, the Claims Court ruled that the DOE violated a commitment to remove spent
fuel from Yankee Atomic. The Claims Court issued similar rulings in November
1998 related to cases brought by Connecticut Yankee and Maine Yankee. Further
proceedings will be scheduled by the Claims Court to decide the amount of
damages.
<PAGE>
EXHIBIT D-1 Page 8 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note C - Town of Norwood
- ------------------------
On September 29, 1998, the United States District Court for the
District Massachusetts dismissed the lawsuit filed by the Town of Norwood,
Massachusetts against NEES and the Company in April 1997. The company had been a
wholesale power supplier for Norwood pursuant to rates approved by the FERC. In
the lawsuit, Norwood had alleged that the Company's divestiture of its power
generating assets would violate the terms of a 1983 power contract. Norwood also
alleged that the divestiture and recovery of stranded investment costs
contravened federal antitrust laws. The District Court judge granted NEES' and
the Company's motion for dismissal on the grounds that the contract did not
require the Company to retain its generating units, that the FERC-approved filed
rates govern these matters and that Norwood had adequate opportunity at the FERC
to litigate these matters. Norwood has filed a motion to alter or amend the
order of dismissal.
In March 1998, Norwood gave notice of its intent to terminate its
contract with the Company, without accepting responsibility for its share of the
Company's stranded costs, and began taking power from another supplier
commencing in April 1998. In May 1998, the FERC ruled that the Company could
assess a contract termination charge to any of the Company's unaffiliated
customers that choose to terminate their wholesale power contracts early.
Norwood claimed that the contract termination charge approved by the FERC did
not apply to Norwood; however, in denying Norwood's motion for rehearing, the
FERC ruled that the charge did apply to Norwood. On October 2, 1998, Norwood
appealed this decision to the First Circuit Court of Appeals (First Circuit).
The Company's billings to Norwood for this charge through September 1998 have
been approximately $4 million. Norwood has not paid any of these billings. The
Company intends to pursue collection action to recover these amounts.
Norwood appealed the FERC's orders approving the divestiture and the
Massachusetts and Rhode Island industry restructuring settlement agreements
(including modification of the Company's contracts with Massachusetts Electric
and Narragansett Electric) to the First Circuit on July 31, 1998 and August 7,
1998, respectively. The FERC had found that the challenged orders do not apply
to Norwood.
<PAGE>
EXHIBIT D-1 Page 9 of 9
NEW ENGLAND POWER COMPANY
Statement of all Known Contingent Liabilities
Note C - Town of Norwood - continued
- ------------------------
On October 20, 1998, the First Circuit consolidated all three of
Norwood's appeals from the FERC's orders. These consolidated appeals will likely
be consolidated with two other appeals that were filed on August 6, 1998 with
the Second Circuit Court of Appeals and transferred to the First Circuit on
October 13, 1998. Both appeals, filed by the Northeast Center for Social Issue
Studies, challenge the FERC's approval of the Company's sale of its
hydroelectric facilities.
Note D - Hydro-Quebec Arbitration
- ---------------------------------
In 1996, various New England utilities which are members of the New
England Power Pool, including the Company, submitted a dispute to arbitration
regarding their Firm Energy Purchased Power Contract with Hydro-Quebec. In June
1997, Hydro-Quebec presented a damage claim of approximately $37 million for
past damages, of which the Company's share would have been approximately $6
million to $9 million. The claims involved a dispute over the components of a
pricing formula and additional costs under the contract. With respect to ongoing
claims, the Company paid Hydro-Quebec the higher amount (additional costs of
approximately $3 million per year) from July 1996 until September 1, 1998 under
protest and subject to refund. The contract was transferred to USGen on
September 1, 1998 in conjunction with the sale of the nonnuclear generating
business. In October 1997, an arbitrator ruled in favor of the New England
utilities in all respects. Hydro-Quebec has not yet refunded any monies and has
appealed the decision. In June 1998, the United States District Court (District
Court) issued an order affirming the 1997 arbitration decision in favor of the
Company and the other utilities. Hydro-Quebec is appealing this order to the
Court of Appeals for the First Circuit.
On July 31, 1998, in a separate proceeding, an arbitrator denied the
request of the Company and other utilities that they be allowed to withhold
payment of disputed amounts from Hydro-Quebec during the pendency of
Hydro-Quebec's appeal. The Company and the other utilities have filed a petition
with the District Court to vacate this decision, and Hydro-Quebec has petitioned
the District Court to confirm it.
<PAGE>
EXHIBIT D-2 Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note A - Hazardous Waste
- ------------------------
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict, joint
and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances. A number of states, including
Massachusetts, have enacted similar laws.
The electric utility industry typically utilizes and/or generates in
its operations a range of potentially hazardous products and by-products.
Massachusetts Electric Company (the Company) currently has in place an internal
environmental audit program and an external waste disposal vendor audit and
qualification program intended to enhance compliance with existing federal,
state, and local requirements regarding the handling of potentially hazardous
products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the United States Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for 16 sites at which hazardous waste is
alleged to have been disposed. Private parties have also contacted or initiated
legal proceedings against the Company regarding hazardous waste cleanup. The
most prevalent types of hazardous waste sites with which the Company has been
associated are manufactured gas locations. (Until the early 1970's, New England
Electrical System (NEES) was a combined electric and holding company system.)
The Company is aware of approximately 35 such manufactured gas locations in
Massachusetts. The Company has been identified as a PRP at eight of these
manufactured gas locations, which are included in the 16 PRP sites discussed
above. The Company is engaged in various phases of investigation and remediation
work at 17 of the manufactured gas locations. The Company is currently aware of
other possible locations. The Company is currently aware of other possible
hazardous waste sites, and may in the future become aware of additional sites,
that it may be held responsible for remediating.
In 1993, the Massachusetts Department of Public Utilities approved a
settlement agreement regarding the rate recovery of remediation costs of former
manufactured gas sites and certain other hazardous waste sites located in
Massachusetts. Under that agreement, qualified remedial costs related to these
sites are paid out of a special fund established on the Company's books. The
Company made an initial $30 million contribution to the fund. Rate-recoverable
contributions of $3 million, adjusted since 1993 for inflation, are added
annually to the fund along with interest and any recoveries from insurance
carriers and other third parties. At September 30, 1998, the fund had a balance
of $46 million.
<PAGE>
EXHIBIT D-2 Page 2 of 2
MASSACHUSETTS ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note A - Hazardous Waste - continued
- ------------------------
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant uncertainties
as to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by the Company. The
NEES companies have recovered amounts from certain insurers and other third
parties, and, where appropriate, the Company intends to seek recovery from other
insurers and from other PRPs, but it is uncertain whether, and to what extent,
such efforts will be successful. At September 30, 1998, the Company had total
reserves for environmental response costs of $47 million. This represents an
increase from the $35 million balance at the end of 1997. Since all of the sites
for which increased reserves were recognized are covered by rate agreements,
this increase in the reserves did not have an adverse effect on net income. The
Company believes that hazardous waste liabilities for all sites of which it is
aware, and which are not covered by a rate agreement, are not material to its
financial position.
<PAGE>
EXHIBIT D-3 Page 1 of 1
THE NARRAGANSETT ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note A - Hazardous Waste
- ------------------------
The Federal Comprehensive Environmental Response, Compensation and
Liability Act, more commonly known as the "Superfund" law, imposes strict, joint
and several liability, regardless of fault, for remediation of property
contaminated with hazardous substances.
The electric utility industry typically utilizes and/or generates in
its operations a range of potentially hazardous products and by-products. The
Narragansett Electric Company (the Company) currently has in place an internal
environmental audit program and an external waste disposal vendor audit and
qualification program intended to enhance compliance with existing federal,
state, and local requirements regarding the handling of potentially hazardous
products and by-products.
The Company has been named as a potentially responsible party (PRP) by
either the United States Environmental Protection Agency or the Massachusetts
Department of Environmental Protection for three sites (two of which are located
in Massachusetts) at which hazardous waste is alleged to have been disposed. The
Company is currently aware of other possible hazardous waste sites, and may in
the future become aware of additional sites, that it may be held responsible for
remediating.
Gas was manufactured from coal in Rhode Island in the past. The
Company is aware of five sites on which gas was manufactured or manufactured gas
was stored that were owned either by the Company or by its predecessor
companies. It is not known to what extent the Company would be held liable for
hazardous wastes, if any, left at these manufactured gas locations.
Predicting the potential costs to investigate and remediate hazardous
waste sites continues to be difficult. There are also significant uncertainties
as to the portion, if any, of the investigation and remediation costs of any
particular hazardous waste site that may ultimately be borne by the Company. A
preliminary review by a consultant hired by the New England Electric System
(NEES) companies of the potential cost of investigating and, if necessary,
remediating Rhode Island manufactured gas sites resulted in costs per site
ranging from less than $1 million to $11 million. An informal survey of other
utilities conducted on behalf of NEES and its subsidiaries indicated costs in a
similar range. The NEES companies have recovered amounts from certain insurers
and other third parties, and, where appropriate, the Company intends to seek
recovery from other insurers and from other PRPs, but it is uncertain whether,
and to what extent, such efforts will be successful. The Company believes that
hazardous waste liabilities for all sites of which it is aware are not material
to its financial position.
<PAGE>
EXHIBIT D-4
NEW ENGLAND ELECTRIC TRANSMISSION CORPORATION
No known contingent liabilities
<PAGE>
EXHIBIT D-5
NEW ENGLAND HYDRO TRANSMISSION CORPORATION
No known contingent liabilities
<PAGE>
EXHIBIT D-6
NEW ENGLAND HYDRO-TRANSMISSION ELECTRIC COMPANY, INC.
No known contingent liabilities
<PAGE>
EXHIBIT D-7 Page 1 of 5
MONTAUP ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note A - Nuclear Fuel Disposal and Nuclear Decommissioning Costs
- ----------------------------------------------------------------
The owners (or lead participants) of the nuclear units in which
Montaup has an interest have made, or expect to make, various arrangements for
the acquisition of uranium concentrate, the conversion, enrichment, fabrication
and utilization of nuclear fuel and the disposition of that fuel after use. The
owners (or lead participants) of United States nuclear units have entered into
contracts with the Department of Energy (DOE) for disposal of spent nuclear fuel
in accordance with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA
requires (subject to various contingencies) that the federal government design,
license, construct and operate a permanent repository for high level radioactive
wastes and spent nuclear fuel and establish a prescribed fee for the disposal of
such wastes and nuclear fuel. The NWPA specifies that the DOE provide for the
disposal of such waste and spent nuclear fuel starting in 1998. Objections on
environmental and other grounds have been asserted against proposals for storage
as well as disposal of spent nuclear fuel. The DOE now estimates that a
permanent disposal site for spent fuel will not be ready to accept fuel for
storage or disposal until as late as the year 2010. In early 1998, a number of
utilities filed suit in federal appeals court seeking, among other things, an
order requiring the DOE to immediately establish a program for the disposal of
spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9%
interest in Seabrook I. Northeast Utilities, the operator of the units,
indicates that Millstone 3 has sufficient on-site storage facilities which, with
rack additions, can accommodate its spent fuel for the projected life of the
unit. At the Seabrook Project, there is on-site storage capacity which, with
rack additions, will be sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power plants
in which Montaup has an interest. These assessments are calculated based on the
utilities' prior use of the government facilities and have been levied by the
DOE, starting in September 1993, and will continue over 15 years. This cost is
passed on to the joint owners or power buyers as an additional fuel charge on a
monthly basis and is currently being recovered by Montaup through rates.
<PAGE>
EXHIBIT D-7 Page 2 of 5
MONTAUP ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note A - Nuclear Fuel Disposal and Nuclear
- ------------------------------------------
Decommissioning Costs - continued
---------------------
Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear
generating facility which is in the process of decommissioning. Montaup's share
of the total estimated costs for the permanent shutdown, decommissioning and
recovery of the investment in Connecticut Yankee is approximately $23.8 million.
On August 31, 1998, a FERC law judge rejected Connecticut Yankee's filed plan to
decommission the plant. The judge claimed that estimates of clean-up costs were
flawed and certain restoration costs were not supported. The judge also said
Connecticut Yankee could not pass on spent fuel storage costs to rate-payers.
The judge recommended that Connecticut Yankee withdraw its decommissioning plan
and submit a new plan which addresses the issues cited by him. FERC will review
the judge's recommendation and issue a decision on this case in the coming
months. If FERC concurs with the judge's recommendation, this may result in a
write down of certain of Connecticut Yankee plant investments.
In August 1997, as a result of an economic evaluation, the Maine
Yankee Board of Directors voted to permanently close that nuclear plant. Montaup
has a 4.0% equity ownership in Maine Yankee. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning and recovery of the
remaining investment in Maine Yankee is approximately $31.0 million. In January
1998, FERC accepted Maine Yankee's rate filing, subject to refund, for the
recovery of its costs during the decommissioning period.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone 3 is $22.4 million in
1998 dollars, and Seabrook I is $14.4 million in 1998 dollars. These figures are
based on studies performed for the lead owner of the units. Montaup also pays
into decommissioning reserves pursuant to contractual arrangements with other
nuclear generating facilities in which it has an equity ownership interest or
life of the unit entitlement. Such expenses are currently recoverable through
rates.
<PAGE>
EXHIBIT D-7 Page 3 of 5
MONTAUP ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note B - Environmental Matters
- ------------------------------
There is an extensive body of federal and state statutes governing
environmental matters, which permit, among other things, federal and state
authorities to initiate legal action providing for liability, compensation,
cleanup, and emergency response to the release or threatened release of
hazardous substances into the environment and for the cleanup of inactive
hazardous waste disposal sites which constitute substantial hazards. Because of
the nature of Montaup's business, various by-products and substances are
produced or handled which are classified as hazardous under the rules and
regulations promulgated by the United States Environmental Protection Agency
(EPA) as well as state and local authorities. The Company generally provides for
the disposal of such substances through licensed contractors, but these
statutory provisions generally impose potential joint and several responsibility
on the generators of the wastes for cleanup costs. In the past, Montaup had been
notified with respect to a number of sites where they were allegedly responsible
for such costs, including sites where they allegedly had joint and several
liability with other responsible parties. Montaup is currently not involved in
any environmental site investigation.
It is the policy of Montaup to notify liability insurers and to
initiate claims. The Company is unable to predict whether liability, if any,
will be assumed by, or can be enforced against, the insurance carriers in these
matters. The costs incurred in connection with these sites have been financed
primarily with internally generated cash.
The Clean Air Act Amendments created new regulatory programs and
generally updated and strengthened air pollution control laws. These amendments
expanded the regulatory role of the EPA regarding emissions from electric
generating facilities and a host of other sources. Montaup generating facilities
were first affected in 1995, when EPA regulations took effect for facilities
owned by Montaup. Montaup's coal-fired Somerset Unit No. 6 is utilizing lower
sulfur content coal to meet the 1995 air standards. Eastern Edison does not
anticipate the impact from the Amendments to be material to its financial
position.
<PAGE>
EXHIBIT D-7 Page 4 of 5
MONTAUP ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note B - Environmental Matters - continued
- ------------------------------
In July, the EPA issued a new and more stringent rule covering ozone
particulate matter which is to be followed by promulgation of more stringent
ozone and particulate matter standards. The effect that such standards will have
on the EUA System cannot be determined by management at this time.
Montaup and the Massachusetts Attorney General and Division of Energy
Resources entered into a settlement regarding electric utility industry
restructuring in Massachusetts. The settlement includes a plan for emissions
reductions related to Montaup's Somerset Station Units 5 and 6, and to Montaup's
50% ownership share of Canal Electric's Unit 2. The basis for sulfur dioxide
(SO2) and nitrogen oxide (NOx) emission reductions in the proposed settlement is
an allowance cap calculation. Montaup may meet its allowance caps by any
combination of control technologies, fuel switching, operational changes, and/or
the use of purchased or surplus allowances. The proposed settlement was approved
by FERC on December 19, 1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight Northeast states including
Massachusetts and Rhode Island issued recommendations for NOx controls for
existing utility boilers required to meet the ozone non-attainment requirements
of the Clean Air Act. The NESCAUM recommendations are more restrictive than the
Clean Air Act requirements. The Massachusetts Department of Environmental
Management has amended its regulations to require that Reasonably Available
Control Technology (RACT) be implemented at all stationary sources potentially
emitting 50 tons or more per year of NOx. Similar regulations have been issued
in Rhode Island. Montaup has initiated compliance, through, among other things,
selective, noncatalytic reduction processes.
A number of scientific studies in the past several years have examined
the possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. Some states have enacted regulations to limit the strength of
magnetic fields at the edge of transmission line rights-of-way. Rhode Island has
enacted a statute which authorizes and directs the Energy Facility Siting Board
to establish rules and regulations governing construction of high voltage
transmission lines of 69kv or more. Management cannot predict the ultimate
outcome of the EMF issue.
<PAGE>
EXHIBIT D-7 Page 5 of 5
MONTAUP ELECTRIC COMPANY
Statement of all Known Contingent Liabilities
Note C - Other
- --------------
Since early 1997, fourteen plaintiffs brought suit against numerous
defendants, including EUA, for injuries and illness all allegedly caused by
exposure to asbestos over approximately a thirty-year period, at premises,
including some owned by EUA companies. The total damages claimed in all of these
complaints was $34 million in compensatory and punitive damages, plus exemplary
damages and interest and costs. Each names between fifteen and twenty-eight
defendants, including EUA. These complaints have been referred to the applicable
insurance companies. Counsel has been retained by the insurers and is actively
defending all cases. Four cases have been dismissed as against EUA companies.
EUA cannot predict the ultimate outcome of this matter at this time.
<PAGE>
EXHIBIT D-8 Page 1 of 4
BLACKSTONE VALLEY ELECTRIC
Statement of all Known Contingent Liabilities
Note A - Environmental Matters
- -------------------------------
The Comprehensive Environmental Response, Compensation Liability Act
of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986,
and certain similar state statutes authorize various governmental authorities to
seek court orders compelling responsible parties to take cleanup action at
disposal sites which have been determined by such governmental authorities to
present an imminent and substantial danger to the public and to the environment
because of an actual or threatened release of hazardous substances. Because of
the nature of Blackstone's business, various by-products and substances are
produced or handled which are classified as hazardous under the rules and
regulations promulgated by the EPA as well as state and local authorities.
Blackstone generally provides for the disposal of such substances through
licensed contractors, but these statutory provisions generally impose potential
joint and several responsibility on the generators of the wastes for cleanup
costs. Blackstone has been notified with respect to a number of sites where they
may be responsible for such costs, including sites where they may have joint and
several liability with other responsible parties. It is the policy of Blackstone
to notify liability insurers and to initiate claims. However, it is not possible
at this time to predict whether liability, if any, will be assumed by, or can be
enforced against, the insurance carriers in these matters.
On December 13, 1994, the United States District Court for the
District of Massachusetts (District Court) issued a judgment against Blackstone,
finding Blackstone liable to the Commonwealth of Massachusetts (commonwealth)
for the full amount of response costs incurred by the Commonwealth in the
cleanup of a by-product of manufactured gas at a site at Mendon Road in
Attleboro, Massachusetts. The judgment also found Blackstone liable for interest
and litigation expenses calculated to the date of judgment. The total liability
is approximately $5.9 million, including approximately $3.6 million in interest
which has accumulated since 1985. Due to the uncertainty of the ultimate outcome
of this proceeding and anticipated recoverability, Blackstone recorded the $5.9
million District Court judgment as a deferred debit. This amount is included
with Other Assets on the Balance Sheet at December 31, 1997 and 1996.
<PAGE>
EXHIBIT D-8 Page 2 of 4
BLACKSTONE VALLEY ELECTRIC
Statement of all Known Contingent Liabilities
Note A - Environmental Matters - continued
- ------------------------------
On January 20, 1995, Blackstone entered into an escrow agreement with
the Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent
who transferred the funds into an interest bearing money market account. The
distribution of the proceeds of the escrow account will be determined upon the
final resolution of the judgment. No additional interest expense will accrue on
the judgment amount.
Blackstone filed a Notice of Appeal of the District Court's judgment
and filed its brief with the United States Court of Appeals for the First
Circuit (Circuit Court) on February 24, 1995. On October 6, 1995, the Circuit
Court vacated the District Court's $5.9 million judgement to refer the matter to
the EPA to determine whether the chemical substance ferric ferrocyanide (FFC)
contained within the by-product is a hazardous substance.
Given the present posture of the case, Blackstone may not be liable to
reimburse the Commonwealth for the Mendon Road cleanup costs if the EPA
determines that FFC is not a hazardous substance. On January 9, 1997, Blackstone
met with representatives of EPA and the Commonwealth to discuss the procedure
EPA would follow in resolving the FFC issue. In January 1997, Blackstone
submitted written comments which were followed by the Commonwealth's written
reply in March 1997. Both parties submitted additional memoranda to EPA during
remainder of the year. The EPA will now determine whether FFC is a hazardous
substance. Further court proceedings are likely.
On January 28, 1994, Blackstone filed a complaint in the Massachusetts
District court, seeking, among other relief, contribution and reimbursement from
Stone & Webster Inc., of New York City and several of its affiliated companies
(Stone & Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley)
for any damages incurred by Blackstone regarding the Mendon Road site. On
November 7, 1994, the Court denied motions to dismiss the complaint filed by
Stone & Webster and Valley. This proceeding was stayed in December 1995 pending
final EPA determination as to whether FFC is a hazardous substance.
<PAGE>
EXHIBIT D-8 Page 3 of 4
BLACKSTONE VALLEY ELECTRIC
Statement of all Known Contingent Liabilities
Note A - Environmental Matters - continued
- ------------------------------
In addition, Blackstone has notified certain liability insurers and
has filed claims with respect to the Mendon Road site, as well as other sites.
Blackstone reached settlement with one carrier for reimbursement of legal costs
related to the Mendon Road case. In January 1996, Blackstone received the
proceeds of the settlement.
As of December 31, 1998, Blackstone had incurred costs of
approximately $6.7 million (excluding the $5.9 million Mendon Road judgment) in
connection with the investigation and cleanup of these sites. These amounts have
been financed primarily by internally generated cash. Blackstone is currently
amortizing all of its incurred costs over a five-year period consistent with
prior regulatory recovery periods and is recovering certain of those costs in
rates. The Company estimates that additional costs of up to approximately $1.8
million (excluding the $5.9 million Mendon Road judgment) may be incurred at
these sites through 1999 by it and the other responsible parties. Estimated
amounts after 1999 are not now determinable since site studies, which are the
basis of these estimates, have not been completed.
As a result of the recoverability of cleanup costs in rates and the
uncertainly regarding both its estimated liability, as well as potential
contributions from insurance carriers and other responsible parties, Blackstone
does not believe that the ultimate impact of the environmental costs will be
material to its financial position and thus, no loss provision is required at
this time.
A number of scientific studies in the past several years have examined
the possibility of health effects from electric and magnetic fields (EMF) that
are found wherever there is electricity. While some of the studies have
indicated some association between exposure to EMF and health effects, many
others have indicated no direct association.
Some states have enacted regulations to limit the strength of EMF at
the edge of transmission line rights-of-way. The Rhode Island legislature has
enacted a statute which authorizes and directs the Rhode Island Energy Facility
Siting Board to establish rules and regulations governing construction of high
voltage transmission lines of 69 kv or more. In addition, an energy facility
siting application, in Rhode Island must include, when applicable, any current
independent, scientific research pertaining to EMF exposure for review by the
Board. Management cannot predict the impact, if any, that legislation or other
developments concerning EMF may have on Blackstone.
<PAGE>
EXHIBIT D-8 Page 4 of 4
BLACKSTONE VALLEY ELECTRIC
Statement of all Known Contingent Liabilities
Note B- Other
- -------------
Since early 1997, thirteen plaintiffs brought suit against numerous
defendants, including EUA, for injuries and illness allegedly caused by exposure
to asbestos over approximately a thirty-year period, at premises, including some
owned by EUA companies. The total damages claimed in all of these complaints was
$34 million in compensatory and punitive damages, plus exemplary damages and
interest and costs. Each complaint names between fifteen and twenty-eight
defendants, including EUA. These complaints have been referred to the applicable
insurance companies. Counsel has been retained by the insurers and is actively
defending all cases. Four cases have been dismissed as against EUA companies,
with prejudice. EUA cannot predict the ultimate outcome of this matter at this
time.
<PAGE>
EXHIBIT D-9 Page 1 of 5
EASTERN EDISON COMPANY
Statement of all Known Contingent Liabilities
Note A - Nuclear Fuel Disposal and Nuclear Decommissioning Costs
- ----------------------------------------------------------------
The owners (or lead participants) of the nuclear units in which
Montaup has an interest have made, or expect to make, various arrangements for
the acquisition of uranium concentrate, the conversion, enrichment, fabrication
and utilization of nuclear fuel and the disposition of that fuel after use. The
owners (or lead participants) of United States nuclear units have entered into
contracts with the Department of Energy (DOE) for disposal of spent nuclear fuel
in accordance with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA
requires (subject to various contingencies) that the federal government design,
license, construct and operate a permanent repository for high level radioactive
wastes and spent nuclear fuel and establish a prescribed fee for the disposal of
such wastes and nuclear fuel. The NWPA specifies that the DOE provide for the
disposal of such waste and spent nuclear fuel starting in 1998. Objections on
environmental and other grounds have been asserted against proposals for storage
as well as disposal of spent nuclear fuel. The DOE now estimates that a
permanent disposal site for spent fuel will not be ready to accept fuel for
storage or disposal until as late as the year 2010. In early 1998, a number of
utilities filed suit in federal appeals court seeking, among other things, an
order requiring the DOE to immediately establish a program for the disposal of
spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9%
interest in Seabrook I. Northeast Utilities, the operator of the units,
indicates that Millstone 3 has sufficient on-site storage facilities which, with
rack additions, can accommodate its spent fuel for the projected life of the
unit. At the Seabrook Project, there is on-site storage capacity which, with
rack additions, will be sufficient to at least the year 2011.
The Energy Policy Act of 1992 requires that a fund be created for the
decommissioning and decontamination of the DOE uranium enrichment facilities.
The fund will be financed in part by special assessments on nuclear power plants
in which Montaup has an interest. These assessments are calculated based on the
utilities' prior use of the government facilities and have been levied by the
DOE, starting in September 1993, and will continue over 15 years. This cost is
passed on to the joint owners or power buyers as an additional fuel charge on a
monthly basis and is currently being recovered by Montaup through rates.
<PAGE>
EXHIBIT D-9 Page 2 of 5
EASTERN EDISON COMPANY
Statement of all Known Contingent Liabilities
Note A - Nuclear Fuel Disposal and Nuclear
- ------------------------------------------
Decommissioning Costs - continued
---------------------
Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear
generating facility which is in the process of decommissioning. Montaup's share
of the total estimated costs for the permanent shutdown, decommissioning and
recovery of the investment in Connecticut Yankee is approximately $23.8 million.
On August 31, 1998, a FERC law judge rejected Connecticut Yankee's filed plan to
decommission the plant. The judge claimed that estimates of clean-up costs were
flawed and certain restoration costs were not supported. The judge also said
Connecticut Yankee could not pass on spent fuel storage costs to rate-payers.
The judge recommended that Connecticut Yankee withdraw its decommissioning plan
and submit a new plan which addresses the issues cited by him. FERC will review
the judge's recommendation and issue a decision on this case in the coming
months. If FERC concurs with the judge's recommendation, this may result in a
write down of certain of Connecticut Yankee plant investments.
In August 1997, as a result of an economic evaluation, the Maine
Yankee Board of Directors voted to permanently close that nuclear plant. Montaup
has a 4.0% equity ownership in Maine Yankee. Montaup's share of the total
estimated costs for the permanent shutdown, decommissioning and recovery of the
remaining investment in Maine Yankee is approximately $31.0 million. In January
1998, FERC accepted Maine Yankee's rate filing, subject to refund, for the
recovery of its costs during the decommissioning period.
Also, Montaup is recovering through rates its share of estimated
decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the
current estimate of total costs to decommission Millstone 3 is $22.4 million in
1998 dollars, and Seabrook I is $14.4 million in 1998 dollars. These figures are
based on studies performed for the lead owner of the units. Montaup also pays
into decommissioning reserves pursuant to contractual arrangements with other
nuclear generating facilities in which it has an equity ownership interest or
life of the unit entitlement. Such expenses are currently recoverable through
rates.
<PAGE>
EXHIBIT D-9 Page 3 of 5
EASTERN EDISON COMPANY
Statement of all Known Contingent Liabilities
Note B - Environmental Matters
- ------------------------------
There is an extensive body of federal and state statutes governing
environmental matters, which permit, among other things, federal and state
authorities to initiate legal action providing for liability, compensation,
cleanup, and emergency response to the release or threatened release of
hazardous substances into the environment and for the cleanup of inactive
hazardous waste disposal sites which constitute substantial hazards. Because of
the nature of the Eastern Edison business, various by-products and substances
are produced or handled which are classified as hazardous under the rules and
regulations promulgated by the United States Environmental protection Agency
(EPA) as well as state and local authorities. The Company generally provides for
the disposal of such substances through licensed contractors, but these
statutory provisions generally impose potential joint and several responsibility
on the generators of the wastes for cleanup costs. In the past, Eastern Edison
and Montaup had been notified with respect to a number of sites where they were
allegedly responsible for such costs, including sites where they allegedly had
joint and several liability with other responsible parties.
It is the policy of Eastern Edison and Montaup to notify liability
insurers and to initiate claims. Eastern Edison is currently not involved in any
environmental site investigation. It is the policy of Eastern Edison to notify
liability insurers and to initiate claims. The Company is unable to predict
whether liability, if any, will be assumed by, or can be enforced against, the
insurance carriers in these matters. The costs incurred in connection with these
sites have been financed primarily with internally generated cash.
The Clean Air Act Amendments created new regulatory programs and
generally updated and strengthened air pollution control laws. These amendments
expanded the regulatory role of the EPA regarding emissions from electric
generating facilities and a host of other sources. Montaup generating facilities
were first affected in 1995, when EPA regulations took effect for facilities
owned by Montaup. Montaup's coal-fired Somerset Unit No. 6 is utilizing lower
sulfur content coal to meet the 1995 air standards. Eastern Edison does not
anticipate the impact from the Amendments to be material to its financial
position.
In July, the EPA issued a new and more stringent rule covering ozone
particulate matter which is to be followed by promulgation of more stringent
ozone and particulate matter standards. The effect that such standards will have
on the EUA System cannot be determined by management at this time.
<PAGE>
EXHIBIT D-9 Page 4 of 5
EASTERN EDISON COMPANY
Statement of all Known Contingent Liabilities
Note B - Environmental Matters - continued
- ------------------------------
Eastern Edison, Montaup, the Massachusetts Attorney General and
Division of Energy Resources entered into a settlement regarding electric
utility industry restructuring in Massachusetts. The settlement includes a plan
for emissions reductions related to Montaup's Somerset Station Units 5 and 6,
and to Montaup's 50% ownership share of Canal Electric's Unit 2. The basis for
sulfur dioxide (SO2) and nitrogen oxide (NOx) emission reductions in the
proposed settlement is an allowance cap calculation. Montaup may meet its
allowance caps by any combination of control technologies, fuel switching,
operational changes, and/or the use of purchased or surplus allowances. The
proposed settlement was approved by FERC on December 19, 1997.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight Northeast states including
Massachusetts and Rhode Island issued recommendations for NOx controls for
existing utility boilers required to meet the ozone non-attainment requirements
of the Clean Air Act. The NESCAUM recommendations are more restrictive than the
Clean Air Act requirements. The Massachusetts Department of Environmental
Management has amended its regulations to require that Reasonably Available
Control Technology (RACT) be implemented at all stationary sources potentially
emitting 50 tons or more per year of NOx. Similar regulations have been issued
in Rhode Island. Montaup has initiated compliance, through, among other things,
selective, noncatalytic reduction processes.
A number of scientific studies in the past several years have examined
the possibility of health effects from EMF that are found wherever there is
electricity. While some of the studies have indicated some association between
exposure to EMF and health effects, many others have indicated no direct
association. Some states have enacted regulations to limit the strength of
magnetic fields at the edge of transmission line rights-of-way. Rhode Island has
enacted a statute which authorizes and directs the Energy Facility Siting Board
to establish rules and regulations governing construction of high voltage
transmission lines of 69kv or more. Management cannot predict the ultimate
outcome of the EMF issue.
<PAGE>
EXHIBIT D-9 Page 5 of 5
EASTERN EDISON COMPANY
Statement of all Known Contingent Liabilities
Since early 1997, fourteen plaintiffs brought suit against numerous
defendants, including EUA, for injuries and illness all allegedly caused by
exposure to asbestos over approximately a thirty-year period, at premises,
including some owned by EUA companies. The total damages claimed in all of these
complaints was $34 million in compensatory and punitive damages, plus exemplary
damages and interest and costs. Each names between fifteen and twenty-eight
defendants, including EUA. These complaints have been referred to the applicable
insurance companies. Counsel has been retained by the insurers and is actively
defending all cases. Four cases have been dismissed as against EUA companies.
EUA cannot predict the ultimate outcome of this matter at this time.
A pending class action, filed on March 2, 1998, in the Massachusetts
Supreme Judicial Court naming all eight Massachusetts electric distribution
companies, including Eastern Edison, and certain Massachusetts state agencies,
seeks to invalidate certain sections of the Electric Restructuring Act of 1997.
The Act directs electric distribution companies to fund energy efficient
activities to promote renewable energy projects, and impose a mandatory charge
on all electricity sold to customers to fund such activities and projects. In
addition to declaratory judgement, plaintiffs seek remittance of monies paid to
each distribution company by customers along with any interest earned. The
outcome of this class action is unknown at this time, however Eastern Edison is
vigorously defending the lawsuit.
<PAGE>
EXHIBIT D-10 Page 1 of 1
EASTERN EDISON COMPANY
Statement of all Known Contingent Liabilities
Note A - Environmental Matters
- ------------------------------
The Comprehensive Environmental Response, Compensation Liability Act
of 1980, as amended by the Superfund Amendments and Reauthorizaton Act of 1986,
and certain similar state statutes authorize various governmental authorities to
seek court orders compelling responsible parties to take cleanup action at
disposal sites which have been determined by such governmental authorities to
present an imminent and substantial danger to the public and to the environment
because of an actual or threatened release of hazardous substances. Because of
the nature of Newport's business, various by-products and substances are
produced or handled which are classified as hazardous under the rules and
regulations promulgated by the EPA as well as state and local authorities. The
Company is currently not involved in any environmental site investigations.
Newport generally provides for the disposal of such substances through licensed
contractors, but these statutory provisions generally impose potential joint and
several responsibility on the generators of the wastes for cleanup costs. It is
the policy of Newport to notify liability insurers and to initiate claims.
However, it is not possible at this time to predict whether liability, if any,
will be assumed by, or can be enforced against, the insurance carrier in this
matter.
The Clean Air Act Amendments created new regulatory programs and
generally updated and strengthened air pollution control laws. These amendments
expanded the regulatory role of the United States Environmental Protection
Agency (EPA) regarding emissions from electric generating facilities and a host
of other sources. The Company does not anticipate the impact from the Amendments
to be material to its financial position.
In April 1992, the Northeast States for Coordinated Air Use Management
(NESCAUM), an environmental advisory group for eight Northeast states including
Massachusetts and Rhode Island issued recommendations for nitrogen oxide (NOx)
controls for existing utility boilers required to meet the ozone non-attainment
requirements of the Clean Air Act. The NESCAUM recommendations are more
restrictive than the Clean Air Act requirements. The Massachusetts Department of
Environmental Management has amended its regulations to require that Reasonably
Available Control Technology (RACT) be implemented at all stationary sources
potentially emitting 50 tons or more per year of NOx. Rhode Island has issued
similar regulations also requiring that RACT be implemented at all stationary
sources potentially emitting 50 tons or more per year of NOx. The Company has
initiated compliance through, among other things, selective, reduction
processes. Effective October 1, 1999 Newport sold its own generation as part of
the utility restructuring laws. Newport still owns its share of the Wyman
generating station.
<PAGE>
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, et al.
AND MONTAUP ELECTRIC COMPANY, et al.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT E-1 New England Power Company
EXHIBIT E-2 Massachusetts Electric Company
EXHIBIT E-3 The Narragansett Electric Company
EXHIBIT E-4 New England Electric Transmission Corporation
EXHIBIT E-5 New England Hydro Transmission Corporation
EXHIBIT E-6 New England Hydro - Transmission Electric Company, Inc.
EXHIBIT E-7 Montaup Electric Company
EXHIBIT E-8 Blackstone Valley Electric Company
EXHIBIT E-9 Eastern Edison Company
EXHIBIT E-10 Newport Electric Corporation
Income Statement for the 12 Months Ending September 30, 1998
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. E-1
Page 1 of 2
Name of Respondent
New England Power Company
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
1 UTILITY OPERATING INCOME
<S> <C> <C> <C>
2 Operating Revenues (400) 1,481,067,948 1,481,067,948
3 Operating Expenses
4 Operation Expenses (401) 963,957,991 963,957,991
5 Maintenance Expenses (402) 75,560,088 75,560,088
6 Depreciation Expense (403) 78,245,773 78,245,773
7 Amort. & Depl. of Utility Plant (404-405) 3,000 3,000
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3) 33,786,395 33,786,395
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 61,346,769 61,346,769
14 Income Taxes - Federal (409.1) 243,772,477 243,772,477
15 - Other (409.1) 48,628,105 48,628,105
16 Provision for Deferred Income Taxes (410.1) 210,590,379 210,590,379
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 414,473,197 414,473,197
18 Investment Tax Credit Adj. - Net (411.4) (1,897,334) (1,897,334)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 1,299,520,446 1,299,520,446
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 181,547,502 181,547,502
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. E-1
Page 2 of 2
Name of Respondent
New England Power Company
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 181,547,502 181,547,502
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work
(416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1) 2,627,907 2,627,907
33 Nonoperating Rental Income (418) 524,820 524,820
34 Equity in Earnings of Subsidiary Companies (418.1) 5,466,612 5,466,612
35 Interest and Dividend Income (419) 3,547,764 3,547,764
36 Allowance for Other Funds Used During Construction (419.1) 113,773 113,773
37 Miscellaneous Nonoperating Income (421) 76,473 76,473
38 Gain on Disposition of Property (421.1) 483,765 483,765
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 7,585,300 7,585,300
40 Other Income Deductions
41 Loss on Disposition of Property (421.2) (7,007) (7,007)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 22,273,872 22,273,872
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 22,266,865 22,266,865
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2) 330,286 330,286
47 Income Taxes - Federal (409.2) (741,885) (741,885)
48 Income Taxes - Other (409.2) (12,200) (12,200)
49 Provision for Deferred Inc. Taxes (410.2) 381,700 381,700
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420) (21,422,661) (21,422,661)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (21,464,760) (21,464,760)
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 6,783,195 6,783,195
55 Interest Charges
56 Interest on Long-Term Debt (427) 34,408,021 34,408,021
57 Amort. of Debt Disc. and Expense (428) 862,427 862,427
58 Amortization of Loss on Reacquired Debt (428.1) 2,358,015 2,358,015
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430) 2,700,216 2,700,216
62 Other Interest Expense (431) 9,754,285 9,754,285
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 1,147,923 1,147,923
64 Net Interest Charges (Enter Total of lines 56 thru 63) 48,935,041 48,935,041
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 139,395,656 139,395,656
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 139,395,656 139,395,656
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. E-2
Page 1 of 2
Name of Respondent
Massachusetts Electric Company
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 1,583,046,649 1,583,046,649
3 Operating Expenses
4 Operation Expenses (401) 1,302,105,564 1,302,105,564
5 Maintenance Expenses (402) 37,630,776 37,630,776
6 Depreciation Expense (403) 58,845,497 58,845,497
7 Amort. & Depl. of Utility Plant (404-405)
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 36,990,471 36,990,471
14 Income Taxes - Federal (409.1) 26,868,282 26,868,282
15 - Other (409.1) 5,424,674 5,424,674
16 Provision for Deferred Income Taxes (410.1) 28,663,972 28,663,972
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 14,205,743 14,205,743
18 Investment Tax Credit Adj. - Net (411.4) (1,090,292) (1,090,292)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 1,481,233,201 1,481,233,201
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 101,813,448 101,813,448
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. E-2
Page 2 of 2
Name of Respondent
Massachusetts Electric Company
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 101,813,448 101,813,448
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1) 1,701,619 1,701,619
33 Nonoperating Rental Income (418) (12,241) (12,241)
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) 3,088,624 3,088,624
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 49,375 49,375
38 Gain on Disposition of Property (421.1) 227,271 227,271
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 1,651,410 1,651,410
40 Other Income Deductions
41 Loss on Disposition of Property (421.2) 625 625
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 4,859,474 4,859,474
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 4,860,099 4,860,099
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2) 280,079 280,079
47 Income Taxes - Federal (409.2) (734,407) (734,407)
48 Income Taxes - Other (409.2) (140,900) (140,900)
49 Provision for Deferred Inc. Taxes (410.2) 36,200 36,200
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (559,028) (559,028)
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) (2,649,661) (2,649,661)
55 Interest Charges
56 Interest on Long-Term Debt (427) 26,302,043 26,302,043
57 Amort. of Debt Disc. and Expense (428) 237,624 237,624
58 Amortization of Loss on Reacquired Debt (428.1) 510,833 510,833
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430) 462,294 462,294
62 Other Interest Expense (431) 5,169,282 5,169,282
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 590,154 590,154
64 Net Interest Charges (Enter Total of lines 56 thru 63) 32,091,922 32,091,922
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 67,071,865 67,071,865
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 67,071,865 67,071,865
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. E-3
Page 1 of 2
Name of Respondent
Narragansett Electric Company
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 492,755,355 492,755,355
3 Operating Expenses
4 Operation Expenses (401) 353,720,050 353,720,050
5 Maintenance Expenses (402) 12,030,441 12,030,441
6 Depreciation Expense (403) 23,048,075 23,048,075
7 Amort. & Depl. of Utility Plant (404-405)
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 40,685,062 40,685,062
14 Income Taxes - Federal (409.1) 14,754,386 14,754,386
15 - Other (409.1)
16 Provision for Deferred Income Taxes (410.1) 10,064,285 10,064,285
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 8,482,700 8,482,700
18 Investment Tax Credit Adj. - Net (411.4) (490,596) (490,596)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 445,329,003 445,329,003
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 47,426,352 47,426,352
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. E-3
Page 2 of 2
Name of Respondent
Narragansett Electric Company
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 47,426,352 47,426,352
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1) 826,705 826,705
33 Nonoperating Rental Income (418) 6,096 6,096
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) 834,809 834,809
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 1,760,164 1,760,164
38 Gain on Disposition of Property (421.1) 266,939 266,939
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 2,041,303 2,041,303
40 Other Income Deductions
41 Loss on Disposition of Property (421.2) 36,101 36,101
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 807,314 807,314
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 843,415 843,415
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2) 72,073 72,073
47 Income Taxes - Federal (409.2) (464,501) (464,501)
48 Income Taxes - Other (409.2)
49 Provision for Deferred Inc. Taxes (410.2) (26,053) (26,053)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (418,481) (418,481)
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 1,616,369 1,616,369
55 Interest Charges
56 Interest on Long-Term Debt (427) 14,323,257 14,323,257
57 Amort. of Debt Disc. and Expense (428) 140,171 140,171
58 Amortization of Loss on Reacquired Debt (428.1) 732,145 732,145
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430) 366,514 366,514
62 Other Interest Expense (431) 3,072,789 3,072,789
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 127,378 127,378
64 Net Interest Charges (Enter Total of lines 56 thru 63) 18,507,498 18,507,498
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 30,535,223 30,535,223
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 30,535,223 30,535,223
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. E-4
Page 1 of 2
Name of Respondent
New England Electric Transmission Corporation
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 9,360,175 9,360,175
3 Operating Expenses
4 Operation Expenses (401) 1,195,551 1,195,551
5 Maintenance Expenses (402) 309,577 309,577
6 Depreciation Expense (403) 4,688,448 4,688,448
7 Amort. & Depl. of Utility Plant (404-405)
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 424,728 424,728
14 Income Taxes - Federal (409.1) 346,865 346,865
15 - Other (409.1) 51,336 51,336
16 Provision for Deferred Income Taxes (410.1) 108,090 108,090
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 147,210 147,210
18 Investment Tax Credit Adj. - Net (411.4) (406,443) (406,443)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 6,570,942 6,570,942
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 2,789,233 2,789,233
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. E-4
Page 2 of 2
Name of Respondent
New England Electric Transmission Corporation
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 2,789,233 2,789,233
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1) 4,666 4,666
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) 9,781 9,781
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 861 861
38 Gain on Disposition of Property (421.1)
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 5,976 5,976
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 702 702
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 702 702
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2) 17 17
48 Income Taxes - Other (409.2)
49 Provision for Deferred Inc. Taxes (410.2)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 17 17
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 5,257 5,257
55 Interest Charges
56 Interest on Long-Term Debt (427) 1,734,068 1,734,068
57 Amort. of Debt Disc. and Expense (428) 40,968 40,968
58 Amortization of Loss on Reacquired Debt (428.1)
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430) 173,164 173,164
62 Other Interest Expense (431) 16,694 16,694
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
64 Net Interest Charges (Enter Total of lines 56 thru 63) 1,964,894 1,964,894
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 829,596 829,596
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 829,596 829,596
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. E-5
Page 1 of 2
Name of Respondent
New England Hydro Transmission Corporation
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 31,394,424 31,394,424
3 Operating Expenses
4 Operation Expenses (401) 9,747,947 9,747,947
5 Maintenance Expenses (402) 173,008 173,008
6 Depreciation Expense (403) 5,866,290 5,866,290
7 Amort. & Depl. of Utility Plant (404-405)
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 2,940,284 2,940,284
14 Income Taxes - Federal (409.1) 917,086 917,086
15 - Other (409.1) 353,305 353,305
16 Provision for Deferred Income Taxes (410.1) 683,800 683,800
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 34,200 34,200
18 Investment Tax Credit Adj. - Net (411.4) 1,000,943 1,000,943
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 21,648,463 21,648,463
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 9,745,961 9,745,961
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. E-5
Page 2 of 2
Name of Respondent
New England Hydro Transmission Corporation
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 9,745,961 9,745,961
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1) 4,334 4,334
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) 131,916 131,916
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 370 370
38 Gain on Disposition of Property (421.1)
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 127,952 127,952
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 240 240
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 240 240
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2) 30,620 30,620
48 Income Taxes - Other (409.2)
49 Provision for Deferred Inc. Taxes (410.2)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 30,620 30,620
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 97,092 97,092
55 Interest Charges
56 Interest on Long-Term Debt (427)
57 Amort. of Debt Disc. and Expense (428)
58 Amortization of Loss on Reacquired Debt (428.1) 28,800 28,800
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430) 4,674,165 4,674,165
62 Other Interest Expense (431) 7,235 7,235
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
64 Net Interest Charges (Enter Total of lines 56 thru 63) 4,710,200 4,710,200
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 5,132,853 5,132,853
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 5,132,853 5,132,853
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. E-6
Page 1 of 2
Name of Respondent
New England Hydro Transmission Electric Company
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 39,364,267 39,364,267
3 Operating Expenses
4 Operation Expenses (401) 4,937,241 4,937,241
5 Maintenance Expenses (402) 1,279,759 1,279,759
6 Depreciation Expense (403) 8,867,993 8,867,993
7 Amort. & Depl. of Utility Plant (404-405) 27,600 27,600
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 3,251,403 3,251,403
14 Income Taxes - Federal (409.1) 1,883,988 1,883,988
15 - Other (409.1) 824,873 824,873
16 Provision for Deferred Income Taxes (410.1) 1,610,000 1,610,000
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) (168,364) (168,364)
18 Investment Tax Credit Adj. - Net (411.4) 1,167,961 1,167,961
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 24,019,182 24,019,182
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 15,345,085 15,345,085
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. E-6
Page 2 of 2
Name of Respondent
New England Hydro Transmission Electric Company
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carrie forward) 15,345,085 15,345,085
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1) 10,526 10,526
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) 252,190 252,190
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 4,614 4,614
38 Gain on Disposition of Property (421.1)
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 246,278 246,278
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 2,238 2,238
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 2,238 2,238
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2) 86,419 86,419
48 Income Taxes - Other (409.2) 17,600 17,600
49 Provision for Deferred Inc. Taxes (410.2)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 104,019 104,019
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 140,021 140,021
55 Interest Charges
56 Interest on Long-Term Debt (427)
57 Amort. of Debt Disc. and Expense (428) 43,200 43,200
58 Amortization of Loss on Reacquired Debt (428.1)
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430) 7,620,007 7,620,007
62 Other Interest Expense (431) 10,375 10,375
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
64 Net Interest Charges (Enter Total of lines 56 thru 63) 7,673,582 7,673,582
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 7,811,524 7,811,524
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 7,811,524 7,811,524
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. E-7
Page 1 of 2
Name of Respondent
Montaup Electric Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 332,786,837 332,786,837
3 Operating Expenses
4 Operation Expenses (401) 257,077,165 257,077,165
5 Maintenance Expenses (402) 12,402,499 12,402,499
6 Depreciation Expense (403) 17,221,414 17,221,414
7 Amort. & Depl. of Utility Plant (404-405) 682,111 682,111
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407) 676,468 676,468
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 6,328,539 6,328,539
14 Income Taxes - Federal (409.1) 5,701,818 5,701,818
15 - Other (409.1) 1,088,045 1,088,045
16 Provision for Deferred Income Taxes (410.1) 1,471,757 1,471,757
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 678,952 678,952
18 Investment Tax Credit Adj. - Net (411.4) (905,104) (905,104)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 301,065,760 301,065,760
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 31,721,077 31,721,077
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. E-7
Page 2 of 2
Name of Respondent
Montaup Electric Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 31,721,077 31,721,077
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1)
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1) 1,548,829 1,548,829
35 Interest and Dividend Income (419) 1,674,347 1,674,347
36 Allowance for Other Funds Used During Construction (419.1) 132,163 132,163
37 Miscellaneous Nonoperating Income (421) 89,804 89,804
38 Gain on Disposition of Property (421.1) 138,533 138,533
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 3,583,676 3,583,676
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) (178,932) (178,932)
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) (178,932) (178,932)
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2) 875,589 875,589
48 Income Taxes - Other (409.2) 190,795 190,795
49 Provision for Deferred Inc. Taxes (410.2) 29,667 29,667
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 1,096,051 1,096,051
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 2,666,557 2,666,557
55 Interest Charges
56 Interest on Long-Term Debt (427) 19,994,750 19,994,750
57 Amort. of Debt Disc. and Expense (428) 68,950 68,950
58 Amortization of Loss on Reacquired Debt (428.1) 870,418 870,418
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430)
62 Other Interest Expense (431) 277,863 277,863
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 83,786 83,786
64 Net Interest Charges (Enter Total of lines 56 thru 63) 21,128,195 21,128,195
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 13,259,439 13,259,439
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 13,259,439 13,259,439
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. E-8
Page 1 of 2
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) $131,551,288 131,551,288
3 Operating Expenses
4 Operation Expenses (401) 101,814,860 101,814,860
5 Maintenance Expenses (402) 2,815,522 2,815,522
6 Depreciation Expense (403) 5,999,741 5,999,741
7 Amort. & Depl. of Utility Plant (404-405) 88,650 88,650
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 7,717,100 7,717,100
14 Income Taxes - Federal (409.1) 1,700,202 1,700,202
15 - Other (409.1) 1,134 1,134
16 Provision for Deferred Income Taxes (410.1) 2,188,258 2,188,258
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 319,823 319,823
18 Investment Tax Credit Adj. - Net (411.4) (178,839) (178,839)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 121,826,805 121,826,805
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 9,724,483 9,724,483
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. E-8
Page 2 of 2
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 9,724,483 9,724,483
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1)
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) (3,114) (3,114)
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 76,396 76,396
38 Gain on Disposition of Property (421.1) 45,744 45,744
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 119,026 119,026
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 154,821 154,821
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 154,821 154,821
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2) 15,561 15,561
48 Income Taxes - Other (409.2)
49 Provision for Deferred Inc. Taxes (410.2)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 15,561 15,561
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) (51,356) (51,356)
55 Interest Charges
56 Interest on Long-Term Debt (427) 3,073,092 3,073,092
57 Amort. of Debt Disc. and Expense (428) 82,023 82,023
58 Amortization of Loss on Reacquired Debt (428.1)
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430)
62 Other Interest Expense (431) 836,696 836,696
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 108,232 108,232
64 Net Interest Charges (Enter Total of lines 56 thru 63) 3,883,579 3,883,579
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 5,789,548 5,789,548
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 5,789,548 5,789,548
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. E-9
Page 1 of 2
Name of Respondent
Eastern Edison Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) $266,376,072 266,376,072
3 Operating Expenses
4 Operation Expenses (401) 220,415,459 220,415,459
5 Maintenance Expenses (402) 5,126,282 5,126,282
6 Depreciation Expense (403) 10,625,246 10,625,246
7 Amort. & Depl. of Utility Plant (404-405)
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 4,623,228 4,623,228
14 Income Taxes - Federal (409.1) 7,500,708 7,500,708
15 - Other (409.1) 1,486,136 1,486,136
16 Provision for Deferred Income Taxes (410.1) 2,454,729 2,454,729
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) 153,009 153,009
18 Investment Tax Credit Adj. - Net (411.4) (304,593) (304,593)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 251,774,186 251,774,186
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 14,601,886 14,601,886
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. E-9
Page 2 of 2
Name of Respondent
Eastern Edison Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 14,601,886 14,601,886
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1)
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1) 13,259,439 13,259,439
35 Interest and Dividend Income (419) 20,139,609 20,139,609
36 Allowance for Other Funds Used During Construction (419.1) (45,605) (45,605)
37 Miscellaneous Nonoperating Income (421) 132,766 132,766
38 Gain on Disposition of Property (421.1) (13,879) (13,879)
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 33,472,330 33,472,330
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 640,491 640,491
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 640,491 640,491
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2) 50,332 50,332
48 Income Taxes - Other (409.2) 9,997 9,997
49 Provision for Deferred Inc. Taxes (410.2)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420)
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) 60,329 60,329
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 32,771,510 32,771,510
55 Interest Charges
56 Interest on Long-Term Debt (427) 13,941,414 13,941,414
57 Amort. of Debt Disc. and Expense (428) 322,185 322,185
58 Amortization of Loss on Reacquired Debt (428.1) 568,186 586,186
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430)
62 Other Interest Expense (431) 3,404,253 3,404,253
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 176,180 176,180
64 Net Interest Charges (Enter Total of lines 56 thru 63) 18,059,858 18,059,858
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 29,313,538 29,313,538
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 29,313,538 29,313,538
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA Companies
Exhibit No. E-10
Page 1 of 2
Name of Respondent
Newport Electric Corporation At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) $61,343,166 $61,343,166
3 Operating Expenses
4 Operation Expenses (401) 44,831,555 44,831,555
5 Maintenance Expenses (402) 2,188,747 2,188,747
6 Depreciation Expense (403) 2,864,116 2,864,116
7 Amort. & Depl. of Utility Plant (404-405) 61,860 61,860
8 Amort. of Utility Plant Acq. Adj. (406)
9 Amort. of Property Losses, Unrecovered Plant and
Regulatory Study Costs (407)
10 Amort. of Conversion Expenses (407)
11 Regulatory Debits (407.3)
12 (Less) Regulatory Credits (407.4)
13 Taxes Other Than Income Taxes (408.1) 4,016,508 4,016,508
14 Income Taxes - Federal (409.1) 1,170,049 1,170,049
15 - Other (409.1) 1,162 1,162
16 Provision for Deferred Income Taxes (410.1) 652,811 652,811
17 (Less) Provision for Deferred Income Taxes - Cr. (411.1) (662) (662)
18 Investment Tax Credit Adj. - Net (411.4) (3,960) (3,960)
19 (Less) Gains from Disp. of Utility Plant (411.6)
20 Losses from Disp. of Utility Plant (411.7)
21 (Less) Gains from Disposition of Allowances (411.8)
22 Losses from Disposition of Allowances (411.9)
23 TOTAL Utility Operating Expenses (Enter Total of
Lines 4 thru 22) 55,783,510 55,783,510
24 Net Utility Operating Income (Enter Total of
line 2 less 23) (Carry forward to line 25) 5,559,656 5,559,656
<PAGE>
<CAPTION>
EUA Companies
Exhibit No. E-10
Page 2 of 2
Name of Respondent
Newport Electric Company At September 30, 1998
STATEMENT OF INCOME FOR THE YEAR (Continued)
12 months 12 months
Line Account ended Pro-Forma Adjusted
No. 9-30-98 Adjustments 9-30-98
<S> <C> <C> <C>
25 Net Utility Operating Income (Carried forward) 5,559,656 5,559,656
26 Other Income and Deductions
27 Other Income
28 Nonutility Operating Income
29 Revenues From Merchandising, Jobbing and Contract Work (415)
30 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
31 Revenues From Nonutility Operations (417)
32 (Less) Expenses of Nonutility Operations (417.1)
33 Nonoperating Rental Income (418)
34 Equity in Earnings of Subsidiary Companies (418.1)
35 Interest and Dividend Income (419) 10,617 10,617
36 Allowance for Other Funds Used During Construction (419.1)
37 Miscellaneous Nonoperating Income (421) 4,209 4,209
38 Gain on Disposition of Property (421.1) (4,345) (4,345)
39 TOTAL Other Income (Enter Total of lines 29 thru 38) 10,481 10,481
40 Other Income Deductions
41 Loss on Disposition of Property (421.2)
42 Miscellaneous Amortization (425)
43 Miscellaneous Income Deductions (426.1-426.5) 76,463 76,463
44 TOTAL Other Income Deductions (Total of lines 41 thru 43) 76,463 76,463
45 Taxes Applic. to Other Income and Deductions
46 Taxes Other Than Income Taxes (408.2)
47 Income Taxes - Federal (409.2)
48 Income Taxes - Other (409.2) (10,452) (10,452)
49 Provision for Deferred Inc. Taxes (410.2)
50 (Less) Provision for Deferred Income Taxes - Cr. (411.2)
51 Investment Tax Credit Adj. - Net (411.5)
52 (Less) Investment Tax Credits (420) 81,360 81,360
53 TOTAL Taxes on Other Income and Deduct. (Total of 46 thru 52) (91,812) (91,812)
54 Net Other Income and Deductions (Enter Total of lines 39, 44, 53) 25,830 25,830
55 Interest Charges
56 Interest on Long-Term Debt (427) 1,444,216 1,444,216
57 Amort. of Debt Disc. and Expense (428) 54,539 54,539
58 Amortization of Loss on Reacquired Debt (428.1) 47,056 47,056
59 (Less) Amort. of Premium on Debt - Credit (429)
60 (Less) Amortization of Gain on Reacquired Debt - Credit (429.1)
61 Interest on Debt to Assoc. Companies (430)
62 Other Interest Expense (431) 677,550 677,550
63 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 41,530 41,530
64 Net Interest Charges (Enter Total of lines 56 thru 63) 2,181,831 2,181,831
65 Income Before Extraordinary Items (Total of lines 25, 54 and 64) 3,403,655 3,403,655
66 Extraordinary Items
67 Extraordinary Income (434)
68 (Less) Extraordinary Deductions (435)
69 Net Extraordinary Items (Enter Total of line 67 less line 68)
70 Income Taxes-Federal and Other (409.3)
71 Extraordinary Items After Taxes (Enter Total of line 69 less line 70)
72 Net Income (Enter Total of lines 65 and 71) 3,403,655 3,403,655
</TABLE>
<PAGE>
JOINT APPLICATION OF
NEW ENGLAND POWER COMPANY, et al.
AND MONTAUP ELECTRIC COMPANY, et al.
FOR APPROVAL OF MERGER AND RELATED AUTHORIZATIONS
EXHIBIT F-1 New England Power Company
EXHIBIT F-2 Massachusetts Electric Company
EXHIBIT F-3 The Narragansett Electric Company
EXHIBIT F-4 New England Electric Transmission Corporation
EXHIBIT F-5 New England Hydro Transmission Corporation
EXHIBIT F-6 New England Hydro-Transmission Electric Company, Inc.
EXHIBIT F-7 Montaup Electric Company
EXHIBIT F-8 Blackstone Valley Electric Company
EXHIBIT F-9 Eastern Edison Company
EXHIBIT F-10 Newport Electric Corporation
Analysis of Retained Earnings for the 12 Months Ending September 30, 1998
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-1
Page 1 of 2
Name of Respondent
New England Power Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 372,385,240 372,385,240
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit: Transfer from 215.1 23,204,856 23,204,856
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8) 23,204,856 23,204,856
10 Debit: Repurchase of Common Stock (193,817,339) (193,817,339)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439)
(Total of lines 10 thru 14) (193,817,339) (193,817,339)
16 Balance Transferred from Income (Account 433 less Account 418.1) 133,929,044 133,929,044
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal (3,451,609) (3,451,609)
19
20
21
22 Total Appropriations of Retained Earnings (Acc. 436)
(Total of lines 18 thru 21) (3,451,609) (3,451,609)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends Declared on Preferred Stock (1,697,833) (1,697,833)
25
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. 437)
(Total of lines 24 thru 28) (1,697,833) (1,697,833)
30 Dividends Declared - Common Stock (Account 438)
31 Dividends Declared on Common Stock (166,084,822) (166,084,822)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. 438)
(Total of lines 31 thru 35) (166,084,822) (166,084,822)
37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary
Earnings 7,634,030 7,634,030
38 Balance - End of Year (Total of lines 01,09,15,16,22,29,36, and 37) 172,101,567 172,101,567
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-1
Page 2 of 2
Name of Respondent
New England Power Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization Reserve, Federal
(Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1) (Enter
total of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 216)(Enter total of
lines 38 and 47) 172,101,567 172,101,567
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit) 16,420,340 16,420,340
50 Equity in Earnings for Year (Credit) (Account 418.1) 5,466,612 5,466,612
51 (Less) Dividends Received (Debit) 7,634,030 7,634,030
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52) 14,252,922 14,252,922
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-2
Page 1 of 2
Name of Respondent
Massachusetts Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 171,807,605 171,807,605
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Premium on Redemption of Preferred Stock (3,764,951) (3,764,951)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439) (3,764,951) (3,764,951)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 418.1) 67,071,865 67,071,865
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc. 436)
(Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock
25 Cummulative Preferred Stock 4.44% (147,360) (147,360)
26 Cummulative Preferred Stock 4.76% (156,776) (156,776)
27 Cummulative Preferred Stock 6.99% (493,691) (493,691)
28 Cummulative Preferred Stock 6.84% (408,042) (408,042)
29 TOTAL Dividends Declared - Preferred Stock (Acct. 437)
(Total of lines 24 thru 28) (1,205,869) (1,205,869)
30 Dividends Declared - Common Stock (Account 438)
31 2,398,111 Shares @ $17.50/Share (41,966,943) (41,966,943)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. 438)
(Total of lines 31 thru 35) (41,966,943) (41,966,943)
37 Transfers from Acct. 216.1, Unappropriated Undistributed Subsidiary
Earnings
38 Balance - End of Year (Total of lines 01,09,15,16,22,29,36, and 37) 191,941,707 191,941,707
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-2
Page 2 of 2
Name of Respondent
Massachusetts Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39 4,637,347
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215) 4,637,347
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization Reserve, Federal
(Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)
(Enter total of lines 45 and 46) 4,637,347 4,637,347
48 Total Retained Earnings (Account 215, 215.1, 216)
(Enter total of lines 38 and 47) 196,579,054 196,579,054
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-3
Page 1 of 2
Name of Respondent
Narragansett Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 129,686,160 129,686,160
2 Changes (Identify by prescribed retained earnings
accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Reacquisition of Preferred Stock (2,826,003) (2,826,003)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439) (2,826,003) (2,826,003)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 30,535,223 30,535,223
418.1)
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc.
436) (Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock
25 4.50% Series (144,600) (144,600)
26 4.64% Series (165,596) (165,596)
27 6.95% Series (515,086) (515,086)
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. (825,282) (825,282)
437) (Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31 1,132,487 Shares at $64.50 (73,045,412) (73,045,412)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. 73,045,412) (73,045,412)
438) (Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed
Subsidiary Earnings
38 Balance - End of Year (Total of lines 83,524,686 83,524,686
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-3
Page 2 of 2
Name of Respondent
Narragansett Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 83,524,686 83,524,686
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-4
Page 1 of 2
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 294,086 294,086
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Premium on reacquisition of Capital Stock (42,282) (42,282)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 418.1) 829,596 829,596
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc. 436)
(Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock
25
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct.437)
(Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31 (954,000) (954,000)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct.438) (954,000) (954,000)
(Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed
Subsidiary Earnings
38 Balance - End of Year (Total of lines 127,400 127,400
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-4
Page 2 of 2
Name of Respondent
New England Electric Transmission Corporation At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 216) 127,400 127,400
(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-5
Page 1 of 2
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 557,639 537,639
2 Changes (Identify by prescribed retained earnings
accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Premium on reacquisition of Capital Stock (50,466) (50,466)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439) (50,466) (50,466)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 418.1) 5,132,853 5,132,853
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc. 436)
(Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock
25
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. 437)
(Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31 (5,549,750) (5,549,750)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. 438) (5,549,750) (5,549,750)
(Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed
Subsidiary Earnings
38 Balance - End of Year (Total of lines 90,276 90,276
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-5
Page 2 of 2
Name of Respondent
New England Hydro Transmission Corporation At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 90,276 90,276
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-6
Page 1 of 2
Name of Respondent
New England Hydro Transmission Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 456,236 456,226
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Premium on reacquisition of Capital Stock (31,362) (31,362)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439) (31,362) (31,362)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 7,811,524 7,811,524
418.1)
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc.
436) (Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock
25
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. 437)
(Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31 (8,140,000) (8,140,000)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. (8,140,000) (8,140,000)
438) (Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed
Subsidiary Earnings
38 Balance - End of Year (Total of lines 96,398 96,398
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-6
Page 2 of 2
Name of Respondent
New England Hydro Transmission Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. 9-30-98 Adjustments 9-30-98
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 96,398 96,398
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-7
Page 1 of 2
Name of Respondent
Montaup Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 69,650,578 69,650,578
2 Changes (Identify by prescribed retained earnings
accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit:
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 11,710,610 11,710,610
418.1)
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc.
436) (Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock (339,000) (339,000)
25
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. (339,000)` (339,000)
437) (Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31 (13,243,600) (13,243,600)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. (13,243,600) (13,243,600)
438) (Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed 1,951,718 1,951,718
Subsidiary Earnings
38 Balance - End of Year (Total of lines 69,730,306 69,730,306
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-7
Page 2 of 2
Name of Respondent
Montaup Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 69,730,306 69,730,306
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit) 4,462,275 4,462,275
50 Equity in Earnings for Year (Credit) (Account 418.1) 1,548,829 1,548,829
51 (Less) Dividends Received (Debit) 1,951,718 1,951,718
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52) 4,059,386 4,059,386
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-8
Page 1 of 2
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 10,102,232 10,102,232
2 Changes (Identify by prescribed retained earnings
accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit:
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 5,789,548 5,789,548
418.1)
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc.
436) (Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock
25 4.25% Preferred Stock (148,750) (148,750)
26 5.60% Preferred Stock (140,000) (140,000)
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. (288,750) (288,750)
437) (Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31
32 Common Stock (1,923,449) (1,923,449)
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. (1,923,449) (1,923,449)
438) (Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed
Subsidiary Earnings
38 Balance - End of Year (Total of lines 13,679,581 13,679,581
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-8
Page 2 of 2
Name of Respondent
Blackstone Valley Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 13,679,581 13,679,581
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-9
Page 1 of 2
Name of Respondent
Eastern Edison Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 26,070,503 26,070,503
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Amortization of Preferred Stock Redemption Cost (435,552) (435,552)
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439) ($435,552) (435,552)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 16,054,099 16,054,099
418.1)
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc.
436) (Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 6.625% (1,987,500) (1,987,500)
25
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. (1,987,500) (1,987,500)
437) (Total of lines 24 thru 28)
30 Dividends Declared - Common Stock (Account 438)
31 (27,612,460) (27,612,460)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. (27,612,460) (27,612,460)
438) (Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed 13,582,600 13,582,600
Subsidiary Earnings
38 Balance - End of Year (Total of lines 25,671,690 25,671,690
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-9
Page 2 of 2
Name of Respondent
Eastern Edison Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 25,671,690 25,671,690
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit) 74,112,853 74,112,853
50 Equity in Earnings for Year (Credit) (Account 418.1) 13,259,439 13,259,439
51 (Less) Dividends Received (Debit) 13,582,600 13,582,600
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52) 73,789,692 73,789,692
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES Companies
Exhibit No. F-10
Page 1 of 2
Name of Respondent
Newport Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
<S> <C> <C> <C>
1 Balance - Beginning of Year 2,283,575 2,283,575
2 Changes (Identify by prescribed retained earnings accounts)
3 Adjustments to Retained Earnings (Account 439)
4 Credit:
5 Credit:
6 Credit:
7 Credit:
8 Credit:
9 TOTAL Credits to Retained Earnings (Acc. 439)
(Total of lines 4 thru 8)
10 Debit: Amortization of Preferred Stock Redemption Cost
11 Debit:
12 Debit:
13 Debit:
14 Debit:
15 TOTAL Debits to Retained Earnings (Acc. 439)
(Total of lines 10 thru 14)
16 Balance Transferred from Income (Account 433 less Account 3,403,655 3,403,655
418.1)
17 Appropriations of Retained Earnings (Account 436)
18 Amortization Reserve, Federal
19
20
21
22 Total Appropriations of Retained Earnings (Acc.
436) (Total of lines 18 thru 21)
23 Dividends Declared - Preferred Stock (Account 437)
24 *Dividends declared on preferred stock (28,834) (28,834)
25 3.75% Preferred Stock
26
27
28
29 TOTAL Dividends Declared - Preferred Stock (Acct. (28,834) (28,834)
437) (Total of lines 24 thru 28)
(Account 438)
30 Dividends Declared - Common Stock
31 (2,410,000) (2,410,000)
32
33
34
35
36 TOTAL Dividends Declared - Common Stock (Acct. (2,410,000) (2,410,000)
438) (Total of lines 31 thru 35)
37 Transfers from Acct. 216.1, Unappropriated Undistributed
Subsidiary Earnings
38 Balance - End of Year (Total of lines 3,248,396 3,248,396
01,09,15,16,22,29,36, and 37)
<PAGE>
<CAPTION>
NEES Companies
Exhibit No. F-10
Page 2 of 2
Name of Respondent
Newport Electric Company At September 30, 1998
STATEMENT OF RETAINED EARNINGS FOR THE YEAR (Continued)
Adjusted
Line Item Balance at Pro-Forma Balance at
No. September 1998 Adjustments September 1998
APPROPRIATED RETAINED EARNINGS (Account 215)
<S> <C> <C> <C>
39
40
41
42
43
44
45 Total Appropriated Retained Earnings (Account 215)
APPROPRIATED RETAINED EARNINGS - AMORTIZATION RESERVE, FEDERAL
(Account 215.1)
46 Total Appropriated Retained Earnings - Amortization
Reserve, Federal (Account 215.1)
47 Total Appropriated Retained Earnings - (Account 215,215.1)(Enter total
of lines 45 and 46)
48 Total Retained Earnings (Account 215, 215.1, 3,248,396 3,248,396
216)(Enter total of lines 38 and 47)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (ACCOUNT 216.1)
49 Balance - Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
52 Other Changes (Explain)
53 Balance - End of Year (Total of Lines 49 thru 52)
</TABLE>
<PAGE>
Exhibit G
State filings to be provided separately.
<PAGE>
Exhibit H
See separate volume.
AGREEMENT AND PLAN OF MERGER
and CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
Exhibit I
[Map Reflecting the NEES and EUA
Direct Retail Service Areas
and Transmission Networks]
<PAGE>
AGREEMENT AND PLAN OF MERGER
and CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
TABLE OF CONTENTS
AGREEMENT AND PLAN OF MERGER...................................................1
CONSENT AGREEMENT..............................................................2
<PAGE>
Tab 1
AGREEMENT AND PLAN OF MERGER
dated as of February 1, 1999
by and among
NEW ENGLAND ELECTRIC SYSTEM,
RESEARCH DRIVE LLC
and
EASTERN UTILITIES ASSOCIATES
<PAGE>
TABLE OF CONTENTS
Page
No.
ARTICLE I
THE MERGER......................................................... 1
1.01 The Merger......................................................... 1
1.02 Effective Time..................................................... 1
1.03 Effects of the Merger.............................................. 2
ARTICLE II
CONVERSION OF SHARES............................................... 2
2.01 Conversion of Capital Stock........................................ 2
2.02 Surrender of Shares................................................ 3
2.03 Withholding Rights................................................. 4
ARTICLE III
THE CLOSING........................................................ 4
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5
4.01 Organization and Qualification..................................... 5
4.02 Capital Stock...................................................... 6
4.03 Authority.......................................................... 7
4.04 Non-Contravention; Approvals and Consents.......................... 7
4.05 SEC Reports, Financial Statements and Utility Reports.............. 8
4.06 Absence of Certain Changes or Events............................... 9
4.07 Legal Proceedings.................................................. 9
4.08 Information Supplied............................................... 9
4.09 Compliance......................................................... 10
4.10 Taxes.............................................................. 10
4.11 Employee Benefit Plans; ERISA...................................... 12
4.12 Labor Matters...................................................... 14
4.13 Environmental Matters.............................................. 15
4.14 Regulation as a Utility............................................ 17
4.15 Insurance.......................................................... 17
4.16 Nuclear Facilities................................................. 18
4.17 Vote Required...................................................... 18
4.18 Opinion of Financial Advisor....................................... 18
-i-
<PAGE>
Page
No.
4.19 Ownership of NEES Common Shares.................................... 18
4.20 State Anti-Takeover Statutes....................................... 18
4.21 Year 2000.......................................................... 19
4.22 EUA Associates..................................................... 19
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES............................. 19
5.01 Organization and Qualification..................................... 19
5.02 Authority.......................................................... 20
5.03 Capital Stock...................................................... 20
5.04 Non-Contravention; Approvals and Consents.......................... 20
5.05 Information Supplied............................................... 21
5.06 Compliance......................................................... 21
5.07 Financing.......................................................... 22
5.08 No Vote Required................................................... 22
5.09 Ownership of EUA Shares............................................ 22
5.10 Merger with The National Grid Group plc............................ 22
ARTICLE VI
COVENANTS................................................ 22
6.01 Covenants of EUA................................................... 22
6.02 Covenants of NEES.................................................. 28
6.03 Additional Covenants by NEES and EUA............................... 29
ARTICLE VII
ADDITIONAL AGREEMENTS.................................... 30
7.01 Access to Information.............................................. 30
7.02 Proxy Statement.................................................... 31
7.03 Approval of Shareholders........................................... 31
7.04 Regulatory and Other Approvals..................................... 31
7.05 Employee Benefit Plans............................................. 32
7.06 Labor Agreements and Workforce Matters............................. 34
7.07 Post Merger Operations............................................. 34
7.08 No Solicitations................................................... 35
7.09 Directors' and Officers' Indemnification and Insurance............. 36
7.10 Expenses........................................................... 37
7.11 Brokers or Finders................................................. 37
7.12 Anti-Takeover Statutes............................................. 38
7.13 Public Announcements............................................... 38
-ii-
<PAGE>
Page
No.
7.14 Restructuring of the Merger........................................ 38
ARTICLE VIII
CONDITIONS......................................................... 39
8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39
8.03 Conditions to Obligation of EUA to Effect the Merger............... 40
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER.................................. 41
9.01 Termination........................................................ 41
9.02 Effect of Termination.............................................. 43
9.03 Termination Fees................................................... 43
9.04 Amendment.......................................................... 44
9.05 Waiver............................................................. 44
ARTICLE X
GENERAL PROVISIONS................................................. 44
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements......................................................... 44
10.02 Notices............................................................ 44
10.03 Entire Agreement; Incorporation of Exhibits........................ 46
10.04 No Third Party Beneficiary......................................... 46
10.05 No Assignment; Binding Effect...................................... 46
10.06 Headings........................................................... 47
10.07 Invalid Provisions................................................. 47
10.08 Governing Law...................................................... 47
10.09 Enforcement of Agreement........................................... 47
10.10 Certain Definitions................................................ 47
10.11 Counterparts....................................................... 48
10.12 WAIVER OF JURY TRIAL............................................... 48
-iii-
<PAGE>
GLOSSARY OF DEFINED TERMS
The following terms, when used in this Agreement, have the meanings
ascribed to them in the corresponding Sections of this Agreement listed below:
"1935 Act" -- Section 4.05(b)
"Adjustment Date" -- Section 2.01(c)
"Affected Employees" -- Section 7.05(a)
"affiliate" -- Section 10.11(a)
"Agreement" -- Preamble
"Alternative Proposal" -- Section 7.08
"beneficially" -- Section 10.10(b)
"business day" -- Section 10.10(c)
"Canceled Shares" -- Section 2.02(b)
"Certificates" -- Section 2.02(b)
"Closing" -- Article III
"Closing Agreement" -- Section 4.10(j)
"Closing Date" -- Article III
"Code" -- Section 2.03
"Confidentiality Agreement" -- Section 7.01
"Constituent Entities" -- Section 1.01
"Contracts" -- Section 4.04(a)
"control," "controlling,"
"controlled by" and
"under common control with" -- Section 10.10(a)
"DOE" -- Section 4.05(b)
"Effective Time" -- Section 1.02
"Environmental Claim" -- Section 4.13(f)(i)
"Environmental Laws" -- Section 4.13(f)(ii)
"Environmental Permits" -- Section 4.13(b)
"ERISA" -- Section 4.11(a)
"ERISA Affiliate" -- Section 4.11(c)
"EUA" -- Preamble
"EUA Associates" -- Section 4.01(b)
"EUA Employee Agreements" -- Section 7.05(d)(ii)
"EUA Executives" -- Section 7.05(d)(ii)
"EUA Shares" -- Preamble
"EUA Disclosure Letter" -- Section 4.01(a)
"EUA Employee Benefit Plans" -- Section 4.11(a)
"EUA Financial Statements" -- Section 4.05(a)
"EUA Nuclear Facilities" -- Section 4.16
"EUA Material Adverse Effect" -- Section 4.01(a)
"EUA Required Consents" -- Section 4.04(a)
"EUA Required Statutory Approvals" -- Section 4.04(b)
"EUA SEC Reports" -- Section 4.05(a)
-iv-
<PAGE>
"EUA Shareholders' Approval" -- Section 7.03
"EUA Shareholders' Meeting" -- Section 7.03
"EUA Significant Subsidiary" -- Section 7.08
"EUA Shares" -- Preamble
"EUA Trust Agreement" -- Section 1.03
"EUA Voting Debt -- Section 4.02(d)
"Evaluation Material" -- Section 7.01(a)
"Exchange Act" -- Section 4.05(a)
"Exchange Fund" -- Section 2.02(a)
"Extended Termination Date" -- Section 9.01(b)
"FCC" -- Section 4.05(b)
"FERC" -- Section 4.05(b)
"Final Order" -- Section 8.01(d)
"Governmental Authority" -- Section 4.04(a)
"Hazardous Materials" -- Section 4.13(f)(iii)
"HSR Act" -- Section 7.04(a)
"Indemnified Liabilities" -- Section 7.09(a)
"Indemnified Party" -- Section 7.09(a)
"Indemnified Parties" -- Section 7.09(a)
"Information Systems" -- Section 4.21
"Initial Termination Date" -- Section 9.01(b)
"IRS" -- Section 4.10(m)
"knowledge" -- Section 10.11(d)
"laws" -- Section 4.04(a)
"Lien" -- Section 4.02(b)
"LLC" -- Preamble
"Massachusetts Secretary" -- Section 1.02
"Merger" -- Preamble
"Merger Consideration" -- Section 2.01(b)(ii)
"MGL" -- Section 1.01
"National Grid Group" -- Section 5.10
"National Grid Merger Agreement" -- Section 5.10
"NEES" -- Preamble
"NEES Disclosure Letter" -- Section 5.03
"NEES Material Adverse Effect" -- Section 5.01
"NEES-EUA Regulatory Approvals" -- Section 7.04(b)
"NEES-EUA Regulatory Proceedings" -- Section 7.04(c)
"NEES Required Consents" -- Section 5.04(a)
"NEES Required Statutory Approvals" -- Section 5.04(b)
"NEES-NGG Regulatory Approvals" -- Section 7.04(c)
"NEES-NGG Regulatory Proceedings" -- Section 7.04(c)
"NEES-NGG Required Statutory Approvals"-- Section 7.04
"NEES-NGG Transactions" -- Section 7.04
"NEES Shares" -- Section 5.03
-v-
<PAGE>
"NEES Trust Agreement" -- Section 5.01
"NGG Circular" -- Section 7.02
"NRC" -- Section 4.05(b)
"Options" -- Section 4.02(a)
"orders" -- Section 4.04(a)
"Out-of-Pocket Expenses" -- Section 9.03(a)
"Paying Agent" -- Section 2.02(a)
"PBGC" -- Section 4.11(g)
"person" -- Section 10.11(e)
"Per Share Amount" -- Section 2.01(b)(ii)
"Post Closing Plans" -- Section 7.05(b)
"Proxy Statement" -- Section 4.08(a)
"Release" -- Section 4.13(f)(iv)
"Representatives" -- Section 10.11(f)
"SEC" -- Section 4.05(a)
"Securities Act" -- Section 4.05(a)
"Subsidiary" -- Section 10.11(g)
"Surviving Entity" -- Section 1.01
"Tax Ruling" -- Section 4.10(j)
"Taxes" -- Section 4.10
"Tax Return" -- Section 4.10
"US GAAP" -- Section 4.05(a)
"Yankee Companies" -- Section 4.16
"Y2K Consultant" -- Section 6.01(o)
-vi-
<PAGE>
This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this
"Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM,
a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a
Massachusetts limited liability company which is directly and indirectly wholly
owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust
("EUA").
WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA
and the members of LLC have each determined that it is advisable and in the best
interests of their respective shareholders and members to consummate, and have
approved, the business combination transaction provided for herein in which LLC
would merge with and into EUA, with EUA being the surviving entity (the
"Merger"), pursuant to the terms and conditions of this Agreement, as a result
of which NEES will own, directly or indirectly, all of the issued and
outstanding common shares of EUA (the "EUA Shares");
WHEREAS, NEES, LLC and EUA desire to make certain representations,
warranties and agreements in connection with the Merger and also to prescribe
various conditions to the Merger;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements set forth in this Agreement, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereto hereby agree as follows:
ARTICLE I
THE MERGER
1.01 The Merger. Upon the terms and subject to the conditions of this
Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be
merged with and into EUA in accordance with Section 2 of Chapter 182 and Section
59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective
Time, the separate existence of LLC shall cease and EUA shall continue as the
surviving entity in the Merger. EUA, after the Effective Time, is sometimes
referred to herein as the "Surviving Entity" and EUA and LLC are sometimes
referred to herein as the "Constituent Entities". The effect and consequences of
the Merger shall be as set forth in Article II.
1.02 Effective Time. Subject to the provisions of this Agreement, on
the Closing Date (as defined in Article III), a certificate of merger shall be
executed and filed by EUA and LLC with the Secretary of the Commonwealth of
Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective
at the time of the filing of the certificate of merger relating to the Merger
with the Massachusetts Secretary, or at such later time as is specified in the
certificate of merger (such date and time being referred to herein as the
"Effective Time").
<PAGE>
1.03 Effects of the Merger. At the Effective Time, the Agreement and
Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately
prior to the Effective Time shall be the agreement and declaration of trust of
the Surviving Entity, until thereafter amended as provided by law and such
agreement and declaration of trust. Subject to the foregoing, the additional
effects of the Merger shall be as provided in the applicable provisions of
Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability
Company Act of Massachusetts.
ARTICLE II
CONVERSION OF SHARES
2.01 Conversion of Capital Stock. At the Effective Time, by virtue of
the Merger and without any action on the part of the holder thereof:
(a) Membership Interests of LLC. Each one percent of the issued
and outstanding membership interests in LLC shall be converted into one
transferable certificate of participation or share of the Surviving Entity.
(b) Conversion of EUA Shares.
(i) Cancellation of Treasury Shares and Shares Owned by
NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares
and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as
defined in Section 10.11) of NEES shall be canceled and retired and shall cease
to exist and no cash or other consideration shall be delivered in exchange
therefor.
(ii) Conversion of EUA Shares. Each EUA Share issued and
outstanding immediately prior to the Effective Time (other than shares to be
canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted
in accordance with the provisions of this Section 2.01 into the right to receive
cash in the amount (the "Per Share Amount") of $31.00 as such amount may
hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger
Consideration"), payable, without interest, to the holder of such EUA Share,
upon surrender, in the manner provided in Section 2.02 hereof, of the
certificate formerly evidencing such share.
(c) Adjustment in Amount of Merger Consideration. In the event
that the Closing Date shall not have occurred on or prior to the date that is
the six (6) month anniversary of the date on which EUA Shareholders' Approval is
obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for
each day after the Adjustment Date up to and including the day which is one day
prior to the earlier of the Closing Date and the Extended Termination Date, by
an amount equal to $0.003.
-2-
<PAGE>
2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the
Effective Time, NEES shall designate a bank or trust company reasonably
acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the
holders of EUA Shares in connection with the Merger to receive the funds to
which holders of EUA Shares shall become entitled pursuant to Section
2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or
after the Effective Time, NEES or LLC shall make or cause to be made available
to the Paying Agent immediately available funds in amounts and at the times
necessary for the payment of the Merger Consideration upon surrender of
Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b),
it being understood that any and all interest or other income earned on funds
made available to the Paying Agent pursuant to this Section 2.02(a) shall belong
to and shall be paid (at the time provided for in Section 2.02(e)) as directed
by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be
invested by the Paying Agent as directed by NEES or LLC.
(b) Exchange Procedure. As soon as practicable after the
Effective Time, the Paying Agent shall mail to each holder of record of a
certificate or certificates (the "Certificates") which immediately prior to the
Effective Time represented outstanding EUA Shares (the "Canceled Shares") that
were canceled and became instead the right to receive the Merger Consideration
pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as
NEES and EUA may reasonably agree (which shall specify that delivery shall be
effected, and risk of loss and title to the Certificates shall pass, only upon
actual delivery of the Certificates to the Paying Agent) and (ii) instructions
for effecting the surrender of the Certificates in exchange for the Merger
Consideration. Upon surrender of a Certificate or Certificates to the Paying
Agent for cancellation (or to such other agent or agents as may be appointed by
NEES and are reasonably acceptable to EUA), together with a duly executed letter
of transmittal and such other documents as the Paying Agent shall require, the
holder of such Certificate shall be entitled to receive the Merger Consideration
in exchange for each EUA Share formerly evidenced by such Certificate which such
holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of
a transfer of ownership of Canceled Shares which is not registered in the
transfer records of EUA, the Merger Consideration in respect of such Canceled
Shares may be given to the transferee thereof if the Certificate or Certificates
representing such Canceled Shares is presented to the Paying Agent, accompanied
by all documents required to evidence and effect such transfer and by evidence
satisfactory to the Paying Agent that any applicable stock transfer taxes have
been paid. At any time after the Effective Time, each Certificate shall be
deemed to represent only the right to receive the Merger Consideration subject
to and upon the surrender of such Certificate as contemplated by this Section
2.02. No interest shall be paid or will accrue on the Merger Consideration
payable to holders of Certificates pursuant to Section 2.01(b)(ii).
(c) No Further Ownership Rights in EUA Shares. The Merger
Consideration paid upon the surrender of Certificates in accordance with the
terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective
Time in full satisfaction of all rights pertaining to EUA Shares represented
thereby. From and after the Effective Time, the share transfer books of EUA
shall be closed and there shall be no further registration of transfers thereon
of EUA Shares which were outstanding immediately prior to the Effective Time.
-3-
<PAGE>
If, after the Effective Time, Certificates are presented to NEES for any reason,
they shall be canceled and exchanged as provided in this Section 2.02.
(d) Lost, Stolen or Destroyed Certificates. In the event any
owner of any Certificate shall claim that such Certificate shall have been lost,
stolen or destroyed, upon the making of an affidavit of that fact by the owner
of such Certificate and delivery of that affidavit to the Paying Agent and, if
required by NEES or LLC, the posting by such person of a bond in customary
amount as indemnity against any claim that may be made against NEES, EUA or the
Surviving Entity with respect to such Certificate, the Paying Agent will issue
in exchange for such lost, stolen or destroyed Certificate the Merger
Consideration payable upon due surrender of, and deliverable pursuant to this
Section 2.02 in respect of, EUA Shares to which such Certificate relates.
(e) Termination of Exchange Fund. Any portion of the Exchange
Fund which remains undistributed to the shareholders of EUA for one (1) year
after the Effective Time shall be delivered to the Surviving Entity, upon
demand, and any Shareholders of EUA who have not theretofore complied with this
Article II shall thereafter look only to the Surviving Entity (subject to
abandoned property, escheat and other similar laws) as general creditors for
payment of their claim for the Merger Consideration payable upon due surrender
of the Certificates held by them. None of NEES, LLC or the Surviving Entity
shall be liable to any former holder of EUA Shares for the Merger Consideration
delivered to a public official pursuant to any applicable abandoned property,
escheat or similar law.
2.03 Withholding Rights. Each of the Surviving Entity and NEES shall
be entitled to deduct and withhold from the consideration otherwise payable
pursuant to this Agreement to any holder of EUA Shares such amounts as it is
required to deduct and withhold with respect to the making of such payment under
the Internal Revenue Code of 1986, as amended (the "Code"), or any other
provision of state, local or foreign tax law. To the extent that amounts are so
withheld by the Surviving Entity or NEES, as the case may be, such withheld
amounts shall be treated for all purposes of this Agreement as having been paid
to the holder of EUA Shares in respect of which such deduction and withholding
was made by the Surviving Entity or NEES, as the case may be.
ARTICLE III
THE CLOSING
The closing of the Merger and other transactions contemplated hereby
(the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher
& Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local
time, on the second business day following satisfaction or waiver (where
applicable) of the conditions set forth in Article VIII (other than those
conditions that by their nature are to be fulfilled at the Closing, but subject
to the fulfillment or waiver of such conditions), unless another date, time or
place is agreed to in writing by the parties hereto (the "Closing Date").
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA
EUA represents and warrants to NEES and LLC as follows:
4.01 Organization and Qualification. (a) EUA is a voluntary
association duly organized, validly existing and in good standing under the laws
of the Commonwealth of Massachusetts and has full power, authority and legal
right to own its property and assets and to transact the business in which it is
engaged. Each of EUA's Subsidiaries is a corporation duly organized or
incorporated, validly existing and in good standing under the laws of its
jurisdiction of organization or incorporation and has full corporate power and
authority to conduct its business as and to the extent now conducted and to own,
use and lease its assets and properties, except where failure to be so organized
or incorporated, existing and in good standing or to have such power and
authority, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA
Material Adverse Effect" means a material adverse effect on the business,
assets, results of operations, condition (financial or otherwise) or prospects
of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries
is duly qualified, licensed or admitted to do business and is in good standing
in each jurisdiction in which the ownership, use or leasing of its assets and
properties, or the conduct or nature of its business, makes such qualification,
licensing or admission necessary, except where failure to be so qualified,
licensed or admitted and in good standing, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect. Section
4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA
concurrently with the execution and delivery of this Agreement (the "EUA
Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or
organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized
capital stock, (iii) the number of issued and outstanding shares of capital
stock of such Subsidiary and (iv) the number of shares of such Subsidiary held
of record by EUA. EUA has previously delivered to NEES correct and complete
copies of the EUA Trust Agreement and the certificate or articles of
organization or incorporation and bylaws (or other comparable charter documents)
of its Subsidiaries.
(b) Section 4.01 of the EUA Disclosure Letter sets forth a
description as of the date hereof, of all EUA Associates, including (i) the name
of each such entity and EUA's interest therein and (ii) a brief description of
the principal line or lines of business conducted by each such entity. For
purposes of this Agreement "EUA Associates" shall mean any corporation or other
entity (including partnerships and other business associations) that is not a
Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly
or indirectly, owns an equity interest (other than short-term investments in the
ordinary course of business) if such corporation or other entity (including
partnerships and other business associations) contributes five percent or more
of EUA's consolidated revenues, assets, income or costs.
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4.02 Capital Stock. (a) The authorized equity securities of EUA
consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and
outstanding as of the close of business on January 29, 1999. As of the close of
business on January 29, 1999, no EUA Shares were held in the treasury of EUA.
Since such date there has been no change in the sum of the issued and
outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly
authorized, validly issued, fully paid and nonassessable. Except pursuant to
this Agreement and except as described in Section 4.02 of the EUA Disclosure
Letter, on the date hereof there are no outstanding subscriptions, options,
warrants, rights (including share appreciation rights), preemptive rights or
other contracts, commitments, understandings or arrangements, including any
right of conversion or exchange under any outstanding security, instrument or
agreement (together, "Options"), obligating EUA or any of its Subsidiaries to
issue or sell any shares of equity securities of EUA or to grant, extend or
enter into any Option with respect thereto. The EUA Disclosure Letter sets forth
all capital stock authorized, issued and outstanding at subsidiary levels as of
the close of business on January 29, 1999.
(b) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the
outstanding shares of capital stock of each Subsidiary of EUA are duly
authorized, validly issued, fully paid and nonassessable and are owned,
beneficially and of record, by EUA or a Subsidiary, which is wholly owned,
directly or indirectly, by EUA, free and clear of any liens, claims, mortgages,
encumbrances, pledges, security interests, equities and charges of any kind
(each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date
of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i)
outstanding Options obligating EUA or any of its Subsidiaries to issue or sell
any shares of capital stock of any Subsidiary of EUA or to grant, extend or
enter into any such Option or (ii) voting trusts, proxies or other commitments,
understandings, restrictions or arrangements in favor of any person other than
EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with
respect to the voting of, or the right to participate in, dividends or other
earnings on any capital stock of any Subsidiary of EUA.
(c) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are
no outstanding contractual obligations of EUA or any Subsidiary of EUA to
repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of
any Subsidiary of EUA or to provide funds to, or make any investment (in the
form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or
any other person.
(d) As of the date of this Agreement, no bonds, debentures,
notes or other indebtedness of EUA or any Subsidiary of EUA having the right to
vote (or which are convertible into or exercisable for securities having the
right to vote) (together "EUA Voting Debt") on any matters on which Shareholders
may vote are issued or outstanding nor are there any outstanding Options
obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt
or to grant, extend or enter into any Option with respect thereto.
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4.03 Authority. EUA has full power and authority to enter into this
Agreement, to perform its obligations hereunder and, subject to obtaining EUA
Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required
Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger
and other transactions contemplated hereby. The execution, delivery and
performance of this Agreement by EUA and the consummation by EUA of the Merger
and other transactions contemplated hereby have been duly authorized by all
necessary action on the part of EUA, subject to obtaining EUA Shareholders'
Approval with respect to the consummation of the Merger and the other
transactions contemplated hereby. This Agreement has been duly and validly
executed and delivered by EUA and constitutes a legal, valid and binding
obligation of EUA enforceable against EUA in accordance with its terms, except
as enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
4.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by EUA do not, and the performance by EUA of its
obligations hereunder and the consummation of the Merger and other transactions
contemplated hereby will not, conflict with, result in a violation or breach of,
constitute (with or without notice or lapse of time or both) a default under,
result in or give to any person any right of payment or reimbursement,
termination, cancellation, modification or acceleration of, or result in the
creation or imposition of any Lien upon any of the assets or properties of EUA
or any of its Subsidiaries or any of the terms, conditions or provisions of (i)
the EUA Trust Agreement or the certificates or articles of incorporation or
organization or bylaws (or other comparable charter documents) of EUA's
Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval,
EUA Required Consents, EUA Required Statutory Approvals and the taking of any
other actions described in this Section 4.04, (x) any statute, law, rule,
regulation or ordinance (together, "laws"), or any judgment, decree, order,
writ, permit or license (together, "orders"), of any court, tribunal,
arbitrator, authority, agency, commission, official or other instrumentality of
the United States, any foreign country or any domestic or foreign state, county,
city or other political subdivision (a "Governmental Authority") applicable to
EUA or any of its Subsidiaries or any of their respective assets or properties,
or (y) subject to obtaining the third-party consents set forth in Section 4.04
of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond,
mortgage, security agreement, indenture, license, franchise, permit, concession,
contract, lease or other instrument, obligation or agreement of any kind
(together, "Contracts") to which EUA or any of its Subsidiaries is a party or by
which EUA or any of its Subsidiaries or any of their respective assets or
properties is bound, excluding from the foregoing clauses (x) and (y) such
conflicts, violations, breaches, defaults, payments or reimbursements,
terminations, cancellations, modifications, accelerations and creations and
impositions of Liens which, individually or in the aggregate, could not
reasonably be expected to have an EUA Material Adverse Effect.
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(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by EUA or the consummation by
EUA of the Merger and other transactions contemplated hereby except as described
in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain
could not reasonably be expected to result in an EUA Material Adverse Effect
(the "EUA Required Statutory Approvals," it being understood that references in
this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean
making such declarations, filings or registrations; giving such notices;
obtaining such authorizations, consents or approvals; and having such waiting
periods expire as are necessary to avoid a violation of law).
4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA
delivered to NEES prior to the execution of this Agreement a true and complete
copy of each form, report, schedule, registration statement, registration
exemption, if applicable, definitive proxy statement and other document
(together with all amendments thereof and supplements thereto) filed by EUA or
any of its Subsidiaries with the Securities and Exchange Commission (the "SEC")
under the Securities Act of 1933, as amended, and the rules and regulations
thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as
amended, and the rules and regulations thereunder (the "Exchange Act") since
December 31, 1995 (as such documents have since the time of their filing been
amended or supplemented, the "EUA SEC Reports"), which are all the documents
(other than preliminary materials) that EUA and its Subsidiaries were required
to file with the SEC under the Securities Act and the Exchange Act since such
date. As of their respective dates, EUA SEC Reports (i) complied as to form in
all material respects with the requirements of the Securities Act or the
Exchange Act, as the case may be, and (ii) did not contain any untrue statement
of a material fact or omit to state a material fact required to be stated
therein or necessary in order to make the statements therein, in light of the
circumstances under which they were made, not misleading. Each of the audited
consolidated financial statements and unaudited interim consolidated financial
statements (including, in each case, the notes, if any, thereto) included in EUA
SEC Reports (the "EUA Financial Statements") complied as to form in all material
respects with the published rules and regulations of the SEC with respect
thereto, were prepared in accordance with U.S. generally accepted accounting
principles ("US GAAP") applied on a consistent basis during the periods involved
(except as may be indicated therein or in the notes thereto and except with
respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly
present (subject, in the case of the unaudited interim financial statements, to
normal, recurring year-end audit adjustments (which are not expected to be,
individually or in the aggregate, materially adverse to EUA and its Subsidiaries
taken as a whole)) the consolidated financial position of EUA and its
consolidated subsidiaries as at the respective dates thereof and the
consolidated results of their operations and cash flows for the respective
periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure
Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in
EUA Financial Statements for all periods covered thereby.
(b) All filings (other than immaterial filings) required to be
made by EUA or any of its Subsidiaries since December 31, 1995, under the Public
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Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the
Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state
laws and regulations, have been filed with the SEC, the Federal Energy
Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the
Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission
(the "FCC") or any appropriate state public utility commissions (including,
without limitation, to the extent required, the state public utility regulatory
agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and
Connecticut as the case may be, including all forms, statements, reports,
agreements (oral or written) and all documents, exhibits, amendments and
supplements appertaining thereto, including but not limited to all rates,
tariffs, franchises, service agreements and related documents and all such
filings complied, as of their respective dates, in all material respects with
all applicable requirements of the appropriate statutes and the rules and
regulations thereunder.
4.06 Absence of Certain Changes or Events. Except as set forth in
Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports
filed prior to the date of this Agreement since December 31, 1997, EUA and each
of EUA's Subsidiaries have conducted its business only in the ordinary course of
business consistent with past practice and there has not been, and no fact or
condition exists which, individually or in the aggregate, has or could
reasonably be expected to have an EUA Material Adverse Effect.
4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed
prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure
Letter and except for environmental matters which are governed by Section 4.13,
(i) there are no actions, claims, hearings, suits, arbitrations or proceedings
pending or, to the knowledge of EUA or any of its Subsidiaries, threatened
against, specifically relating to or affecting, and, to the knowledge of EUA or
any of its Subsidiaries, there are no Governmental Authority investigations or
audits pending or threatened against, specifically relating to or affecting, EUA
or any of its Subsidiaries or any of their respective assets and properties
which, individually or in the aggregate, could reasonably be expected to have an
EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is
subject to any order of any Governmental Authority which, individually or in the
aggregate, could reasonably be expected to have an EUA Material Adverse Effect.
4.08 Information Supplied. (a) The proxy statement relating to EUA
Shareholders' Meeting, as amended or supplemented from time to time (as so
amended and supplemented, the "Proxy Statement"), and any other documents to be
filed by EUA with the SEC (including, without limitation, under the 1935 Act) or
any other Governmental Authority in connection with the Merger and other
transactions contemplated hereby will comply as to form in all material respects
with the requirements of the Exchange Act, the Securities Act and the 1935 Act,
as applicable, and will not, on the date of their respective filings or, in the
case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and
at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain
any untrue statement of a material fact or omit to state any material fact
necessary in order to make the statements therein, in light of the circumstances
under which they are made, not misleading.
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(b) Notwithstanding the foregoing provisions of this Section
4.08, no representation or warranty is made by EUA with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by NEES or LLC for inclusion or incorporation by reference therein.
4.09 Compliance. Except as set forth in Section 4.09 of the EUA
Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date
hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the
knowledge of EUA, under investigation with respect to any violation of, or has
been given notice or been charged with any violation of, any law, statute,
order, rule, regulation, ordinance or judgment (including, without limitation,
any applicable environmental law, ordinance or regulation) of any Governmental
Authority, except for possible violations which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as
disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's
Subsidiaries have all permits, licenses, franchises and other governmental
authorizations, consents and approvals necessary to conduct their businesses as
presently conducted except for such failures which could not reasonably be
expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's
Subsidiaries is in breach or violation of, or in default in the performance or
observance of any term or provision of, (i) the EUA Trust Agreement, in the case
of EUA, or articles of incorporation or organization or by-laws, in the case of
EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture,
mortgage, loan agreement, note, lease, bond, license, approval or other
instrument to which it is a party or by which EUA or any Subsidiary of EUA is
bound or to which any of their respective property is subject, except for
possible violations, breaches or defaults which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure
Letter:
(a) Filing of Timely Tax Returns. EUA and each of its
Subsidiaries have timely filed all Tax Returns required to be filed by each of
them under applicable law. All Tax Returns were (and, as to Tax Returns not
filed as of the date hereof, will be) true, complete and correct;
(b) Payment of Taxes. EUA and each of its Subsidiaries have,
within the time and in the manner prescribed by law, paid (and until the Closing
Date will pay within the time and in the manner prescribed by law) all Taxes
that are currently due and payable except for those contested in good faith and
for which adequate reserves have been taken;
(c) Tax Reserves. EUA and its Subsidiaries have established (and
until the Closing Date will maintain) on their books and records adequate
reserves for all Taxes and for any liability for deferred income taxes in
accordance with GAAP;
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(d) Extensions of Time for Filing Tax Returns. Neither EUA nor
any of its Subsidiaries has requested any extension of time within which to file
any Tax Return, which Tax Return has not since been filed;
(e) Waivers of Statute of Limitations. Neither EUA nor any of
its Subsidiaries has in effect any extension, outstanding waivers or comparable
consents regarding the application of the statute of limitations with respect to
any Taxes or Tax Returns;
(f) Expiration of Statute of Limitations. The Tax Returns of
EUA, each of its Subsidiaries and any affiliated, consolidated, combined or
unitary group that includes EUA or any of its Subsidiaries either have been
examined and settled with the appropriate Tax authority or closed by virtue of
the expiration of the applicable statute of limitations for all years through
and including 1993;
(g) Audit, Administrative and Court Proceedings. No audits or
other administrative proceedings or court proceedings are presently pending or
threatened with regard to any Taxes or Tax Returns of EUA or any of its
Subsidiaries (other than those being contested in good faith and for which
adequate reserves have been established) and no issues have been raised in
writing by any Tax authority in connection with any Tax or Tax Return;
(h) Tax Liens. There are no Tax liens upon any asset of EUA or
any of its Subsidiaries except liens for Taxes not yet due.
(i) Powers of Attorney. No power of attorney currently in force
has been granted by EUA or any of its Subsidiaries concerning any Tax matter;
(j) Tax Rulings. Neither EUA nor any of its Subsidiaries has,
during the five year period prior to the date of this Agreement, received a Tax
Ruling (as defined below) or entered into a Closing Agreement (as defined below)
with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a
written ruling of a taxing authority relating to Taxes. "Closing Agreement", as
used in this Agreement, shall mean a written and legally binding agreement with
a taxing authority relating to Taxes;
(k) Availability of Tax Returns. EUA and its Subsidiaries have
made available to NEES complete and accurate copies, covering all years ending
on or after December 31, 1993, of (i) all Tax Returns, and any amendments
thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports
received from any taxing authority relating to any Tax Return filed by EUA or
any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or
any of its Subsidiaries with any taxing authority.
(l) Tax Sharing Agreements. No agreements relating to the
allocation or sharing of Taxes exist between or among EUA and any of its
Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member
of an affiliated group filing a consolidated federal income tax return (other
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than a group the common parent of which was EUA) or (ii) has any liability for
Taxes of any Person (other than EUA or its Subsidiaries) under United States
Treasury Regulation Section 1.1502-6 (or any provision of state, local), or
foreign law, as a transferee or successor, by contract or otherwise;
(m) Code Section 481 Adjustments. Neither EUA nor any of its
Subsidiaries is required to include in income any adjustment pursuant to Code
Section 481(a) by reason of a voluntary change in accounting method initiated by
EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has
not proposed any such adjustment or change in accounting method;
(n) Code Sections 6661 and 6662. All transactions that could
give rise to an understatement of federal income tax, and within the meaning of
Code Section 6662 have been adequately disclosed (or, with respect to Tax
Returns filed following the Closing, will be adequately disclosed) on the Tax
Returns of EUA and its Subsidiaries in accordance with Code Section
6662(d)(2)(B);
(o) Intercompany Transactions. Neither EUA nor any of its
Subsidiaries has engaged in any intercompany transactions within the meaning of
Treasury Regulations ss. 1.1502-13 for which any income or gain will remain
unrecognized as of the close of the last taxable year prior to the Closing Date;
and
(p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries
is required to file a foreign tax return.
"Taxes" as used in this Agreement, shall mean any federal, state,
county, local or foreign taxes, charges, fees, levies, or other assessments,
including all net income, gross income, premiums, sales and use, ad valorem,
transfer, gains, profits, windfall profits, excise, franchise, real and personal
property, gross receipts, capital stock, production, business and occupation,
employment, disability, payroll, license, estimated, stamp, custom duties,
severance or withholding taxes, other taxes or similar charges of any kind
whatsoever imposed by any governmental entity, whether imposed directly on a
Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar
provision of state, local or foreign law), as a transferee or successor, by
contract or otherwise and includes any interest and penalties on or additions to
any such taxes or in respect of a failure to comply with any requirement
relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a
report, return or other information required to be supplied to a governmental
entity with respect to Taxes including, where permitted or required, combined,
unitary or consolidated returns for any group of entities.
4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan"
(as defined in Section 3(3) of the Employee Retirement Income Security Act of
1974, as amended ("ERISA")), bonus, deferred compensation, share option or other
written agreement relating to employment or fringe benefits for employees,
former employees, officers, trustees or directors of EUA or any of its
Subsidiaries effective as of the date hereof or providing benefits as of the
date hereof to current employees, former employees, officers, trustees or
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directors of EUA or pursuant to which EUA or any of its subsidiaries has or
could reasonably be expected to have any liability (collectively, the "EUA
Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure
Letter, is in material compliance with applicable law, and has been administered
and operated in all material respects in accordance with its terms. Each EUA
Employee Benefit Plan which is intended to be qualified within the meaning of
Section 401(a) of the Code has received a favorable determination letter from
the IRS as to such qualification and, to the knowledge of EUA, no event has
occurred and no condition exists which could reasonably be expected to result in
the revocation of, or have any adverse effect on, any such determination.
(b) Complete and correct copies of the following documents have
been made available to NEES as of the date of this Agreement: (i) all EUA
Employee Benefit Plans and any related trust agreements or insurance contracts,
(ii) the most current summary descriptions of each EUA Employee Benefit Plan
subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto
for each EUA Employee Benefit Plan subject to such reporting, (iv) the most
recent determination of the IRS with respect to the qualified status of each EUA
Employee Benefit Plan that is intended to qualify under Section 401(a) of the
Code, (v) the most recent accountings with respect to each EUA Employee Benefit
Plan funded through a trust and (vi) the most recent actuarial report of the
qualified actuary of each EUA Employee Benefit Plan with respect to which
actuarial valuations are conducted.
(c) Except as set forth in Section 4.11(c) of the EUA Disclosure
Letter, neither EUA nor any Subsidiary maintains or is obligated to provide
benefits under any EUA Employee Benefit Plan (other than as an incidental
benefit under a Plan qualified under Section 401(a) of the Code) which provides
health or welfare benefits to retirees or other terminated employees other than
benefit continuations as required pursuant to Section 601 of ERISA. Each EUA
Employee Benefit Plan subject to the requirements of Section 601 of ERISA has
been operated in material compliance therewith. EUA has not contributed to a
nonconforming group health plan (as defined in Code Section 5000(c)) and no
person under common control with EUA within the meaning of Section 414 of the
Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a)
that is or could reasonably be expected to be a liability of EUA's.
(d) Except as set forth in Section 4.11(d) of the EUA Disclosure
Letter, each EUA Employee Benefit Plan covers only employees who are employed by
EUA or a Subsidiary (or former employees or beneficiaries with respect to
service with EUA or a Subsidiary).
(e) Except as set forth in Section 4.11(e) of the EUA Disclosure
Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other
corporation or organization controlled by or under common control with any of
the foregoing within the meaning of Section 4001 of ERISA has, within the
five-year period preceding the date of this Agreement, at any time contributed
to any "multiemployer plan," as that term is defined in Section 4001 of ERISA.
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(f) No event has occurred, and there exists no condition or set
of circumstances in connection with any EUA Employee Benefit Plan, under which
EUA or any Subsidiary, directly or indirectly (through any indemnification
agreement or otherwise), could be subject to any liability under Section 409 of
ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code
except for instances of non-compliance which, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect.
(g) Neither EUA nor any ERISA Affiliate has incurred any
liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section
302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been
satisfied in full and no event or condition exists or has existed which could
reasonably be expected to result in any such material liability. As of the date
of this Agreement, no "reportable event" within the meaning of Section 4043 of
ERISA has occurred with respect to any EUA Employee Benefit Plan that is a
defined benefit plan under Section 3(35) of ERISA.
(h) Except as set forth in Section 4.11(h) of the EUA Disclosure
Letter, no employer securities, employer real property or other employer
property is included in the assets of any EUA Employee Benefit Plan.
(i) Full payment has been made of all material amounts which EUA
or any affiliate thereof was required under the terms of EUA Employee Benefit
Plans to have paid as contributions to such plans on or prior to the Effective
Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which
is subject to Part III of Subtitle B of Title I of ERISA has incurred any
"accumulated funding deficiency" within the meaning of Section 302 of ERISA or
Section 412 of the Code, whether or not waived.
(j) Except as set forth in Section 4.11(j) of the EUA Disclosure
Letter, no amounts payable under any EUA Employee Benefit Plan or other
agreement, contract, or arrangement will fail to be deductible for federal
income tax purposes by virtue of Section 280G or Section 162(m) of the Code.
4.12 Labor Matters. As of the date hereof, except as set forth in
Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries is a party to any material collective bargaining agreement or other
labor agreement with any union or labor organization. To the knowledge of EUA,
as of the date hereof, there is no current union representation question
involving employees of EUA or any of its Subsidiaries, nor does EUA know of any
activity or proceeding of any labor organization (or representative thereof) or
employee group to organize any such employees. Except as set forth in Section
4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice,
employment discrimination or other employment-related complaint or proceeding
against EUA or any of its Subsidiaries pending or, to the knowledge of EUA,
threatened, which has or could reasonably be expected to have an EUA Material
Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or
lockout pending, or, to the knowledge of EUA, threatened, against or involving
EUA or any of its Subsidiaries which has or could reasonably be expected to
have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim,
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suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries,
threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any
Governmental Authority investigation pending or threatened, in respect of which
any trustee, director, officer, employee or agent of EUA or any of its
Subsidiaries is or may be entitled to claim indemnification from EUA or any of
its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and
their respective articles of incorporation and by-laws, in the case of EUA's
Subsidiaries, or as provided in the indemnification agreements listed in Section
4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the
EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all
federal, state and local laws with respect to employment practices and labor
relations, including, without limitation, any provisions relating to affirmative
action, employment discrimination, wages, hours, collective bargaining, and the
payment of social security and similar taxes, safety and health regulations and
mass layoffs and plant closings except for such instances of noncompliance
which, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect.
4.13 Environmental Matters. Except as disclosed in EUA SEC Reports
filed prior to the date of this Agreement or in Section 4.13 of the EUA
Disclosure Letter:
(a) (i) Each of EUA and its Subsidiaries is in compliance with
all applicable Environmental Laws (as hereinafter defined), except where the
failure to be in compliance, in the aggregate could not reasonably be expected
to result in an EUA Material Adverse Effect; and
(ii) Neither EUA nor any of its Subsidiaries has received
any written communication from any person or Governmental Authority that alleges
that EUA or any of its Subsidiaries is not in such compliance (including the
materiality qualifier set forth in clause (i) above) with applicable
Environmental Laws.
(b) Each of EUA and its Subsidiaries has obtained all
environmental, health and safety permits and governmental authorizations
(collectively, the "Environmental Permits") necessary for the construction of
their facilities and the conduct of their operations, as applicable, and all
such Environmental Permits are in good standing or, where applicable, a renewal
application has been timely filed and agency approval is expected in the
ordinary course of business, and EUA and its Subsidiaries are in compliance with
all terms and conditions of the Environmental Permits, except where the failure
have such Environmental Permits, file a renewal application for such
Environmental Permits, or to be in compliance with such Environmental Permits,
in the aggregate could not reasonably be expected to result in an EUA Material
Adverse Effect.
(c) There is no Environmental Claim (as hereinafter defined)
that could, individually or in the aggregate, reasonably be expected to have an
EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries;
(ii) against any person or entity whose liability for any Environmental Claim
EUA or any of its Subsidiaries has or may have retained or assumed either
contractually or by operation of law; or (iii) against any real or personal
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property or operations which EUA or any of its Subsidiaries owns, leases or
manages, in whole or in part.
(d) To the knowledge of EUA there have not been any material
Releases (as hereinafter defined) of any Hazardous Material (as hereinafter
defined) that would be reasonably likely to form the basis of any material
Environmental Claim against EUA or any of its Subsidiaries, or against any
person or entity whose liability for any material Environmental Claim EUA or any
of its Subsidiaries has or may have retained or assumed either contractually or
by operation of law, except for any Environmental Claim that, individually or in
the aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
(e) To the knowledge of EUA with respect to any predecessor of
EUA or any of its Subsidiaries, there is no material Environmental Claim pending
or threatened, and there has been no Release of Hazardous Materials that could
reasonably be expected to form the basis of any material Environmental Claim
except for any Environmental Claim that, individually or in the aggregate, could
not be reasonably be expected to have an EUA Material Adverse Effect.
(f) As used in this Section 4.13:
(i) "Environmental Claim" means any and all written
administrative, regulatory or judicial actions, suits, demands, demand letters,
directives, claims, liens, investigations, proceedings or notices or
noncompliance, liability or violation by any person or entity (including any
Governmental Authority) alleging potential liability (including, without
limitation, potential responsibility or liability for enforcement, investigatory
costs, cleanup costs, governmental response costs, removal costs, remedial
costs, natural resources damages, property damages, personal injuries or
penalties) arising out of, based on or resulting from
(A) the presence, or Release or threatened Release into the
environment, of any Hazardous Materials at any
location, whether or not owned, operated, leased or
managed by EUA or any of its Subsidiaries; or
(B) circumstances forming the basis of any violation, or
alleged violation, of any Environmental Law; or
(C) any and all claims by any third party seeking damages,
contribution, indemnification, cost recovery,
compensation or injunctive relief resulting from the
presence or Release of any Hazardous Materials;
(ii) "Environmental Laws" means all federal, state and local
laws, rules and regulations and binding interpretation thereof, relating to
pollution, the environment (including, without limitation, ambient air, surface
water, groundwater, land surface or subsurface strata) or protection of human
health as it relates to the environment including, without limitation, laws and
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regulations relating to Releases or threatened Releases of Hazardous
Materials, or otherwise relating to the manufacture, generation, processing,
distribution, use, treatment, storage, disposal, transport or handling of
Hazardous Materials;
(iii) "Hazardous Materials" means (A) any petroleum or
petroleum products, radioactive materials, asbestos in any form that is or could
become friable, urea formaldehyde foam insulation, and transformers or other
equipment that contain dielectric fluid containing polychlorinated biphenyls;
and (B) any chemicals, materials or substances which are now defined as or
included in the definition of "hazardous substances", "hazardous wastes",
"hazardous materials", "extremely hazardous wastes", "restricted hazardous
wastes", "toxic substances", "toxic pollutants", or words of similar import,
under any Environmental Law; and (c) any other chemical, material, substance or
waste, exposure to which is now prohibited, limited or regulated under any
Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x)
operates or (y) stores, treats or disposes of Hazardous Materials; and
(iv) "Release" means any release, spill, emission, leaking,
injection, deposit, disposal, discharge, dispersal, leaching or migration into
the atmosphere, soil, surface water, groundwater or property.
4.14 Regulation as a Utility. (a) EUA is a public utility holding
company registered under Section 5, and subject to the provisions, of the 1935
Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA
that are "public utility companies" within the meaning of Section 2(a)(5) of the
1935 Act and lists the jurisdictions where each such Subsidiary is subject to
regulation as a public utility company or public service company. Except as set
forth above and as set forth in Section 4.14 of the EUA Disclosure Letter,
neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to
regulation as a public utility or public service company (or similar
designation) by the federal government of the United States, any state in the
United States or any political subdivision thereof, or any foreign country.
(b) As used in this Section 4.14, the terms "subsidiary company"
and "affiliate" shall have the respective meanings ascribed to them in Section
2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act.
4.15 Insurance. Except as set forth in Section 4.15 of the EUA
Disclosure Letter, each of EUA and its Subsidiaries is, and has been
continuously since January 1, 1994, insured with financially responsible
insurers in such amounts and against such risks and losses as are customary in
all material respects for companies in the United States conducting the business
conducted by EUA and its Subsidiaries during such time period. Except as set
forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries has received any notice of cancellation or termination with respect
to any material insurance policy of EUA or any of its Subsidiaries. The
insurance policies of EUA and each of its Subsidiaries are valid and enforceable
policies.
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4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of
EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power
Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a
minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described
in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities").
With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric
Company holds the required operating licenses from the NRC. With respect to the
Yankee Companies, each Yankee Company holds its own operating license from the
NRC. Because it is a minority stockholder or a minority joint owner, Montaup
Electric Company does not have responsibility for the operation of EUA Nuclear
Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or
as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge
of EUA, neither EUA nor any of its Subsidiaries is in violation of any
applicable health, safety, regulatory and other legal requirement, including NRC
laws and regulations and Environmental Laws, applicable to EUA Nuclear
Facilities except for such failure to comply as could not reasonably be expected
to have a material adverse effect with respect to EUA Nuclear Facilities and the
ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear
Facilities maintains emergency plans designed to respond to an unplanned release
therefrom of radioactive materials into the environment and insurance coverages
consistent with industry practice. EUA has funded, or has caused the funding of,
its portion of the decommissioning cost of each of the EUA Nuclear Facilities
and the storage of spent nuclear fuel consistent with the most recently approved
plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as
set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA,
no EUA Nuclear Facility is as of the date of this Agreement on the List of
Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the
NRC.
4.17 Vote Required. The affirmative vote of two-thirds of the
outstanding EUA Shares voting as a single class (with each EUA Share having one
vote per share) with respect to the approval of the Merger and other
transactions contemplated hereby is the only vote of the holders of any class or
series of equity securities of EUA or its Subsidiaries required to approve this
Agreement and approve the Merger and other transactions contemplated hereby.
4.18 Opinion of Financial Advisor. EUA has received the opinion of
Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that,
as of such date, the Merger Consideration is fair from a financial point of view
to the holders of EUA Shares. A true and complete copy of the written opinion
will be delivered to NEES promptly after receipt thereof by EUA.
4.19 Ownership of NEES Common Shares. Neither EUA nor any of its
Subsidiaries or other affiliates beneficially owns any NEES Common Shares.
4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions
so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply
to this Agreement, the Merger or other transactions contemplated hereby or
thereby.
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4.21 Year 2000. The Information Systems operated by EUA and its
Subsidiaries which is used in the conduct of their business is capable of
providing or being adapted to provide uninterrupted millennium functionality to
record, store, process and present calendar dates falling on or after January 1,
2000 in substantially the same manner and with the same functionality as such
Information Systems record, store, process and present such calendar dates
falling on or before December 31, 1999 other than such interruptions in
millennium functionality that could not, individually or in the aggregate,
reasonably be expected to result in a EUA Material Adverse Effect. EUA
reasonably believes as of the date hereof that the remaining cost of adaptations
referred to in the foregoing sentence will not exceed the amounts reflected in
the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding
the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o)
hereof and of the implementation of any recommendations by such Y2K Consultant
actually made by EUA that are not already part of EUA's compliance plan as of
the date hereof). "Information Systems" means mainframe and midrange hardware,
operating system software and applications programs; network and desktop (PC)
hardware, operating system software and applications programs; EDI (Electronic
Date Interchange) and FTP (File Transfer Protocol) software; and embedded
systems hardware and applications software.
4.22 EUA Associates. The representations and warranties set forth in
Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all
material respects with regard to EUA Associates.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES
NEES represents and warrants to EUA as follows:
5.01 Organization and Qualification. NEES is a voluntary association
duly organized, validly existing and in good standing under the laws of the
Commonwealth of Massachusetts and has full power, authority and legal right to
own its property and assets and to transact the business in which it is engaged.
Each of the NEES Subsidiaries is a corporation duly organized or incorporated,
validly existing and in good standing under the laws of its jurisdiction of
organization or incorporation and has full corporate power and authority to
conduct its business as and to the extent now conducted and to own, use and
lease its assets and properties, except where failure to be so organized or
incorporated, existing and in good standing or to have such power and authority,
individually or in the aggregate, could not reasonably be expected to have a
NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material
Adverse Effect" means a material adverse effect on the business, assets, results
of operations, condition (financial or otherwise) or prospects of NEES and its
Subsidiaries taken as a whole. LLC is a limited liability company validly
existing under the laws of the Commonwealth of Massachusetts. LLC was formed
solely for the purpose of engaging in the Merger and other transactions
contemplated hereby, has engaged in no other business activities (other than in
connection with the formation and capitalization of LLC pursuant to or in
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accordance with the LLC Agreement (as defined below)) and has conducted its
operations only as contemplated hereby and by the LLC Agreement. Each of NEES
and its Subsidiaries is duly qualified, licensed or admitted to do business and
is in good standing in each jurisdiction in which the ownership, use or leasing
of its assets and properties, or the conduct or nature of its business, makes
such qualification, licensing or admission necessary, except where failure to be
so qualified, licensed or admitted and in good standing, individually or in the
aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect. NEES has previously delivered to EUA correct and complete copies of its
Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles
of association of LLC.
5.02 Authority. Each of NEES and LLC has full power and authority to
enter into this Agreement, and to perform its obligations hereunder, and to
consummate the Merger and other transactions contemplated hereby. The execution,
delivery and performance of this Agreement by each of NEES and LLC and the
consummation by each of NEES and LLC of the Merger and other transactions
contemplated hereby have been duly authorized by all necessary corporate action
on the part of NEES and all necessary action on the part of LLC. This Agreement
has been duly and validly executed and delivered by each of NEES and LLC and
constitutes a legal, valid and binding obligation of each of NEES and LLC
enforceable against each of NEES and LLC in accordance with its terms, except as
enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
5.03 Capital Stock. The authorized equity securities of NEES consists
of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986
shares were issued and outstanding as of the close of business on January 29,
1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares
were held in the treasury of NEES. All of the issued and outstanding NEES Shares
are duly authorized, validly issued, fully paid and nonassessable. Except as may
be provided by the New England Electric System Companies' Incentive Share Plan,
the New England Electric System Companies Incentive Thrift Plan I, the New
England Electric System Companies Incentive Thrift Plan II, the New England
Electric Companies Long-Term Performance Share Award Plan, and the New England
Electric System Directors' annual retainer shares, and except as set forth in
Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES
and LLC concurrently with the execution and delivery of this Agreement (the
"NEES Disclosure Letter"), on the date hereof there are no outstanding Options
obligating NEES or any of its Subsidiaries to issue or sell any shares of equity
securities of NEES or to grant, extend or enter into any Option with respect
thereto.
5.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by each of NEES and LLC do not, and the performance
by each of NEES and LLC of its obligations hereunder and the consummation of the
Merger and other transactions contemplated hereby will not, conflict with,
result in a violation or breach of, constitute (with or without notice or lapse
of time or both) a default under, result in or give to any person any right of
payment or reimbursement, termination, cancellation, modification or
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acceleration of, or result in the creation or imposition of any Lien upon any of
the assets or properties of NEES, or LLC under, any of the terms, conditions or
provisions of (i) the NEES Agreement and Declaration of Trust or the articles of
organization of LLC, (ii) subject to the actions described in paragraph (b) of
this Section, (x) any laws or orders of any Governmental Authority applicable to
NEES or LLC or any of their respective assets or properties, or (y) subject to
obtaining the third-party consents (the "NEES Required Consents") set forth in
Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a
party or by which NEES or any of its Subsidiaries or any of their respective
assets or properties is bound, excluding from the foregoing clauses (x) and (y)
conflicts, violations, breaches, defaults, terminations, modifications,
accelerations and creations and impositions of Liens which, individually or in
the aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect.
(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by NEES or LLC or the
consummation by NEES or LLC of the Merger and other transactions contemplated
hereby except as described in Section 5.04 of the NEES Disclosure Letter or the
failure of which to obtain could not reasonably be expected to result in a NEES
Material Adverse Effect (the "NEES Required Statutory Approvals," it being
understood that references in this Agreement to "obtaining" such NEES Required
Statutory Approvals shall mean making such declarations, filings or
registrations; giving such notices; obtaining such authorizations, consents or
approvals; and having such waiting periods expire as are necessary to avoid a
violation of law).
5.05 Information Supplied. (a) The information supplied by NEES or LLC
and included in the Proxy Statement with the written consent of NEES or LLC, as
the case may be, will not, at the date mailed to EUA's Shareholders or at the
time of EUA Shareholder's Meeting, contain any untrue statements of a material
fact or omit to state any material fact required to be stated therein or
necessary in order to make the statements therein, in light of the circumstances
under which they were made, not misleading.
(b) Notwithstanding the foregoing provisions of this Section
5.05, no representation or warranty is made by NEES with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by EUA for inclusion or incorporation by reference therein or based on
information which is not made in or incorporated by reference in such documents
but which should have been disclosed pursuant to this Section 5.05.
5.06 Compliance. Except as set forth in Section 5.06 of the NEES
Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date
hereof, NEES is not in violation of, is, to the knowledge of NEES, under
investigation with respect to any violation of, or has been given notice or been
charged with any violation of, any law, statute, order, rule, regulation,
ordinance or judgment (including, without limitation, any applicable
environmental law, ordinance or regulation) of any Governmental Authority,
except for possible violations which, individually or in the aggregate, could
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not reasonably be expected to have a NEES Material Adverse Effect. Except as set
forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES
Reports filed prior to the date hereof, NEES and its Subsidiaries have all
material permits, licenses and other governmental authorizations, consents and
approvals necessary to conduct their businesses as presently conducted which are
material to the operation of the businesses of NEES. NEES is not in breach or
violation of, or in default in the performance or observance of, any term or
provision of, and no event has occurred which, with lapse of time or action by a
third party, could result in a default by NEES under (i) the NEES Agreement and
Declaration of Trust or by-laws or (ii) any contract, commitment, agreement,
indenture, mortgage, loan agreement, note, lease, bond, license, approval or
other instrument to which it is a party or by which NEES is bound or to which
any of their respective property is subject, except for possible violations,
breaches or defaults which, individually or in the aggregate, could not
reasonably be expected to have a NEES Material Adverse Effect.
5.07 Financing. NEES has or will have available, prior to the
Effective Time, sufficient cash in immediately available funds to pay or to
cause LLC to pay the Merger Consideration pursuant to Article II hereof and to
consummate the Merger and other transactions contemplated hereby.
5.08 No Vote Required. No vote of the NEES Shares or of any class or
series of equity securities of NEES or its Subsidiaries is necessary for the
approval of the Merger and other transactions contemplated hereby.
5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries
or other affiliates beneficially owns any EUA Shares.
5.10 Merger with The National Grid Group plc. NEES has entered into an
Agreement and Plan of Merger dated as of December 11, 1998 by and among The
National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly
known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to
Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of
this Agreement to National Grid Group, and National Grid Group has given NEES
its written consent to enter into this Agreement and consummate the Merger on
the terms set forth in this Agreement. Prior to the execution of this Agreement,
NEES has provided EUA with a copy of such written consent.
ARTICLE VI
COVENANTS
6.01 Covenants of EUA. At all times from and after the date hereof
until the Effective Time, EUA covenants and agrees as to itself and its
Subsidiaries that (except as expressly contemplated or permitted by this
Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to
the extent that NEES shall otherwise previously consent in writing):
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(a) Ordinary Course. EUA and each of its Subsidiaries shall
conduct their businesses only in, and EUA and each of its Subsidiaries shall not
take any action except in, the ordinary course consistent with good utility
practice. Without limiting the generality of the foregoing, EUA and its
Subsidiaries shall use all commercially reasonable efforts to preserve intact in
all material respects their present business organizations and reputation, to
maintain in effect all existing permits, to keep available the services of their
key officers and employees, to maintain their assets and properties in good
working order and condition, ordinary wear and tear excepted, to maintain
insurance on their tangible assets and businesses in such amounts and against
such risks and losses as are currently in effect, to preserve their
relationships with customers and suppliers and others having significant
business dealings with them and to comply in all material respects with all laws
and orders of all Governmental Authorities applicable to them.
(b) Charter Documents. EUA shall not, nor shall it permit any of
its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the
case of EUA, and its certificate or articles of incorporation or organization or
bylaws (or other comparable charter documents), in the case of EUA's
Subsidiaries.
(c) Dividends. EUA shall not, nor shall it permit any of its
Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other
distributions in respect of, any of its capital stock or share capital, except:
(A) that EUA may continue the declaration and payment of
regular quarterly dividends on EUA Shares with usual
record and payment dates not, in any fiscal year, in
excess of the dividend for the comparable period in the
prior fiscal year;
(B) that the Subsidiaries of EUA set forth in Section
6.01(c) of the EUA Disclosure Letter may continue the
declaration and payment of dividends on preferred stock
in accordance with the terms of such stock, with the
record and payment dates and in the amounts set forth
in Section 6.01(c) of the EUA Disclosure Letter;
(C) if the Effective Time does not occur between a record
date and payment date of a regular quarterly dividend,
for a special dividend on EUA Shares with respect to
the quarter in which the Effective Time occurs with a
record date on or prior to the date on which the
Effective Time occurs, which does not exceed an amount
equal to the product of (x) the number of days between
the last payment date of a regular quarterly dividend
and the record date of such special dividend,
multiplied by (y) $.0045; and
(D) for dividends and distributions (including liquidating
distributions) by a direct or indirect Subsidiary of
EUA to its parent.
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(ii) split, combine, subdivide, reclassify or take similar action with respect
to any of its capital stock or share capital or issue or authorize or propose
the issuance of any other securities in respect of, in lieu of or in
substitution for shares of its capital stock or comprised in its share capital,
(iii) adopt a plan of complete or partial liquidation or resolutions providing
for or authorizing such liquidation or a dissolution, merger, consolidation,
restructuring, recapitalization or other reorganization or (iv) directly or
indirectly redeem, repurchase or otherwise acquire any shares of its capital
stock or any Option with respect thereto except:
(A) in connection with intercompany purchases of capital
stock or share capital,
(B) for the purpose of funding EUA's dividend reinvestment
and share purchase plan in accordance with past
practice, or
(C) subject to EUA's obligations under the Securities Act
and the Exchange Act, pursuant to EUA's previously
announced share repurchase program provided that the
number of EUA Shares repurchased does not exceed
3,000,000 and the price paid per share does not exceed
95% of the Per Share Amount.
(d) Share Issuances. EUA shall not, nor shall it permit any of
its Subsidiaries to, issue, deliver or sell, or authorize or propose the
issuance, delivery or sale of, any shares of its capital stock or any Option
with respect thereto (other than the issuance by a wholly owned Subsidiary of
its capital stock to its direct or indirect parent corporation, or modify or
amend any right of any holder of outstanding shares of capital stock or Options
with respect thereto).
(e) Acquisitions. EUA shall not, nor shall it permit any of its
Subsidiaries to acquire or agree to acquire (by merging or consolidating with,
or by purchasing a substantial equity interest in or substantial portion of the
assets of, or by any other manner) any business or any corporation, partnership,
association or other business organization or division thereof.
(f) Dispositions. EUA shall not, nor shall it permit any of its
Subsidiaries to sell, lease, securitize, grant any security interest in or
otherwise dispose of or encumber any of its assets or properties, other than
dispositions in the ordinary course of its business consistent with past
practice and having an aggregate value of less than $1,000,000 for each
disposition and $5,000,000 in the aggregate.
(g) Indebtedness. EUA shall not, nor shall it permit any of its
Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed
or guaranteed or otherwise assumed, including, without limitation, the issuance
of debt securities or warrants or rights to acquire debt) or enter into any
"keep well" or other agreement to maintain any financial condition of another
Person or enter into any arrangement having the economic effect of any of the
foregoing other than (i) short-term indebtedness in the ordinary course of
business consistent with past practice (such as the issuance of commercial paper
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or the use of existing credit facilities) in amounts not exceeding the amounts
set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term
indebtedness in connection with the refinancing of existing indebtedness either
at its stated maturity or at a lower cost of funds (calculating such cost on an
aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in
favor of wholly owned Subsidiaries of EUA in connection with the conduct of the
business of such wholly owned Subsidiaries of EUA not aggregating more than
$1,000,000.
(h) Capital Expenditures. Except (i) as required by law or (ii)
as reasonably deemed necessary by EUA after consulting with NEES following a
catastrophic event, such as a major storm, EUA shall not, nor shall it permit
any of its Subsidiaries to make any capital expenditures or commitments during
any fiscal year that is in excess of 110% of (i) the aggregate amount set forth
in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its
Subsidiaries that are public utility companies within the meaning of Section
2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the
EUA Disclosure Letter with respect to each of EUA's other Subsidiaries.
(i) Employee Benefits. EUA shall not, nor shall it permit any of
its Subsidiaries to enter into, adopt, amend (except as may be required by
applicable law) or terminate any EUA Employee Benefit Plan, or other agreement,
arrangement, plan or policy between EUA or one of its Subsidiaries and one or
more of its trustees, directors, officers, employees or former employees, or,
except for normal increases in the ordinary course of business, (a) increase in
any manner the compensation or fringe benefits of any trustee, director or
executive officer, (b) increase in any manner the compensation or fringe
benefits of any employee, (c) pay any benefit not required by any plan or
arrangement in effect as of the date hereof or, (d) cause any trustee, director,
officer, employee or former employee of EUA to accrue or receive additional
benefits, accelerate vesting or accelerate the payment of any benefits under any
EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA,
prior to the Closing Date, shall take all necessary action and make all
necessary amendments to its stock-based plans so that all such plans will be in
a form that allows the plans to function after the Effective Time and after any
merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to
the Closing Date, shall take all necessary actions, in a manner satisfactory to
NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity
nor their affiliates' stock or securities will be required to be held in, or
distributed pursuant to, any EUA Employee Benefit Plan.
(j) Labor Matters. Notwithstanding any other provision of this
Agreement to the contrary, EUA or its Subsidiaries may negotiate successor
collective bargaining agreements to those referenced in Section 4.12 hereof, and
may negotiate other collective bargaining agreements or arrangements as required
by law or for the purpose of implementing the agreements referenced in Section
4.12 hereof. EUA will keep NEES informed as to the status of, and will consult
with NEES as to the strategy for, all negotiations with collective bargaining
representatives. EUA and its Subsidiaries shall act prudently and reasonably and
consistent with their obligation under applicable law in such negotiations.
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(k) Discharge of Liabilities. EUA shall not, nor shall it permit
its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities
or obligations (absolute, accrued, asserted or unasserted, contingent or
otherwise), other than the payment, discharge or satisfaction, in the ordinary
course of business consistent with past practice (which includes the payment of
final and unappealable judgments) or in accordance with their terms, of
liabilities reflected or reserved against in, or contemplated by, the most
recent consolidated financial statements (or the notes thereto) of such party
included in EUA SEC Reports, or incurred in the ordinary course of business
consistent with past practice.
(l) Contracts. EUA shall not, nor shall it permit its
Subsidiaries, except in the ordinary course of business consistent with past
practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to
modify, amend, terminate or fail to use commercially reasonable efforts to renew
any material Contract to which EUA or any of its Subsidiaries is a party or
waive, release or assign any material rights or claims or (ii) to enter into any
new material Contracts except as expressly permitted by Sections 6.01 (f), (g)
or (i) and 7.06 hereof.
(m) Equity Investments. EUA shall not, nor shall it permit its
Subsidiaries or affiliates to, make equity contributions to non-affiliates or to
its non-utility Subsidiaries.
(n) Loans. EUA shall not, nor shall it permit its Subsidiaries
or affiliates to, loan money to non-affiliates or to its non-utility
Subsidiaries.
(o) Year 2000. EUA, within 15 days of the date of this
Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a
detailed assessment of the adequacy and state of completion of its Year 2000
Program, including but not limited to assessment and testing of its customer,
accounting, and operational systems. The Y2K Consultant and scope of work of the
Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be
completed as soon thereafter as practicable. EUA shall have such assessment
updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA
shall allow designated NEES personnel and representatives access to the Y2K
Consultant's personnel, reports and recommendations and access to EUA's
personnel, documents, and information related to the Y2K issue. EUA and the
third party shall meet with such designated NEES personnel and representatives
on a periodic basis (but not less frequently than monthly) to update NEES on
EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section
9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K
Consultant.
(p) Insurance. EUA shall, and shall cause its Subsidiaries to,
maintain with financially responsible insurance companies (or through
self-insurance, consistent with past practice) insurance in such amounts and
against such risks and losses as are customary for companies engaged in their
respective businesses.
(q) 1935 Act. EUA shall not, nor shall it permit any of its
Subsidiaries to, engage in any activities which would cause a change in its
status, or that of its Subsidiaries, under the 1935 Act.
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(r) Regulatory Matters. Subject to applicable law and except for
non-material filings in the ordinary course of business consistent with past
practice, EUA shall consult with NEES prior to implementing any changes in its
or any of its Subsidiaries' rates or charges, standards of service or accounting
or executing any agreement with respect thereto that is otherwise permitted
under this Agreement and shall, and shall cause its Subsidiaries to, deliver to
NEES a copy of each such filing or agreement at least four (4) business days
prior to the filing or execution thereof so that NEES may comment thereon. EUA
shall, and shall cause its Subsidiaries to, make all such filings (i) only in
the ordinary course of business consistent with past practice or (ii) as
required by a Governmental Authority or regulatory agency with appropriate
jurisdiction.
(s) Accounting. EUA shall not, nor shall it permit any of its
Subsidiaries to make any changes in their accounting methods, policies or
procedures, except as required by law, rule, regulation or applicable generally
accepted accounting principles;
(t) Tax Status. Neither EUA nor any of its Subsidiaries shall
(i) make or rescind any material express or deemed election relating to Taxes,
(ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii)
settle or compromise any material claim, action, suit, litigation, proceeding,
arbitration, investigation, audit, or controversy relating to Taxes or (iv)
change in any material respect any of its methods of reporting income,
deductions or accounting for federal income tax purposes from those employed in
the preparation of its federal income Tax Return for the taxable year ending
December 31, 1997, except as may be required by applicable law.
(u) No Breach. EUA shall not, nor shall it permit any of its
Subsidiaries to willfully take or fail to take any action that would or is
reasonably likely to result in (i) a material breach of any provision of this
Agreement or (ii) its representations and warranties set forth in this Agreement
being untrue in any material respect on and as of the Closing Date.
(v) Advice of Changes. EUA shall confer with NEES on a regular
and frequent basis with respect to EUA's business and operations and other
matters relevant to the Merger to the extent permitted by law, and shall
promptly advise NEES, orally and in writing, of any material change or event,
including, without limitation, any complaint, investigation or hearing by any
Governmental Authority (or communication indicating the same may be
contemplated) or the institution or threat of material litigation; provided that
EUA shall not be required to make any disclosure to the extent such disclosure
would constitute a violation of any applicable law or regulation.
(w) Notice and Cure. EUA will notify NEES in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to EUA, that causes or will or may be likely to cause any covenant or agreement
of EUA under this Agreement to be breached or that renders or will render untrue
in any material respect any representation or warranty of EUA contained in this
Agreement. EUA also will notify NEES in writing of, and will use all
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commercially reasonable efforts to cure, before the Closing, any material
violation or breach, as soon as practical after it becomes known to EUA, of any
representation, warranty, covenant or agreement made by EUA. No notice given
pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(x) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, EUA will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to the other's obligations contained in
this Agreement and to consummate and make effective the Merger and other
transactions contemplated by this Agreement, and EUA will not, nor will it
permit any of its Subsidiaries to, take or fail to take any action that could be
reasonably expected to result in the nonfulfillment of any such condition.
(y) Third Party Standstill Agreements. Except as provided in
Section 7.08 hereto, during the period from the date of this Agreement through
the Effective Time, neither EUA nor any of its Subsidiaries shall terminate,
amend, modify or waive any provision of any confidentiality or standstill
agreement to which it is a party. During such period, EUA shall take all steps
necessary to enforce, to the fullest extent permitted under applicable law, the
provisions of any such agreement.
6.02 Covenants of NEES. At all times from and after the date hereof
until the Effective Time, NEES covenants and agrees that (except as expressly
contemplated or permitted by this Agreement or to the extent that EUA shall
otherwise previously consent in writing):
(a) No Breach. NEES shall not, nor shall it permit any of its
Subsidiaries to, except as otherwise expressly provided for in this Agreement,
willfully take or fail to take any action that would or is reasonably likely to
result in (i) a material breach of any of its covenants or agreements contained
in this Agreement or (ii) any of its representations and warranties set forth in
Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this
Agreement being untrue in any material respect on and as of the Closing Date.
(b) Advice of Changes. NEES shall confer with EUA on a regular
and frequent basis with respect to any matter having, or which, insofar as can
be reasonably foreseen, could reasonably be expected to have, a NEES Material
Adverse Effect or materially impair the ability of NEES to consummate the Merger
and other transactions contemplated hereby; provided that NEES shall not be
required to make any disclosure to the extent such disclosure would constitute a
violation of any applicable law or regulation.
(c) Notice and Cure. NEES will notify EUA in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to NEES, that causes or will or may be likely to cause any covenant or agreement
of NEES under this Agreement to be breached or that renders or will render
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untrue in any material respect any representation or warranty of NEES contained
in this Agreement. NEES also will notify EUA in writing of, and will use all
commercially reasonable efforts to cure before the Closing, any material
violation or breach, as soon as practical after it becomes known to such party,
of any representation, warranty, covenant or agreement made by NEES. No notice
given pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(d) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, NEES will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to its obligations contained in this
Agreement and to consummate and make effective the Merger and other transactions
contemplated by this Agreement, and NEES will not, nor will it permit any of its
Subsidiaries to, take or fail to take any action that could be reasonably
expected to result in the nonfulfillment of any such condition.
(e) Conduct of Business of LLC. Prior to the Effective Time,
except as may be required by applicable law and subject to the other provisions
of this Agreement, NEES shall cause LLC to (i) perform its obligations under
this Agreement in accordance with its terms, and (ii) not engage directly or
indirectly in any business or activities of any type or kind and not enter into
any agreements or arrangements with any person, or be subject to or bound by any
obligation or undertaking, which is inconsistent with this Agreement.
(f) Certain Mergers. NEES shall not, and shall not permit any of
its Subsidiaries to, acquire or agree to acquire by merging or consolidating
with, or by purchasing a substantial portion of the assets of or equity in, or
by any other manner, any business or any corporation, partnership, association
or other business organization or division thereof, or otherwise acquire or
agree to acquire any assets if the entering into of a definitive agreement
relating to or the consummation of such acquisition, merger or consolidation
could reasonably be expected to (i) impose any material delay in the obtaining
of, or significantly increase the risk of not obtaining, any authorizations,
consents, orders, declarations or approvals of any Governmental Authority
necessary to consummate the Merger or the expiration or termination of any
applicable waiting period, (ii) significantly increase the risk of any
Governmental Authority entering an order prohibiting the consummation of the
Merger, (iii) significantly increase the risk of not being able to remove any
such order on appeal or otherwise or (iv) materially delay the consummation of
the Merger.
6.03 Additional Covenants by NEES and EUA.
(a) Control of Other Party's Business. Nothing contained in this
Agreement shall give NEES, directly or indirectly, the right to control or
direct EUA's operations prior to the Effective Time. Nothing contained in this
Agreement shall give EUA, directly or indirectly, the right to control or direct
NEES' operations prior to the Effective Time. Prior to the Effective Time, each
of EUA and NEES shall exercise, consistent with the terms and conditions of this
Agreement, complete control and supervision over its respective operations.
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(b) Transition Steering Team. As soon as reasonably practicable
after the date hereof, NEES and EUA shall create a special transition steering
team, with representation from EUA and NEES, that will develop recommendations
concerning the future structure and operations of EUA after the Effective Time,
subject to applicable law. The members of the transition steering team shall be
appointed by the Chief Executive Officers of NEES and EUA. The functions of the
transition steering team shall include (i) to direct the exchange of information
and documents between the parties and their Subsidiaries as contemplated by
Section 7.01 and (ii) the development of regulatory plans and proposals,
corporate organizational and management plans, workforce combination proposals,
and such other matters as they deem appropriate.
ARTICLE VII
ADDITIONAL AGREEMENTS
7.01 Access to Information. EUA shall, and shall cause each of its
Subsidiaries to, and shall use commercially reasonable efforts to cause EUA
Associates to, throughout the period from the date hereof to the Effective Time
to the extent permitted by law, (i) provide NEES and its Representatives with
full access, upon reasonable prior notice and during normal business hours, to
all facilities, operations, officers (including EUA's environmental, health and
safety personnel), employees, agents and accountants of EUA and its Subsidiaries
and Associates and their respective assets, properties, books and records, to
the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal
obligation not to provide access or to the extent that such access would not
constitute a waiver of the attorney client privilege and does not unreasonably
interfere with the business and operations of EUA and its Subsidiaries and
Associates and (ii) furnish promptly to such persons (x) a copy of each report,
statement, schedule and other document filed or received by EUA or any of its
Subsidiaries pursuant to the requirements of federal or state securities laws
and each material report, statement, schedule and other document filed with any
other Governmental Authority, and (y) all other information and data (including,
without limitation, copies of Contracts, EUA Employee Benefit Plans, and other
books and records) concerning the business and operations of EUA and its
Subsidiaries as NEES or any of its Representatives reasonably may request. No
review pursuant to this Section 7.01 or otherwise shall affect any
representation or warranty contained in this Agreement or any condition to the
obligations of the parties hereto. Any such information or material obtained
pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such
term is defined in the letter agreement dated as of December 18, 1998 between
EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms
of the Confidentiality Agreement. NEES may provide information or materials that
it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01
to National Grid Group; the treatment by National Grid Group of such information
or material shall be governed by the terms of the letter agreement dated as of
December 21, 1998 between EUA and National Grid Group.
7.02 Proxy Statement. As soon as reasonably practicable after the
date of this Agreement, EUA shall prepare and file the Proxy Statement with the
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SEC. NEES and EUA shall cooperate with each other in the preparation of the
Proxy Statement and any amendment or supplement thereto, and EUA shall promptly
notify NEES of the receipt of any comments of the SEC with respect to the Proxy
Statement and of any requests by the SEC for any amendment or supplement thereto
or for additional information, and shall promptly provide to NEES copies of all
correspondence between EUA or any of its Representatives and the SEC with
respect to the Proxy Statement (except reports from financial advisors other
than with the consent of such financial advisors). Each of the parties hereto
shall furnish all information concerning itself which is required or customary
for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the
Proxy Statement and have due regard to any comments NEES may make in relation to
the Proxy Statement. EUA shall give NEES and its counsel the opportunity to
review the Proxy Statement and all responses to requests for additional
information by and replies to comments of the SEC before their being filed with,
or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best
efforts, after consultation with the other parties hereto, to respond promptly
to all such comments of and requests by the SEC. After obtaining the consent of
EUA, which consent shall not be unreasonably withheld, NEES may provide
information supplied to NEES by EUA to National Grid Group for inclusion of such
information in the Super Class 1 circular ("NGG Circular") to be issued to
shareholders of National Grid Group in connection with approval by such
shareholders of the National Grid Merger Agreement. NEES shall use its best
efforts to provide EUA with a draft of any portion of the NGG Circular with
information relating to EUA prior to the issuance of the NGG Circular.
7.03 Approval of Shareholders. EUA shall, through its Board of
Trustees, duly call, give notice of, convene and hold a meeting of its
shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the
approval of the Merger and other transactions contemplated hereby (the "EUA
Shareholders' Approval") as soon as reasonably practicable after the date
hereof; provided, however, subject to the fiduciary duties of its Board of
Trustees and the requirements of applicable law, EUA shall include in the Proxy
Statement the recommendation of the Board of Trustees of EUA that the
Shareholders of EUA approve the Merger and the other transactions contemplated
hereby, and shall use its reasonable best efforts to obtain such approval.
7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party
hereto shall file or cause to be filed with the Federal Trade Commission and the
Department of Justice any notifications required to be filed by its respective
"ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated
thereunder with respect to the Merger and other transactions contemplated
hereby. Such parties will use all commercially reasonable efforts to make such
filings in a timely manner and to respond on a timely basis to any requests for
additional information made by either of such agencies.
(b) Other Regulatory Approvals. Each party shall cooperate and
use its best efforts to promptly prepare and file all necessary applications,
notices, petitions, filings and other documents with, and to use all
commercially reasonable efforts to obtain all necessary permits, consents,
approvals and authorizations of, all Governmental Authorities necessary or
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advisable to obtain the EUA Required Statutory Approvals, the NEES Required
Statutory Approvals and the approvals of the state utility commissions referred
to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The
parties agree that they will consult with each other with respect to obtaining
the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have
primary responsibility for the preparation and filing of any related
applications, filings or other material with the SEC, the FERC, the NRC and
state utility commissions. EUA shall have the right to review and approve in
advance drafts of and final applications, filings and other material (including
material with respect to proposed settlements) submitted to or filed with the
SEC, the FERC, the NRC and state utility commissions or parties to such
proceedings before such Governmental Authority, which approval shall not be
unreasonably withheld or delayed.
(c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge
that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA
Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the
regulatory approvals (the "NEES-NGG Regulatory Approvals") required to
consummate the transactions contemplated by the National Grid Merger Agreement.
NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA
Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the
prosecution by National Grid Group and NEES of the proceedings relating to the
NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but
recognize that one or more of the NEES-EUA Regulatory Proceedings may be
consolidated with one or more of the NEES-NGG Regulatory Proceedings by the
relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA
reasonably apprised of the status of the NEES-NGG Regulatory Proceedings.
7.05 Employee Benefit Plans.
(a) For a period of twelve (12) months immediately following the
Closing Date, the compensation, benefits and coverage provided to those
non-union individuals who continue to be employees of the Surviving Entity (the
"Affected Employees") pursuant to employee benefit plans or arrangements
maintained by NEES or the Surviving Entity shall be, in the aggregate, not less
favorable (as determined by NEES and the Surviving Entity using reasonable
assumptions and benefit valuation methods) than those provided, in the
aggregate, to such Affected Employees immediately prior to the Closing Date. In
addition to the foregoing, NEES shall, or shall cause the Surviving Entity to,
pay any Affected Employee whose employment is terminated by NEES or the
Surviving Entity within twelve (12) months of the Closing Date a severance
benefit package equivalent to the severance benefit package that would be
provided under the NEES Standard Severance Plan as in effect on the date hereof.
(b) NEES shall, or shall cause the Surviving Entity to, give the
Affected Employees full credit for purposes of eligibility, vesting, benefit
accrual (including, without limitation, benefit accrual under any defined
benefit pension plans) and determination of the level of benefits under any
employee benefit plans or arrangements maintained by NEES or the Surviving
Entity in effect as of the Closing Date for such Affected Employees' service
with EUA or any Subsidiary of EUA (or any prior employer) to the same extent
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recognized by EUA or such Subsidiary immediately prior to the Closing Date. With
respect to any employee benefit plan or arrangement established by NEES, EUA or
the Surviving Entity after the Closing Date (the "Post Closing Plans"), service
shall be credited in accordance with the terms of such Post Closing Plans.
(c) NEES shall, or shall cause the Surviving Entity to, (i)
waive all limitations as to preexisting conditions, exclusions and waiting
periods with respect to participation and coverage requirements applicable to
the Affected Employees under any welfare benefit plan established to replace any
EUA welfare benefit plans in which such Affected Employees may be eligible to
participate after the Closing Date, other than limitations or waiting periods
that are already in effect with respect to such Affected Employees and that have
not been satisfied as of the Closing Date under any welfare plan maintained for
the Affected Employees immediately prior to the Closing Date, and (ii) provide
each Affected Employee with credit for any co-payments and deductibles paid
prior to the Closing Date in satisfying any applicable deductible or
out-of-pocket requirements under any welfare plans that such Affected Employees
are eligible to participate in after the Closing Date.
(d)(i) NEES shall, or shall cause the Surviving Entity and its
Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect
on the date hereof; provided, however, that this Section 7.05(d)(i) is not
intended to prevent NEES or the Surviving Entity from exercising their rights
with respect to all EUA Employee Benefit Plans solely in accordance with their
terms, including but not limited to the right to alter, terminate or otherwise
amend such EUA Employee Benefit Plans.
(ii) NEES shall, or shall cause the Surviving Entity and
its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, (A) all employment severance, consulting and
retention agreements or arrangements as in effect on the date hereof, as set
forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in
accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or
arrangements, the "EUA Employee Agreements" and the individuals who are parties
to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee
Benefit Plans in which such EUA Executives participate; provided, however, that
this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity
from exercising their rights with respect to the EUA Employee Agreements and the
EUA Employee Benefit Plans in which such EUA Executives participate, in each
case solely in accordance with their terms, including but not limited to the
right to alter, terminate or otherwise amend such EUA Employee Agreements and
EUA Employee Benefit Plans.
(e) Notwithstanding the foregoing, NEES and the Surviving Entity
and its subsidiaries shall neither be required to or prevented from merging
EUA's benefit plans, agreements, or arrangements into NEES or the Surviving
Entity and its subsidiaries benefit plans, agreements, or arrangements or from
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replacing EUA's benefit plans, agreements or arrangements with NEES or the
Surviving Entity and its subsidiaries benefit plans, agreements or arrangements.
7.06 Labor Agreements and Workforce Matters.
(a) Labor Agreements. NEES shall honor, or shall cause the
appropriate subsidiaries of the Surviving Entity to honor, all collective
bargaining agreements of EUA or its subsidiaries in effect as of the Effective
Time until their expiration; provided, however, that this undertaking is not
intended to prevent NEES or the Surviving Entity and its subsidiaries from
exercising their rights with respect to such collective bargaining agreements
and in accordance with their terms, including any right to amend, modify,
suspend, revoke or terminate any such contract, agreement, collective bargaining
agreement or commitment or portion thereof.
(b) Workforce Matters. Subject to applicable law and obligations
under applicable collective bargaining agreements, for a period of 2 years
following the Effective Time, any reductions in workforce in respect of
employees of the Surviving Entity and its Subsidiaries shall be made on a fair
and equitable basis as determined by the Surviving Entity, with due
consideration to prior experience and skills, and any employee whose employment
is terminated or job is eliminated during such period shall be entitled to
participate on a fair and equitable basis as determined by NEES or the Surviving
Entity in the job opportunity and employment placement programs offered by NEES
or the Surviving Entity or any of their Subsidiaries for which they are
eligible. Any workforce reductions carried out following the Effective Time by
the Surviving Entity and its Subsidiaries shall be done in accordance with all
applicable collective bargaining agreements and all laws and regulations
governing the employment relationship and termination thereof including, without
limitation, the Worker Adjustment and Retraining Notification Act, and the
regulations promulgated thereunder, and any comparable state or local law.
7.07 Post Merger Operations.
(a) NEES Advisory Board. If the Merger is consummated, then,
promptly following the closing of the merger contemplated by the National Grid
Merger Agreement, NEES shall take such action as is necessary to cause all of
the members of the Board of Directors of EUA to be appointed to serve on the
advisory board to be formed pursuant to Section 7.07(e) of the National Grid
Merger Agreement.
(b) Charities. The parties agree that provision of charitable
contribution and community support within the New England region serves a number
of important goals. After the Effective Time, NEES intends to cause the
Surviving Entity to provide charitable contributions and community support
within the New England region at annual levels substantially comparable to the
annual level of charitable contributions and community support provided,
directly or indirectly, by EUA and its public utility subsidiaries within the
New England region during 1998.
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7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a)
that neither it nor any of its Subsidiaries shall, and it shall use its best
efforts to cause its Representatives (as defined in Section 10.10) not to,
knowingly initiate, solicit or encourage, directly or indirectly, any inquiries
or any proposal or offer (including, without limitation, any proposal or offer
to its Shareholders) with respect to a merger, consolidation or other business
combination including EUA or any of its significant Subsidiaries (as defined in
Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than
EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or
similar transaction (including, without limitation, a tender or exchange offer)
involving the purchase of (i) all or any significant portion of the assets of
EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the
outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the
capital stock of any EUA Significant Subsidiary (any such proposal or offer
being hereinafter referred to as an "Alternative Proposal"), or engage in any
negotiations concerning, or provide any confidential information or data to, or
have any other discussions with, any person or group relating to an Alternative
Proposal, or otherwise knowingly facilitate any effort or attempt to make or
implement an Alternative Proposal other than from NEES and its affiliates; (b)
that it will immediately cease and cause to be terminated any existing
activities, discussions or negotiations with any parties with respect to any
Alternative Proposal; and (c) that it will notify NEES immediately if any such
inquiries, proposals or offers are received by, any such information is
requested from, or any such negotiations or discussions are sought to be
initiated or continued with, it or any of such persons; provided, however, that,
prior to receipt of the EUA Shareholders' Approval, nothing contained in this
Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing
information to (but only pursuant to a confidentiality agreement in customary
form and having terms and conditions no less favorable to EUA than the
Confidentiality Agreement (as defined in Section 7.01)) or entering into
discussions or negotiations with any person or group that makes an unsolicited
Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees
of EUA, based upon advice of outside counsel with respect to fiduciary duties,
determines in good faith that such action is necessary for the Board of Trustees
to act in a manner consistent with its fiduciary duties to Shareholders under
applicable law, (B) the Board of Trustees of EUA has reasonably concluded in
good faith (after consultation with its financial advisors) that the person or
group making such Alternative Proposal will have adequate sources of financing
to consummate such Alternative Proposal and that such Alternative Proposal is
likely to be more favorable to EUA's shareholders than the Merger, (C) prior to
furnishing such information to, or entering into discussions or negotiations
with, such person or group, EUA provides written notice to NEES to the effect
that it is furnishing information to, or entering into discussions or
negotiations with, such person or group, which notice shall identify such person
or group and the material terms of the Alternative Proposal in reasonable
detail, and (D) EUA keeps NEES promptly informed of the status and all material
information with respect to any such discussions or negotiations; and (ii) to
the extent required, complying with Rule 14e-2 promulgated under the Exchange
Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall
(x) permit EUA to terminate this Agreement (except as specifically provided in
Article IX), (y) permit EUA to enter into any agreement with respect to an
Alternative Proposal for so long as this Agreement remains in effect (it being
agreed that for so long as this Agreement remains in effect, EUA shall not enter
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into any agreement with any person or group that provides for, or in any way
knowingly facilitates, an Alternative Proposal (other than a confidentiality
agreement under the circumstances described above)), or (z) affect any other
obligation of EUA under this Agreement.
7.09 Directors' and Officers' Indemnification and Insurance.
(a) Indemnification. To the extent, if any, not provided by an
existing right of indemnification or other agreement or policy, from and after
the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the
fullest extent permitted by applicable law, indemnify, defend and hold harmless
each person who is now, or has been at any time prior to the date hereof, or who
becomes prior to the Effective Time, (x) an officer, trustee or director or (y)
an employee covered as of the date hereof (to the extent of the coverage
extended as of the date hereof) of EUA or any Subsidiary of EUA (each an
"Indemnified Party," and collectively, the "Indemnified Parties") against (i)
all losses, expenses (including reasonable attorney's fees and expenses),
claims, damages or liabilities or, subject to the first proviso of the next
succeeding sentence, amounts paid in settlement, arising out of actions or
omissions occurring at or prior to the Effective Time (and whether asserted or
claimed prior to, at or after the Effective Time) that are, in whole or in part,
based on or arising out of the fact that such person is or was a director,
trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified
Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based
on or arise out of or pertain to the transactions contemplated by this
Agreement, in each case, to the extent permitted by the EUA Trust Agreement or
the indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter. In the event of any such loss, expense, claim, damage or liability
(whether or not arising before the Effective Time), (i) NEES shall, or shall
cause the Surviving Entity to, pay the reasonable fees and expenses of counsel
selected by the Indemnified Parties, which counsel shall be reasonably
satisfactory to NEES or the Surviving Entity, as appropriate, promptly after
statements therefor are received and otherwise advance to such Indemnified Party
upon request, reimbursement of documented expenses reasonably incurred, in
either case to the extent not prohibited by the EUA Trust Agreement or the
indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter upon receipt of an undertaking by or on behalf of such director, trustee
or officer to repay such amounts as and to the extent required by the EUA Trust
Agreement or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of
any such matter and (iii) any determination required to be made with respect to
whether an Indemnified Party's conduct complies with the standards set forth
under the EUA Trust Agreement or the indemnification agreements set forth in
Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation
or by-laws or similar governing documents of the Surviving Entity shall be made
by independent counsel mutually acceptable to the Surviving Entity and the
Indemnified Party; provided, however, that the Surviving Entity shall not be
liable for any settlement effected without its written consent (which consent
shall not be unreasonably withheld) and provided further that no indemnification
shall be made if such indemnification is prohibited by the EUA Trust Agreement
or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter.
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(b) Insurance. For a period of six years after the Effective
Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be
maintained in effect an extended reporting period for current policies of
directors' and officers' liability insurance for the benefit of such persons who
are currently covered by such policies of EUA on terms no less favorable than
the terms of such current insurance coverage or (ii) shall provide tail coverage
for such persons which provides such persons with coverage for a period of six
years for acts prior to the Effective Time on terms no less favorable than the
terms of such current insurance coverage.
(c) Successors. In the event the Surviving Entity or any of its
successors or assigns (i) consolidates with or merges into any other person or
entity and shall not be the continuing or surviving corporation or entity of
such consolidation or merger or (ii) transfers all or substantially all of its
properties and assets to any person or entity, then and in either such case,
proper provisions shall be made so that the successors and assigns of the
Surviving Entity, as applicable, shall assume the obligations set forth in this
Section 7.09.
(d) Survival of Indemnification. To the fullest extent permitted
by law, from and after the Effective Time, all rights to indemnification as of
the date hereof in favor of the employees, agents, directors, trustees and
officers of EUA and EUA's Subsidiaries with respect to their activities as such
prior to the Effective Time, as provided in the EUA Trust Agreement or the
respective certificates of incorporation and by-laws or similar governing
documents in effect on the date hereof, or otherwise in effect on the date
hereof, shall survive the Merger and shall continue in full force and effect for
a period of not less than six years from the Effective Time.
(e) Benefit. The provisions of this Section 7.09 are intended to
be for the benefit of, and shall be enforceable by, each Indemnified Party, his
or her heirs and his or her representatives.
(f) Amendment of the EUA Trust Agreement. NEES shall not, and
shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement
to in any way limit the indemnification provided to the Indemnified Parties
under this Section 7.09.
7.10 Expenses. Except as set forth in Section 9.03, whether or not
the Merger is consummated, all costs and expenses incurred in connection with
the Merger and other transactions contemplated hereby shall be paid by the party
incurring such cost or expense, except that the filing fees in connection with
the filings required under the HSR Act and the 1935 Act shall be paid by NEES.
7.11 Brokers or Finders. EUA represents, as to itself and its
affiliates, that no agent, broker, investment banker, financial advisor or other
firm or person is or will be entitled to any broker's, finder's or investment
banker's fee or any other commission or similar fee in connection with the
Merger and other transactions contemplated by this Agreement except Salomon
Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance
with EUA's agreement with such firm, and EUA shall indemnify and hold NEES
harmless from and against any and all claims, liabilities or obligations with
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respect to any other such fee or commission or expenses related thereto asserted
by any person on the basis of any act or statement alleged to have been made by
EUA or its affiliates.
7.12 Anti-Takeover Statutes. If any "fair price", "moratorium",
"business combination", "control share acquisition" or other form of
anti-takeover statute or regulation shall become applicable to the Merger or
other transactions contemplated hereby, EUA and the members of the Board of
Trustees of EUA shall grant such approvals and take such actions consistent with
their fiduciary duties and in accordance with applicable law as are reasonably
necessary so that the Merger and other transactions contemplated hereby may be
consummated as promptly as practicable on the terms contemplated hereby and
otherwise act to eliminate or minimize the effects of such statute or regulation
on the Merger and other transactions contemplated hereby.
7.13 Public Announcements. Except as otherwise required by law or the
rules of any applicable securities exchange or national market system or any
other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA
will not, and will not permit any of their respective Subsidiaries or
Representatives to, issue or cause the publication of any press release or make
any other public announcement with respect to the Merger and other transactions
contemplated by this Agreement without the consent of the other party, which
consent shall not be unreasonably withheld. NEES and EUA will cooperate with
each other in the development and distribution of all press releases and other
public announcements with respect to the Merger and other transactions
contemplated hereby, and will furnish the other with drafts of any such releases
and announcements as far in advance as practicable.
7.14 Restructuring of the Merger. It may be preferable to effectuate
a business combination between NEES and EUA by means of an alternative structure
to the Merger. Accordingly, if, prior to satisfaction of the conditions
contained in Article VIII hereto, NEES proposes the adoption of an alternative
structure that otherwise substantially preserves for NEES and EUA the economic
benefits of the Merger and will not materially delay the consummation thereof,
then the parties shall use their respective best efforts to effect a business
combination among themselves by means of a mutually agreed upon structure other
than the Merger that so preserves such benefits; provided, however, that prior
to closing any such restructured transaction, all material third party and
Governmental Authority declarations, filings, registrations, notices,
authorizations, consents or approvals necessary for the effectuation of such
alternative business combination shall have been obtained and all other
conditions to the parties' obligations to consummate the Merger and other
transactions contemplated hereby, as applied to such alternative business
combination, shall have been satisfied or waived.
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ARTICLE VIII
CONDITIONS
8.01 Conditions to Each Party's Obligation to Effect the Merger. The
respective obligation of each party to effect the Merger and other transactions
contemplated hereby is subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following conditions:
(a) Shareholder Approval. EUA Shareholders' Approval shall have
been obtained.
(b) HSR Act. Any waiting period (and any extension thereof)
applicable to the consummation of the Merger under HSR shall have expired or
been terminated.
(c) Injunctions or Restraints. No court of competent
jurisdiction or other competent Governmental Authority shall have enacted,
issued, promulgated, enforced or entered any law or order (whether temporary,
preliminary or permanent) which is then in effect and has the effect of making
illegal or otherwise restricting, preventing or prohibiting consummation of the
Merger or other transactions contemplated hereby.
(d) Governmental and Regulatory and Other Consents and
Approvals. The NEES Required Statutory Approvals and EUA Required Statutory
Approvals shall have been obtained prior to the Effective Time, and shall have
become Final Orders (as hereinafter defined). The Final Orders shall not,
individually or in the aggregate, impose terms and conditions that (i) could
reasonably be expected to have an EUA Material Adverse Effect; (ii) could
reasonably be expected to have a NEES Material Adverse Effect; or (iii)
materially impair the ability of the parties to complete the Merger. The parties
shall have received Final Orders from the Massachusetts Department of
Telecommunications and Energy and the Rhode Island Public Utilities Commission
pertaining to the recovery of costs (including, without limitation, transaction
premium and integration costs) associated with the Merger that are materially
consistent with existing policy and previous orders of such agencies. "Final
Order" for all purposes of this Agreement means action by the relevant
regulatory authority which has not been reversed, stayed, enjoined, set aside,
annulled or suspended with respect to which any waiting period prescribed by law
before the Merger and other transactions contemplated hereby may be consummated
has expired, and as to which all conditions to be satisfied before the
consummation of such transactions prescribed by law, regulation or order have
been satisfied.
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger.
The obligation of NEES and LLC to effect the Merger and other transactions
contemplated hereby is further subject to the satisfaction or waiver at or prior
to the Closing, of each of the following additional conditions (all or any of
which may be waived in whole or in part by NEES and LLC in the sole discretion):
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(a) Representations and Warranties. The representations and
warranties made by EUA in this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "EUA Material Adverse Effect", shall be true and correct as so
made as of the Closing Date as though so made on and as of the Closing Date,
except to the extent expressly given as of a specified date, except where the
failure of such representations and warranties to be true and correct as so made
does not have and could not reasonably be expected to have, individually or in
the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to
NEES a certificate, dated the Closing Date and executed in the name and on
behalf of EUA by its Chairman of the Board, President or any Executive or Senior
Vice President, to such effect.
(b) Performance of Obligations. EUA shall have performed and
complied with, in all material respects, each agreement, covenant and obligation
required by this Agreement to be so performed or complied with by EUA at or
prior to the Closing, and EUA shall have delivered to NEES a certificate, dated
the Closing Date and executed in the name and on behalf of EUA by its Chairman
of the Board, President or any Executive or Senior Vice President, to such
effect.
(c) Material Adverse Effect. No EUA Material Adverse Effect
shall have occurred and there shall exist no facts or circumstances which in the
aggregate could reasonably be expected to have an EUA Material Adverse Effect.
(d) EUA Required Consents. All EUA Required Consents shall have
been obtained by EUA, except where the failure to receive such EUA Required
Consents could not reasonably be expected to (i) have an EUA Material Adverse
Effect, or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
8.03 Conditions to Obligation of EUA to Effect the Merger. The
obligation of EUA to effect the Merger and other transactions contemplated
hereby is further subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following additional conditions (all or any of which may
be waived in whole or in part by EUA in its sole discretion):
(a) Representations and Warranties. The representations and
warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07,
5.08 and 5.09 of this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "NEES Material Adverse Effect," shall be true and correct as so
made as of the Closing Date, except to the extent expressly given as of a
specified date and except where the failure of such representations and
warranties to be so true and correct as so made does not have and could not
reasonably be expected to have, individually or in the aggregate, a NEES
Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC
shall each have delivered to EUA a certificate, dated the Closing Date and
executed in the name and on behalf of NEES by any director of NEES and in the
name and on behalf of LLC by a member of its management committee its Chairman
of the Board, President or any Executive or Senior Vice President to such
effect.
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(b) NEES Required Consents. All NEES Required Consents shall
have been obtained by NEES, except where the failure to receive such NEES
Required Consents could not reasonably be expected to (i) have a NEES Material
Adverse Effect or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
(c) Performance of Obligations. NEES and LLC shall have
performed and complied with, in all material respects, each agreement, covenant
and obligation required by this Agreement to be so performed or complied with by
NEES or LLC at or prior to the Closing, and NEES and LLC shall each have
delivered to EUA a certificate, dated the Closing Date and executed in the name
and on behalf of NEES by its Chairman of the Board, President or any Executive
or Senior Vice President, or on behalf of LLC by a member of its management
committee to such effect.
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER
9.01 Termination. This Agreement may be terminated, and the Merger
and other transactions contemplated hereby may be abandoned, at any time prior
to the Effective Time, whether prior to or after EUA Shareholders' Approval
(except as otherwise provided in Section 9.01(c) below):
(a) By mutual written agreement of the Board of Directors of
NEES and Board of Trustees of EUA, respectively;
(b) By EUA or NEES, by written notice to the other, if the
Closing Date shall not have occurred on or before December 31, 1999 (the
"Initial Termination Date"); provided, however, that the right to terminate the
Agreement under this Section 9.01(b) shall not be available to any party whose
failure to fulfill any obligation under this Agreement has been the cause of, or
resulted in, the failure of the Effective Time to occur on or before such date;
and provided, further, that if on the Initial Termination Date the conditions to
the Closing set forth in Section 8.01(d) shall not have been fulfilled but all
other conditions to the Closing shall be fulfilled or shall be capable of being
fulfilled, then the Initial Termination Date shall be extended for four (4)
months beyond the Initial Termination Date (the "Extended Termination Date");
(c) By NEES, by written notice to EUA, if EUA Shareholders'
Approval shall not have been obtained at a duly held meeting of such
Shareholders, including any adjournments thereof;
(d) By EUA or NEES, if any applicable state or federal law or
applicable law of a foreign jurisdiction or any order, rule or regulation is
adopted or issued that has the effect, as supported by the written opinion of
outside counsel for such party, of prohibiting the Merger or other transactions
contemplated hereby, or if any court of competent jurisdiction or any
Governmental Authority shall have issued a nonappealable final order, judgment
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or ruling or taken any other action having the effect of permanently
restraining, enjoining or otherwise prohibiting the Merger or other transactions
contemplated hereby (provided that the right to terminate this Agreement under
this Section 9.01(d) shall not be available to any party that has not defended
such lawsuit or other legal proceeding (including seeking to have any stay or
temporary restraining order entered by any court or other Governmental Authority
vacated or reversed)).
(e) By EUA upon ten (10) days' prior notice to NEES if the Board
of Trustees of EUA determines in good faith, that termination of this Agreement
is necessary for the Board of Trustees of EUA to act in a manner consistent with
its fiduciary duties to Shareholders under applicable law by reason of an
unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B)
of Section 7.08 having been made; provided that
(A) The Board of Trustees of EUA shall determine based
on advice of outside counsel with respect to the Board of
Trustees' fiduciary duties that notwithstanding a binding
commitment to consummate an agreement of the nature of this
Agreement entered into in the proper exercise of its applicable
fiduciary duties, and notwithstanding all concessions which may
be offered by NEES in negotiation entered into pursuant to clause
(B) below, it is necessary pursuant to such fiduciary duties that
the trustees reconsider such commitment as a result of such
Alternative Proposal, and
(B) prior to any such termination, EUA shall, and
shall cause its respective financial and legal advisors to,
negotiate with NEES to make such adjustments in the terms and
conditions of this Agreement as would enable EUA to proceed with
the Merger or other transactions contemplated hereby on such
adjusted terms;
and provided further that EUA's ability to terminate this Agreement pursuant to
this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES
of any amounts owed by it pursuant to Section 9.03(a);
(f) By EUA, by written notice to NEES, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of NEES hereunder (other than a breach
described in clause (ii)), and such breach shall not have been remedied within
twenty (20) days after receipt by NEES of notice in writing from EUA, specifying
the nature of such breach and requesting that it be remedied; or (ii) NEES shall
fail to deliver or cause to be delivered the amount of cash to the Paying Agent
required pursuant to Section 2.02(a) at a time when all conditions to NEES's
obligation to close have been satisfied or otherwise waived in writing by NEES.
(g) By NEES, by written notice to EUA, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of EUA hereunder, and such breach shall not
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have been remedied within twenty (20) days after receipt by EUA of notice in
writing from NEES, specifying the nature of such breach and requesting that it
be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify
in any manner adverse to NEES its approval of the Merger and other transactions
contemplated hereby or its recommendation to its shareholders regarding the
approval of this Agreement, the Merger and other transactions contemplated
hereby, (B) shall approve or recommend or take no position with respect to an
Alternative Proposal or (C) shall resolve to take any of the actions specified
in clause (A) or (B).
9.02 Effect of Termination. If this Agreement is validly terminated
by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith
become null and void and there shall be no liability or obligation on the part
of either EUA or NEES (or any of their respective Representatives or
affiliates), except that the provisions of this Section 9.02, Sections 7.10,
7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply
following any such termination.
9.03 Termination Fees. (a) In the event that (i) this Agreement is
terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall
have made an Alternative Proposal that has not been withdrawn and this Agreement
is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B)
by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a
definitive agreement with respect to such Alternative Proposal is executed
within two years after such termination, then EUA shall pay to NEES, by wire
transfer of same day funds, either on the date contemplated in Section 9.01(e)
if applicable, or otherwise, within five (5) business days after such
termination, a termination fee of $20 million, plus an amount equal to all
documented out-of-pocket expenses and fees incurred by NEES arising out of, or
in connection with or related to, the Merger and other transactions contemplated
hereby, not in excess of $5 million in the aggregate.
(b) In the event that this Agreement is terminated by either
NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i)
the conditions to the Closing set forth in Section 8.01(d) shall not have been
fulfilled, (ii) if the date of termination is any date other than a date which
is on or after the Extended Termination Date, all conditions contained in
Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or
are capable of being fulfilled as of such date, and (iii) the merger
contemplated by the National Grid Merger Agreement has not yet been consummated,
then NEES shall pay to EUA, by wire transfer of same day funds, within five (5)
business days after such termination, a termination fee of $10 million, plus an
amount equal to all documented out-of-pocket expenses and fees incurred by EUA
arising out of, or in connection with or related to, the Merger and other
transactions contemplated hereby, not in excess of $5 million in the aggregate.
(c) Nature of Fees. The parties agree that the agreements
contained in this Section 9.03 are an integral part of the Merger and the other
transactions contemplated hereby and constitute liquidated damages and not a
penalty. The parties further agree that if any party is or becomes obligated to
pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive
such termination fee shall be the sole remedy of the other party with respect to
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the facts and circumstances giving rise to such payment obligation. If this
Agreement is terminated by a party as a result of a willful breach of a
representation, warranty, covenant or agreement by the other party, including a
termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue
any remedies available to it at law or in equity and shall be entitled to
recover any additional amounts thereunder. Notwithstanding anything to the
contrary contained in this Section 9.03, if one party fails to promptly pay to
the other any fee or expense due under this Section 9.03, in addition to any
amounts paid or payable pursuant to such Section, the defaulting party shall pay
the costs and expenses (including legal fees and expenses) in connection with
any action, including the filing of any lawsuit or other legal action, taken to
collect payment, together with interest on the amount of any unpaid fee at the
publicly announced prime rate of Citibank, N.A. from the date such fee was
required to be paid.
9.04 Amendment. This Agreement may be amended, supplemented or
modified by action taken by or on behalf of the Board of Directors of NEES or
the Board of Trustees of EUA at any time prior to the Effective Time, whether
prior to or after EUA Shareholders' Approval shall have been obtained, but after
such adoption and approval only to the extent permitted by applicable law. No
such amendment, supplement or modification shall be effective unless set forth
in a written instrument duly executed and delivered by or on behalf of each
party hereto.
9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by
action taken by or on behalf of its Board of Directors or Board of Trustees,
respectively, may to the extent permitted by applicable law (i) extend the time
for the performance of any of the obligations or other acts of the other parties
hereto, (ii) waive any inaccuracies in the representations and warranties of the
other parties hereto contained herein or in any document delivered pursuant
hereto or (iii) waive compliance with any of the covenants, agreements or
conditions of the other parties hereto contained herein. No such extension or
waiver shall be effective unless set forth in a written instrument duly executed
by or on behalf of the party extending the time of performance or waiving any
such inaccuracy or non-compliance. No waiver by any party of any term or
condition of this Agreement, in any one or more instances, shall be deemed to be
or construed as a waiver of the same or any other term or condition of this
Agreement on any future occasion.
ARTICLE X
GENERAL PROVISIONS
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements. The representations, warranties, covenants and agreements contained
in this Agreement or in any instrument delivered pursuant to this Agreement
shall not survive the Merger but shall terminate at the Effective Time, except
for the agreements contained in Article I and Article II, in Sections 7.05,
7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective
Time.
10.02 Notices. All notices, requests and other communications
hereunder must be in writing and will be deemed to have been duly given only if
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delivered personally or by facsimile transmission or sent by overnight courier
(providing proof of delivery) to the parties at the following addresses or
facsimile numbers:
If to NEES or LLC, to:
New England Electric System
25 Research Drive
Westborough, MA 01582
Attn: Richard P. Sergel
President and Chief Executive Officer
Telephone: (508) 389-2764
Facsimile: (508) 366-5498
with a copy to:
Skadden, Arps, Slate, Meagher & Flom LLP
919 Third Avenue
New York, NY 10022
Attn: Sheldon S. Adler, Esq.
Telephone: (212) 735-3000
Facsimile: (212) 735-2000
If to EUA, to:
Eastern Utilities Associates
One Liberty Square
Boston, MA 02109
Attn: Donald G. Pardus
Chairman and Chief Executive Officer
Telephone: (617) 357-9590
Facsimile: (617) 357-7320
with a copy to:
Winthrop, Stimson, Putnam & Roberts
1 Battery Park Plaza
New York, NY 10004
Attn: David P. Falck
Telephone: (212) 858-1000
Facsimile: (212) 858-1500
All such notices, requests and other communications will (i) if
delivered personally to the address as provided in this Section, be deemed given
-45-
<PAGE>
upon delivery, (ii) if delivered by facsimile transmission to the facsimile
number as provided in this Section, be deemed given when sent, provided that the
facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if
delivered by mail in the manner described above to the address as provided in
this Section, be deemed given one business day after delivery (in each case
regardless of whether such notice, request or other communication is received by
any other person to whom a copy of such notice, request or other communication
is to be delivered pursuant to this Section). Any party from time to time may
change its address, facsimile number or other information for the purpose of
notices to that party by giving notice specifying such change to the other
parties hereto.
10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement
supersedes all prior discussions and agreements, both written and oral, among
the parties hereto with respect to the subject matter hereof, other than the
Confidentiality Agreement, which shall survive the execution and delivery of
this Agreement in accordance with its terms, and contains, together with the
Confidentiality Agreement, the sole and entire agreement among the parties
hereto with respect to the subject matter hereof.
(b) The EUA Disclosure Letter, the NEES Disclosure Letter and
any Exhibit attached to this Agreement and referred to herein are hereby
incorporated herein and made a part hereof for all purposes as if fully set
forth herein.
10.04 No Third Party Beneficiary. The terms and provisions of this
Agreement are intended solely for the benefit of each party hereto and their
respective successors or permitted assigns, and except as provided in Article II
and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit
of the persons entitled to therein, and may be enforced by any of such persons),
it is not the intention of the parties to confer third-party beneficiary rights
upon any other person.
10.05 No Assignment; Binding Effect. Neither this Agreement nor any
right, interest or obligation hereunder may be assigned, in whole or in part, by
operation of law or otherwise, by any party hereto without the prior written
consent of the other parties hereto and any attempt to do so will be void,
except that LLC may assign any or all of its rights, interests and obligations
hereunder to another direct or indirect wholly owned Subsidiary of NEES,
provided that any such Subsidiary agrees in writing to be bound by all of the
terms, conditions and provisions contained herein and provided further that such
assignment (i) does not require a greater vote for EUA's Shareholder Approval,
(ii) does not require a subsequent vote following EUA's Shareholders Meeting, or
(iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES,
as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required
Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals,
or the NEES Required Consents. Subject to the preceding sentence, this Agreement
is binding upon, inures to the benefit of and is enforceable by the parties
hereto and their respective successors and assigns.
-46-
<PAGE>
10.06 Headings. The headings used in this Agreement have been
inserted for convenience of reference only and do not define, modify or limit
the provisions hereof.
10.07 Invalid Provisions. If any provision of this Agreement is held
to be illegal, invalid or unenforceable under any present or future law or
order, and if the rights or obligations of any party hereto under this Agreement
will not be materially and adversely affected thereby, (i) such provision will
be fully severable, (ii) this Agreement will be construed and enforced as if
such illegal, invalid or unenforceable provision had never comprised a part
hereof, and (iii) the remaining provisions of this Agreement will remain in full
force and effect and will not be affected by the illegal, invalid or
unenforceable provision or by its severance herefrom.
10.08 Governing Law. This Agreement shall be governed by and
construed in accordance with the laws of the Commonwealth of Massachusetts.
10.09 Enforcement of Agreement. The parties hereto agree that
irreparable damage would occur in the event that any of the provisions of this
Agreement was not performed in accordance with its specified terms or was
otherwise breached. It is accordingly agreed that the parties shall be entitled
to an injunction or injunctions to prevent breaches of this Agreement and to
enforce specifically the terms and provisions hereof in any court of competent
jurisdiction, this being in addition to any other remedy to which they are
entitled at law or in equity.
10.10 Certain Definitions. As used in this Agreement:
(a) except as provided in Section 4.14, the term "affiliate," as
applied to any person, shall mean any other person directly or indirectly
controlling, controlled by, or under common control with, that person; for
purposes of this definition, "control" (including, with correlative meanings,
the terms "controlling," "controlled by" and "under common control with"), as
applied to any person, means the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of that
person, whether through the ownership of voting securities, by contract or
otherwise;
(b) a person will be deemed to "beneficially" own securities if
such person would be the beneficial owner of such securities under Rule 13d-3
under the Exchange Act, including securities which such person has the right to
acquire (whether such right is exercisable immediately or only after the passage
of time);
(c) the term "business day" means a day other than Saturday,
Sunday or any day on which banks located in the Massachusetts are authorized or
obligated to close;
(d) the term "knowledge" or any similar formulation of
"knowledge" shall mean, with respect to any party hereto, the actual knowledge
after due inquiry of the executive officers of NEES and its Subsidiaries or EUA
and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES
Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided
-47-
<PAGE>
that as used in Section 4.13 the term "knowledge" shall also include the
knowledge of the environmental, health and safety personnel of EUA;
(e) the term "person" shall include individuals, corporations,
partnerships, trusts, limited liability companies, other entities and groups
(which term shall include a "group" as such term is defined in Section 13(d)(3)
of the Exchange Act);
(f) the "Representatives" of any entity shall have the same
meaning as set forth in the Confidentiality Agreement;
(g) the term "Subsidiary" means any corporation or other entity,
whether incorporated or unincorporated, in which such party directly or
indirectly owns at least a majority of the voting power represented by the
outstanding capital stock or other voting securities or interests having voting
power under ordinary circumstances to elect a majority of the directors or
similar members of the governing body, or otherwise to direct the management and
policies, or such corporation or entity.
10.11 Counterparts. This Agreement may be executed in any number of
counterparts, each of which will be deemed an original, but all of which
together will constitute one and the same instrument and will become effective
when one or more counterparts have been signed by each party and delivered to
the other parties.
10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE
FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY
JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING
TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON
CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO
REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY
OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK
TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER
PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER
THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
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<PAGE>
IN WITNESS WHEREOF, each party hereto has caused this Agreement to be
signed by its officer thereunto duly authorized as of the date first above
written.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability therefor.
EASTERN UTILITIES ASSOCIATES
By: /s/ Donald G. Pardus
-----------------------------------
Name: Donald G. Pardus
Title: Chairman
The name "Eastern Utilities Associates" is the designation of the Trustees of
EUA for the time being in their collective capacity but not personally, under a
Declaration of Trust dated April 2, 1928, as amended, a copy of which amended
Declaration of Trust has been filed in the office of the Secretary of The
Commonwealth of Massachusetts and elsewhere as required by law; and all persons
dealing with EUA must look solely to the trust property for the enforcement of
any claim against EUA, as neither the Trustees nor the officers or shareholders
of EUA assume any personal liability for obligations entered into on behalf of
EUA.
RESEARCH DRIVE LLC
By: /s/ John G. Cochrane
-----------------------------------
Name: John G. Cochrane
Title: Manager
-49-
<PAGE>
Tab 2
CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
CONSENT AGREEMENT
This Consent Agreement (the "Agreement") is entered into as of
February 1, 1999 between The National Grid Group, p1c, a public limited company
incorporated under the laws of England and Wales ("NGG") and New England
Electric System, a Massachusetts business trust ("NEES").
WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly
owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as
of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC
will merge (the "Merger") with and into NEES with NEES being the surviving
entity and becoming a wholly owned subsidiary of NGG;
WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business
Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement
and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger
Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC
with and into EUA with EUA being the surviving entity and becoming a wholly
owned subsidiary of NEES; and
WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is
required to obtain the consent of NGG before entering into the EUA Merger
Agreement and with respect to certain actions relating to the consummation of
the transactions set forth therein.
NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties hereby agree as
follows:
1. Consent to EUA Merger Agreement. Subject to the terms and
conditions of this Consent, NGG hereby consents to NEES entering into the EUA
Merger Agreement with EUA in the form set forth in Exhibit A and agrees that,
subject to the immediately following sentence, the consummation by NEES of the
transactions contemplated by the EUA Merger Agreement in accordance with the
term thereof shall not constitute a breach by NEES of the terms of the Merger
Agreement. NEES and NGG acknowledge that the financing necessary to consummate
the EUA Merger was not contemplated when NEES and NGG agreed to the limitations
set forth in Article VI of the Merger Agreement and NGG consents to such
financing provided that such financing is consistent with the financing
parameters set forth on Exhibit B hereto. NGG also consents to the formation and
<PAGE>
capitalization of Research Drive LLC by NEES for the purpose of effecting the
EUA Merger as contemplated in the EUA Merger Agreement.
2. Access to Information. Subject to the following sentence, NEES
hereby agrees to provide NGG with reasonable access to any information it
receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to
consult with NGG on a regular basis concerning the status of EUA and the EUA
Merger. NGG hereby acknowledges that any such material that is "Evaluation
Material" (as such term is defined in the letter agreement dated as of December
21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be
governed by the terms of the Confidentiality Agreement.
3. Regulatory Filings. NEES hereby agrees that NGG shall have the
right to review in advance, and that NEES will consult with NGG and give due
regard to NGG's views concerning, any applications, notices, petitions, filings
and other documents filed with any Governmental Authority (as defined in the EUA
Merger Agreement) in connection with the EUA Merger which could reasonably be
expected to have a material adverse effect on NGG's or NEES' ability to
consummate the Merger or which could reasonably be expected to adversely affect
in any material manner any material benefit of the Merger to NGG or NEES.
4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will
not, without the prior written consent of NGG, amend or modify the EUA Merger
Agreement in any material respect, including, without limitation, amend or
otherwise modify any provision of the EUA Merger Agreement providing for or
relating to the amount, type or structure of the Merger Consideration (as
defined in the EUA Merger Agreement) or agree to any additional or different
amount, type or structure for the Merger Consideration (as so defined).
5. Acknowledgment. NGG and NEES acknowledge and agree that the
covenants set forth in Article VI of the Merger Agreement do not reflect the
operations of EUA if the EUA Merger is consummated prior to the Effective Time
(as defined in the Merger Agreement). In the event that the EUA Merger is
consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate
in good faith to make appropriate modifications to such covenants set forth in
Section 6.01 of the Merger Agreement to reflect the operations of EUA.
6. Termination and Amendment. This Consent Agreement and the
obligations of NEES hereunder shall terminate upon the earlier to occur of (i)
the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the
Merger, in each case without any further action by the parties hereto. Except as
<PAGE>
provided in the preceding sentence, this Consent can not be terminated or
amended in any material respect prior to the termination of the EUA Merger
Agreement without the prior written consent of EUA. The foregoing sentence is
intended for the benefit of EUA and may be enforced by EUA.
7. Notices. NEES hereby agrees to provide NGG with copies of all
notices and other communications it sends to EUA and all notices and other
communications it receives from EUA under the EUA Merger Agreement. All notices
and other communications provided under this Agreement must be in writing and
shall be given in the same manner and to the same parties as set forth in
Section 10.02 of the Merger Agreement.
8. Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
9. Governing Law and Waiver of Jury Trial. This Agreement shall be
governed by and construed in accordance with the laws of the State of New York
applicable to a contract executed and performed in such State, without giving
effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO
THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL
BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR
RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER
THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR
ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH
OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING
WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN
INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS
AND CERTIFICATIONS IN THIS SECTION.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: /s/ Fiona B. Smith
-----------------------------------
Name: Fiona B. Smith
Title: Company Secretary
NEW ENGLAND ELECTRIC SYSTEM
By: ___________________________
Name:
Title:
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: ______________________________
Name:
Title:
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES
(not legible)
<PAGE>
EXHIBIT B - Financing Parameters
Financing will be in an amount of up to $630 M provided through a
group of banks. The financing (i) will be prepayable, (ii) will have a term not
to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv)
will have other terms and conditions usual and customary for transactions of
this nature.
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
SUPPLEMENT TO APPLICATION
TO ADD DESCRIPTION OF
CORPORATE RESTRUCTURING
AND
FILING OF ADDITIONAL MATERIAL FOR EXHIBIT G
Edward Berlin, Esq. David A. Fazzone, Esq. of
Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and
Scott P. Klurfeld, Esq. McDermott, Will & Emery
Swidler Berlin Shereff Friedman, LLP 28 State Street
3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775
Washington, D.C. 20007-5116 (617) 535-4000
(202) 424-7500 Attorneys for Montaup Electric Company
and Affiliated Applicants
Thomas G. Robinson, Esq.
New England Power Company
25 Research Drive
Westborough, MA 01582
(508) 389-2877
Attorneys for New England Power
Company and Affiliated Applicants
July 1, 1999
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
)
NEW ENGLAND POWER COMPANY, et al. )
and ) Docket No. EC99-70
MONTAUP ELECTRIC COMPANY, et al. )
)
SUPPLEMENT TO APPLICATION
TO ADD DESCRIPTION OF
CORPORATE RESTRUCTURING
AND
FILING OF ADDITIONAL MATERIAL FOR EXHIBIT G
Pursuant to Section 203 of the Federal Power Act ("FPA"),1/ and Part 33
of the Commission's Regulations,2/ New England Power Company ("NEP") and its
affiliates holding jurisdictional assets ("NEES Companies"),3/ Montaup Electric
Company ("Montaup") and its affiliates holding jurisdictional assets ("EUA
Companies"),4/ and Research Drive LLC5/ submit this supplement to the
- ---------------
1/ 16 U.S.C. section 824b (1994).
2/ 18 C.F. R. sections 33.1 et seq. (1998).
3/ These include the following: Massachusetts Electric Company; The
Narragansett Electric Company; New England Electric Transmission Corporation;
New England Hydro-Transmission Corporation; New England Hydro-Transmission
Electric Company, Inc.; and AllEnergy Marketing Company, L.L.C. (which holds no
physical facilities for the generation or transmission of electricity but does
hold a power marketing certificate (see 82 FERC paragraph 61,179 (1998))).
4/ These include the following: Blackstone Valley Electric Company, Eastern
Edison Company ("Eastern Edison"), and Newport Electric Corporation.
5/ Research Drive LLC, a Massachusetts limited liability company, is
jointly-owned by NEES and EUA and was formed for the express purpose of
effectuating the merger that is the subject of this proceeding.
<PAGE>
Application filed on May 5, 1999, in this docket. This proceeding involves the
request for approval of the merger ("Merger") of New England Electric System
("NEES"), the existing holding company for the NEES Companies, and Eastern
Utilities Associates ("EUA"), the existing holding company for the EUA
Companies. Through the Merger, EUA and the EUA Companies will become
subsidiaries of NEES and will ultimately be consolidated into their NEES
counterparts.
The filing of this Supplement has three purposes: (1) to describe a
change in the corporate structure of Montaup that will be implemented prior to
and independent of the closing of the Merger; (2) to the extent required, to
obtain approval from the Commission of this planned corporate restructuring of
Montaup; and (3) to file, in accordance with the commitment made in the original
Application, additional material that should be made part of Exhibit G to the
Application.
DISCUSSION
Corporate Restructuring
As explained in the original Application, currently 100% of the common
stock of Montaup is held by Eastern Edison, which in turn is wholly owned by
EUA. This means that EUA is the existing ultimate parent company of Montaup.
Independent of and prior to the closing of the Merger, Eastern Edison will
transfer all of the common stock of Montaup to EUA so that EUA will become the
direct parent of Montaup. This corporate restructuring is planned for
organizational and financial reasons unrelated to the Merger. Among other
things, this internal restructuring will: (i) complete the functional unbundling
of EUA's remaining generation business from its distribution business through
the complete corporate separation of Eastern Edison and Montaup; (ii) isolate
-2-
<PAGE>
Eastern Edison's capital structure so it applies to distribution ratemaking
only; and (iii) simplify EUA's corporate structure.
The corporate restructuring of Montaup's parent companies has no
impact on the Merger transaction. As a result of the Merger, Montaup will become
a subsidiary of NEES and then will be consolidated into NEP; those steps will
still occur as originally described. The only change is that Montaup will no
longer have an intermediate parent company at the time of the Merger closing.
This Supplement is being filed to make certain that the discussion of Montaup's
corporate structure in the original Application is accurate in light of the
planned restructuring.
Request for Approval of Restructuring (If Required)
In addition, to the extent the Commission determines that this
corporate restructuring of Montaup's parent companies qualifies as a disposition
of control of a jurisdictional entity requiring Commission approval under
Section 203 of the FPA, Montaup requests such approval.6/ If such approval is
required, Montaup, Eastern Edison and EUA believe that the most efficient means
of granting it would be for the Commission to do so in connection with the
processing of the Merger Application because all relevant materials are already
included in this docket.7/ Approval under Section 203 is in the public interest
- ---------------
6/ Applicants have or will inform and, if required, have or will request
approval of the proposed corporate restructuring from the following federal and
state regulatory authorities: the Nuclear Regulatory Commission, the Connecticut
Department of Public Utility Control, and the Massachusetts Department of
Telecommunications and Energy.
7/ Applicants do not foresee any reason that there would be a delay in
approving the Merger Application itself. Accordingly, processing the request for
approval of the independent restructuring of Montaup's parent companies (if any
is required) in conjunction with the Merger Application should provide timely
approval of the restructuring. If, however, there is a delay in granting
approval of the Merger beyond the 60-90 day post-comment time frame established
in the Merger Policy Statement, Applicants request the Commission grant separate
approval of the restructuring of Montaup's parent companies so that the
restructuring may be completed by the beginning of the fourth quarter of this
year.
-3-
<PAGE>
because the change in the structure of the parent companies of Montaup has no
effect on competition, rates or regulation. The existing ultimate parent company
of Montaup, EUA, will remain as the ultimate parent company and, other than
eliminating the intermediate holding company, there is no change in the
structure or operation of any jurisdictional company. In analogous
circumstances, the Commission has approved a restructuring of a company.8/
Submission of Additional Material for Exhibit G
Finally, Applicants submit for filing copies of the following material
that should be made part of Exhibit G to the Application in this proceeding:
Application of Montaup Electric Company and New England Power Company for
Transfer of Licenses and Ownership Interests before the Nuclear Regulatory
Commission (consisting of three volumes).9/
- ---------------
8/ See Doswell Limited Partnership,, 60 FERC paragraph 62,086 (1992)
(approving conversion of partnership interests); Commonwealth Atlantic Limited
Partnership, 57 FERC paragraph 61,193 (1991) (disclaiming jurisdiction under
Section 203 resulting from elimination of intermediate layers of control where
existing ultimate parent remained as such, and approving other changes in
control); see also Citizens Utilities Company, 84 FERC paragraph 61,158 (1998)
(approving spin-off involving distribution of stock of company). The Citizens
Utilities case also directly determined that the payment of a stock dividend to
effectuate the restructuring was not in violation of Section 305(a) of the FPA.
The same is true in this situation with respect to Eastern Edison's transfer of
100% of the common stock of Montaup to EUA. That transfer is merely the vehicle
to effectuate the corporate restructuring and is fully consistent with Section
305(a) of the FPA.
9/ Copies of this filing and all attachments are being filed with the state
commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island, and
Vermont, all parties on the service list in Docket No. EC99-70, and all parties
on the service list in Docket No. ER99-2832.
-4-
<PAGE>
CONCLUSION
In conclusion, Applicants respectfully request that the Commission
approve the Merger Application, as supplemented, without condition, modification
or evidentiary trial-type hearing. Also, to the extent approval is required,
Applicants request that the Commission approve without condition, modification
or evidentiary trial-type hearing, the independent corporate restructuring of
Montaup described above.
Respectfully submitted,
/s/ Scott P. Klurfeld /s/ David A. Fazzone
- ------------------------------------ ----------------------------------------
Edward Berlin, Esq. David A. Fazzone, Esq. of
Kenneth G. Jaffe, Esq. David A. Fazzone, P.C., and
Scott P. Klurfeld, Esq. McDermott, Will & Emery
Swidler Berlin Shereff Friedman, LLP 28 State Street
3000 K Street, N.W., Suite 300 Boston, Massachusetts 02109-1775
Washington, D.C. 20007-5116 (617) 535-4000
(202) 424-7500 Attorney for Montaup Electric Company
and Affiliated Applicants
Thomas G. Robinson, Esq.
New England Power Company
25 Research Drive
Westborough, MA 01582
(508) 389-2877
Attorneys for New England Power
Company and Affiliated Applicants
July 1, 1999
-5-
<PAGE>
[FORM OF NOTICE]
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
NOTICE OF FILING OF
SUPPLEMENT TO APPLICATION
TO ADD DESCRIPTION OF
CORPORATE RESTRUCTURING
AND
FILING OF ADDITIONAL MATERIAL FOR EXHIBIT G
Take notice that on July 1, 1999, New England Power Company ("NEP")
and its affiliates holding jurisdictional assets (Massachusetts Electric
Company, The Narragansett Electric Company, New England Electric Transmission
Corporation, New England Hydro-Transmission Corporation, New England
Hydro-Transmission Electric Company, Inc., and AllEnergy Marketing Company,
L.L.C.) (collectively, the "NEES Companies"), Montaup Electric Company and its
affiliates holding jurisdictional assets (Blackstone Valley Electric Company,
Eastern Edison Company ("Eastern Edison"), Newport Electric Corporation)
(collectively, the "EUA Companies"), and Research Drive LLC submitted a
Supplement to their Application in the above referenced docket. The proceeding
in the above-referenced docket seeks the Commission's approval and related
authorizations to effectuate the merger involving New England Electric System
("NEES"), the parent company of the NEES Companies, and Eastern Utilities
Associates ("EUA"), the parent company of the EUA Companies ("Merger").
<PAGE>
The Supplement explains that currently 100% of the common stock of
Montaup is held by Eastern Edison, which in turn is wholly owned by EUA.
Independent of and prior to the closing of the Merger, Eastern Edison will
transfer all of the common stock of Montaup to EUA so that EUA will become the
direct parent of Montaup. The Supplement states that this independent internal
corporate restructuring of Montaup's parent companies has no impact on the
Merger, but is being filed to make certain that the discussion of Montaup's
corporate structure in the original Application remains accurate.
In addition, the Supplement states that to the extent the Commission
determines that this internal corporate restructuring of Montaup's parent
companies qualifies as a disposition of control of a jurisdictional entity that
requires Commission approval under Section 203 of the FPA, the Applicants
request such approval.
Finally, the Applicants included for filing copies of the following
material that the Applicants request be made part of Exhibit G to the
Application: Application of Montaup Electric Company and New England Power
Company for Transfer of Licenses and Ownership Interests before the Nuclear
Regulatory Commission (consisting of three volumes).
The Applicants have served copies of the filing on the state
commissions of Connecticut, Massachusetts, New Hampshire, Rhode Island, and
Vermont, all parties on the service list of EC99-70, and all parties on the
service list on Docket No. ER99-2832.
Any person desiring to be heard or to protest said amendment should
file a motion to intervene or protest with the Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426 in accordance with
Rules 211 and 214 of the Commission's Rules of Practice and Procedure (18 C.F.R.
385.211 and 18 C.F.R. 385.214). All such motions or protests should be filed on
or before __________. Protests will be considered by the Commission in
determining the appropriate action to be taken, but will not serve to make the
protestants parties to the proceeding. Any person wishing to become a party must
file a motion to intervene. Copies of this filing are on file with the
Commission and are available for public inspection.
-2-
<PAGE>
CERTIFICATE OF SERVICE
I hereby certify that I have this day served the foregoing document
upon each person designated on the official service list compiled by the
Secretary in this proceeding.
Dated at Washington, D.C., this 1st day of July, 1999.
/s/ Sara C. Weinberg
- ---------------------------
Sara C. Weinberg
Swidler Berlin Shereff Friedman, LLP
3000 K Street, N.W., #300
Washington, D.C. 20007
Tel: (202) 424-7500
Fax: (202) 424-7643
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
VERIFICATION
Robert G. Powderly, being duly sworn upon oath, states that he is
Executive Vice-President of Montaup Electric Company, Blackstone Valley Electric
Company, Eastern Edison Company and Newport Electric Corporation and has read
the attached Supplement to Application to Add Description of Corporate
Restructuring and Filing of Additional Material for Exhibit G; that he knows the
contents thereof; that the statements made therein are true and correct to the
best of his knowledge, information and belief; and that he has full power and
authority to sign this document on behalf of Montaup Electric Company,
Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric
Corporation.
/s/ Robert G. Powderly
----------------------------------------
Robert G. Powderly
Executive Vice-President
Subscribed and sworn to before me this 28th day of June, 1999.
---- ----
/s/ Barbara L. Dontono
----------------------------------------
Notary Public
My Commission expires March 30, 2001
--------------
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NEW ENGLAND POWER COMPANY )
MASSACHUSETTS ELECTRIC COMPANY )
THE NARRAGANSETT ELECTRIC COMPANY )
NEW ENGLAND ELECTRIC TRANSMISSION )
CORPORATION ) Docket No. EC99-70
NEW ENGLAND HYDRO-TRANSMISSION )
CORPORATION )
NEW ENGLAND HYDRO-TRANSMISSION )
ELECTRIC COMPANY, INC. )
ALLENERGY MARKETING COMPANY, L.L.C. )
MONTAUP ELECTRIC COMPANY )
BLACKSTONE VALLEY ELECTRIC COMPANY )
EASTERN EDISON COMPANY )
NEWPORT ELECTRIC CORPORATION )
RESEARCH DRIVE LLC )
VERIFICATION
Jennifer Zschokke being duly sworn upon oath, states that she is
Manager of Finance of New England Power Service Company (which provides
financial services to all New England Electric System companies, including New
England Power Company) and has read the attached Supplement to Application to
Add Description of Corporate Restructuring and Filing of Additional Material for
Exhibit G; that she knows the contents thereof; that the statements made therein
are true and correct to the best of her knowledge, information and belief; and
that she has full power and authority to sign this document on behalf of the
Applicants that are New England Electric System companies.
/s/ Jennifer Zschokke
----------------------------------------
Jennifer Zschokke
Manager of Finance
Subscribed and sworn to before me this 30th day of June, 1999.
---- ----
/s/ Celia S. Byler
----------------------------------------
Notary Public
My Commission expires April 5, 2002.
-------------
<PAGE>
New England Electric System and
Eastern Utilities Associates
Massachusetts Electric Company and
Eastern Edison Company Rate Plan
Filing In Support of Merger
Volume 1
Filing Letter & Petition
Testimony & Exhibits of:
Michael E. Jesanis
Robert G. Powderly
Lawrence J. Reilly
Jennifer K. Zschokke
April 30, 1999
Submitted to:
Massachusetts Department of
Telecommunications and Energy
Docket D.T.E. 99-_____
Submitted by:
NEES Logo
EUA Logo
<PAGE>
[NEES logo] [EUA logo]
April 30, 1999
by hand
Mary L. Cottrell, Secretary
Dept. of Telecommunications and Energy
100 Cambridge Street, 12th Floor
Boston, MA 02202
Re: New England Electric System and Eastern Utilities
Associates Merger: Petition for Approval of Mergers,
Financings, and Retail Rate Plan
Dear Secretary Cottrell:
As announced on February 1, 1999, New England Electric System ("NEES")
agreed to acquire all of the outstanding shares of Eastern Utilities Associates
("EUA") for $31 per share subject to adjustment for the date of closing. Because
NEES and EUA are both holding companies, the Department's approval is not
required for the parent-level acquisition. However, following the acquisition,
NEES intends to merge EUA's electric operating subsidiaries into NEES's electric
operating subsidiaries. Thus, in Massachusetts, Eastern Edison Company
("Eastern") will merge into Massachusetts Electric Company ("Mass. Electric"),
and Montaup Electric Company ("Montaup") will merge into New England Power
Company ("NEP"). Enclosed is a Petition that requests approval for the merger of
the NEES and EUA subsidiaries.
Following the merger and the expiration of the distribution rate
freeze in its Restructuring Settlement, Mass. Electric proposes to implement a
rate consolidation plan under which Eastern's customers will be moved onto Mass.
Electric's rates. This rate consolidation plan will reduce the average rates to
Eastern's customers by 14.2 percent or $23 million in 2001. In addition, Mass.
Electric will propose to extend the rate freeze on the distribution component of
its delivery rate for up to four years beyond the end of the rate freeze in its
Restructuring Settlement. This extension occurs in two steps. Upon the merger
with Eastern, the distribution rate freeze will be extended through 2001 and
2002. If the National Grid Group's merger with NEES is approved, the
distribution rate freeze will be extended through 2003 and 2004. Thus, under the
rate plan, Mass. Electric's customers will see stable distribution charges
through December 31, 2004. The enclosed Petition also requests approval by the
Department of the rate plan.
The mergers and rate plan are supported in the testimony of several
witnesses. Michael E. Jesanis, Senior Vice President and Chief Financial Officer
<PAGE>
of NEES, describes the merger and the rate plan. Robert G. Powderly, Executive
Vice President of EUA, discusses EUA's decision to enter the transaction and its
compliance with the Department's standards for mergers and acquisitions.
Lawrence J. Reilly, President and Chief Executive Officer of Mass. Electric,
describes the service improvements and service quality plan that Mass. Electric
proposes following the merger. Jennifer K. Zschokke, Manager of Finance for the
NEES companies, explains the mergers of Mass. Electric and Eastern and of NEP
and Montaup and the required financing approvals to implement the mergers.
In the second volume of the filing, David M. Webster, Principal
Financial Analyst for the NEES companies, explains the accounting issues
associated with the mergers and describes the proposed amendments to Mass.
Electric's funds for recovery of hazardous waste and extraordinary storm costs.
The rate consolidation plan and the mapping of the availability provisions of
Eastern's and Mass. Electric's tariffs are described in the testimonies of
Theresa M. Burns, Principal Rate Analyst for the NEES companies and James J.
Bonner, Jr., Manager of Retail Pricing and Rate Administration for the EUA
companies. Finally, David J. Hoffman and Richard J. Levin of Mercer Management
Consulting set forth the synergies and savings associated with the merger in
third volume of our filing.1/
The NEES-EUA combination provides significant economic benefits to
customers of both Eastern and Mass. Electric. As mentioned above, Eastern's
customers receive a 14.2 percent average rate reduction upon the implementation
of the rate plan. Over the four year period of the rate plan, the customers of
the consolidated company receive economic benefits equal to $128 million. Almost
$106 million of this amount stems directly from the economic value of the
distribution rate freeze. The consolidation of the companies will also produce
ongoing efficiency gains equal to $35 million annually after the expiration of
the rate freeze in 2005.2/ The service quality standards proposed as part of the
rate plan assure that reliability and responsiveness will be maintained during
the period of the rate freeze. Finally, the consolidation of the companies and
the integration of the Mass. Electric and Eastern billing systems should promote
- ---------------
1/Exhibit 3 to Mr. Hoffman and Mr. Levin's testimony is being filed
under separate cover. This exhibit contains confidential payroll and personnel
information. The companies request confidential treatment of the exhibit
pursuant to G.L. c. 25, ss. 5D. As grounds for this request, the companies state
that Exhibit 3 contains confidential information about employees and their
salaries and release to the public would unnecessarily reveal personal
information. Accordingly, the information in Exhibit 3 has been redacted from
the public filing.
2/Under our proposal, these savings are applied first to the cost of
the EUA acquisition and are then divided equally between customers and the
recovery of the acquisition costs resulting from the NEES-National Grid
transaction. Recovery of the EUA acquisition costs in accordance with the
Department's precedent, is a condition of the merger agreement. See Essex County
Gas Co., Docket D.T.E. 98-27 (1998).
<PAGE>
the competitive market for electricity supplies by lowering marketing and
transaction costs for suppliers and customers.
For the reasons set forth here and in the accompanying testimony, we
request the Department to grant the approvals and make the findings set forth in
the accompanying Petition. Thank you for your attention to our filing.
Very truly yours,
/s/ Thomas G. Robinson
----------------------------------------
Thomas G. Robinson
Attorney for New England Electric System
and its subsidiaries,
Massachusetts Electric Company and
New England Power Company
/s/ David A. Fazzone
----------------------------------------
David A. Fazzone of
David A. Fazzone, P.C. and
McDermott, Will & Emery
Attorney for Eastern Utilities Associates
and its subsidiaries,
Eastern Edison Company and
Montaup Electric Company
cc: George B. Dean, Esq.
Robert F. Sydney, Esq.
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- ---------------------------------------------
)
Massachusetts Electric Company and )
New England Power Company, subsidiaries of )
NEW ENGLAND ELECTRIC SYSTEM )
)
and ) Docket D.T.E. 99-___
)
Eastern Edison Company and )
Montaup Electric Company, subsidiaries of )
EASTERN UTILITIES ASSOCIATES )
- ---------------------------------------------)
PETITION FOR APPROVAL OF MERGERS,
FINANCINGS, AND RETAIL RATE PLAN
By this Petition, Massachusetts Electric Company ("Mass. Electric"),
New England Power Company ("NEP"), Eastern Edison Company ("Eastern"), and
Montaup Electric Company ("Montaup") (together the "Petitioners") request the
Department of Telecommunications and Energy ("Department") to:
1. Approve Eastern's merger into Mass. Electric pursuant to G.L. c.
164, section 96;
2. Provide, pursuant to G.L. c. 164, section 96, confirmation and
authorization of the rights and franchises of Mass. Electric to
carry on its business in all cities and towns in which Eastern is
now doing an electric business, and find that further action of
the Commonwealth of Massachusetts under G.L. c. 164, section 21
is not required to consummate the merger;
3. Approve Montaup's merger into NEP pursuant to G.L. c. 164,
section 96;
4. Provide, pursuant to G.L. c. 164, section 96, confirmation and
authorization of the rights and franchises of NEP to carry on its
business in all cities and towns in which Montaup is now doing an
electric business, and find that further action of the
Commonwealth of Massachusetts under G.L. c. 164, section 21 is
not required to consummate the merger;
<PAGE>
5. Approve Mass. Electric's and NEP's increase in capital stock to
the extent necessary pursuant to G.L. c. 164, section 99;
6. Approve the disposition of Montaup's securities by Eastern to the
extent necessary pursuant to G.L. c. 164, section 9A;
7. Approve the issuance of preferred stock, bonds, or other
evidences of indebtedness by Mass. Electric to the extent
necessary pursuant to G.L. c. 164, sections 14, 15, 15A, 16, 18
and 19.
8. Approve the amendments to the NEES Moneypool to permit the
participation by Eastern, Montaup, and their affiliates in EUA in
the NEES Moneypool pursuant to G.L. c. 164, section 17A.
9. Approve Mass. Electric's assumption of Eastern's obligations and
NEP's assumption of Montaup's obligations to the extent necessary
pursuant to G.L. c. 164, section 14; and
10. Approve the rate plan proposed for Mass. Electric and Nantucket
Electric Company after the merger with Eastern detailed in the
accompanying filing, including the recovery of the acquisition
premium and transaction costs as set forth in the filing, the
service quality standards, the accounting changes, and the
treatment of the funds for environmental response costs and
extraordinary storm costs pursuant to G.L. c. 164, section 94.
In support of this Petition, Petitioners state the following:
1. The Petitioners are all electric companies in Massachusetts as
defined pursuant to G.L. c. 164, section 1, and are subject to the Department's
jurisdiction;
2. Mass. Electric and NEP are subsidiaries of New England Electric
System ("NEES"), and Eastern and Montaup and subsidiaries of Eastern Utilities
Associates ("EUA");
3. On February 1, 1999, NEES and EUA agreed to the acquisition of EUA
by NEES;
<PAGE>
4. Following that acquisition, the Petitioners plan is for Eastern to
merge into Mass. Electric, and Montaup to merge into NEP following votes of the
holders of at least two thirds of each class of stock outstanding and entitled
to vote on the question of each of the companies;
5. Following its merger with Eastern, Mass. Electric intends to
implement the rate plan documented in the accompanying filing; and
6. The consummation of the mergers and rate plan requires the
Department's approvals as set forth at the outset of this Petition and
documented in the accompanying testimony.
For the reasons stated in the accompanying filing, the Petitioners
request the Department to grant the approvals and make the findings set forth at
the outset of this Petition.
Respectfully submitted,
MASSACHUSETTS ELECTRIC COMPANY
NEW ENGLAND POWER COMPANY
By its attorney,
/s/ Thomas G. Robinson
-------------------------------------
Thomas G. Robinson
25 Research Drive
Westborough, MA 01582
(508) 389-2877
EASTERN EDISON COMPANY
MONTAUP ELECTRIC COMPANY
By its attorney,
/s/ David A. Fazzone
----------------------------------------
David A. Fazzone, Esq. of
David A. Fazzone, P.C., and
McDermott, Will & Emery
28 State Street
Boston, MA 02109-1775
(617) 535-4016
April 30, 1999
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
MICHAEL E. JESANIS
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
MICHAEL E. JESANIS
Table of Contents
Page
I. Qualifications........................................................1
II. Purpose of Testimony and Summary of Filing............................2
III. Terms, Conditions, and Structure of the Transaction...................6
IV. Rate Plan.............................................................8
1. Rate Consolidation...........................................8
2. Distribution Rate Freeze.....................................9
a. NEES-EUA: Two-Year Extension.............10
b. NEES-National Grid: An Additional
Two Year Extension........................12
3. Service Quality Plan........................................14
4. Recovering the Costs of Consolidation.......................15
V. Benefits Created by the NEES Acquisition of EUA......................21
VI. The Acquisition Premium and Transaction Costs........................30
VII. Compliance With Department's Merger Standards........................38
VIII. Other Regulatory Approvals...........................................39
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 1 of 40
<S> <C>
1 I. Qualifications.
2 Q. Please state your name and business address.
3 A. Michael E. Jesanis, 25 Research Drive, Westborough, Massachusetts.
4
5 Q. By whom are you employed and what is your position?
6 A. I am Senior Vice President and Chief Financial Officer of New England Electric System
7 ("NEES"). I am also Vice President of New England Power Company ("NEP"), The
8 Narragansett Electric Company ("Narragansett"), and New England Power Service
9 Company ("NEPSCO").
10
11 Q. Please summarize your professional and educational background.
12 A. I joined the NEES companies in 1983 as a financial analyst and was elected Treasurer of
13 NEES in 1992. I was elected a Vice President of NEES in 1997 and Senior Vice
14 President and Chief Financial Officer effective March 1, 1998. I earned bachelor's and
15 master's degrees in mathematics from Clarkson College of Technology and a master of
16 business administration degree from the Wharton School at the University of
17 Pennsylvania.
18
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 2 of 40
1 Q. Have you previously testified before any regulatory commission?
2 A. Yes. I have testified before the Department of Telecommunications and Energy
3 ("Department"), the Rhode Island Public Utilities Commission, the New Hampshire Public
4 Utilities Commission, and the Federal Energy Regulatory Commission.
5
6 II. Purpose of Testimony and Summary of Filing.
7 Q. What is the purpose of this filing?
8 A. On February 1, 1999, NEES, Eastern Utilities Associates ("EUA"), and Research Drive
9 LLC ("Research Drive"), a directly and indirectly wholly owned subsidiary of NEES
10 entered into an Agreement and Plan of Merger ("EUA Agreement"). This filing requests
11 certain approvals which are necessary for consummation of the EUA acquisition.
12
13 Q. Please describe the companies involved in this transaction?
14 A. NEES is a registered holding company under the Public Utility Holding Company Act of
15 1935 ("Holding Company Act") and owns the common equity of several electric utility
16 companies, including Massachusetts Electric Company and Nantucket Electric Company
17 (together "Mass. Electric"), NEP, Granite State Electric Company ("Granite State"), and
18 Narragansett. NEES has entered into an agreement to merge with National Grid Group
19 ("National Grid"), completion of which is awaiting regulatory approvals.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 3 of 40
1 EUA is also a registered holding company under the Holding Company Act and
2 owns directly or indirectly the common equity of several electric utility companies,
3 including Eastern Edison Company ("Eastern"), Montaup Electric Company
4 ("Montaup"), Blackstone Valley Electric Company ("Blackstone Valley") and Newport
5 Electric Corporation ("Newport").
6
7 Q. What approvals are being sought from the Department?
8 A. This filing requests Department approval of a number of transactions necessary to
9 consummate the acquisition of EUA. These transactions include:
10 1) the merger of Mass. Electric and Eastern, including the issuances of securities
11 pertaining to such merger;
12 2) the merger of NEP and Montaup, including the issuances of securities pertaining
13 to such merger;
14 3) amendments to the NEES Moneypool, an agreement among NEES companies that
15 allows daily borrowings between companies, to allow participation by EUA and
16 its subsidiaries for the period between the closing of the NEES-EUA merger and
17 the mergers of the operating companies;
18 4) the implementation of a rate plan for the combined Mass. Electric/Eastern which
19 incorporates recovery the acquisition premium paid to acquire EUA and a
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 4 of 40
1 mechanism for recovering a portion of the premium paid by National Grid to
2 acquire NEES, which has allowed this transaction to move forward; and
3 5) approval of service quality standards, certain accounting changes, and
4 amendments to Mass. Electric storm and hazardous waste funds.
5
6 Q. What issues will your testimony address?
7 A. NEES and EUA believe that this transaction provides significant benefits for our
8 constituencies, is in the public interest, and meets the standards for approval by the
9 Department. I will explain the structure and terms of the NEES-EUA merger and
10 summarize our plan for consolidating the NEES and EUA operating companies, moving
11 Eastern's customers to Mass. Electric's lower rates, and freezing Mass. Electric's
12 distribution rates to all customers in the combined companies. I then describe the
13 benefits of the merger and rate plan for customers, employees, and shareholders, and
14 describe the regulatory approvals necessary to implement the transaction. Finally, I
15 address the transaction and acquisition costs associated with the transaction and explain
16 our plans for allocating these costs among the NEES and EUA operating companies and
17 addressing them in the ratemaking process.
18
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 5 of 40
1 Q. Who else is supporting the filing?
2 A. In addition to my testimony, Robert G. Powderly, Executive Vice President of EUA, will
3 discuss the reasons behind EUA's decision to be acquired by NEES. The service quality
4 improvements and longer term benefits of the merger are discussed by Lawrence J.
5 Reilly, President and Chief Executive Officer of Mass. Electric. Mr. Reilly describes the
6 integration process now underway between the two companies and the goals for
7 developing both efficiency gains and service quality improvements through development
8 of best practices. He also describes the service quality plan for Mass. Electric and
9 Eastern following the consolidation. Jennifer K. Zschokke, Manager of Finance, explains
10 the corporate consolidations of the operating companies and the resulting financing
11 savings from those consolidations, and our request for the Department's approval of the
12 amendments to the NEES Moneypool.
13 David M. Webster, Principal Financial Analyst with the NEES companies,
14 addresses the accounting issues associated with the combination of the two companies,
15 including for example, the development of consistent depreciation schedules and accruals
16 for accounting purposes. He also supports our requested amendments to the storm and
17 hazardous waste funds following the Mass. Electric and Eastern merger. Theresa M.
18 Burns, Principal Rate Analyst for the NEES companies, and James J. Bonner, Manager of
19 Retail Pricing and Rate Administration for the EUA companies, support the rate plan
20 following the consolidation of the operating companies. Their testimonies document the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 6 of 40
1 rates and rate mapping associated with consolidating the NEP and Montaup transmission
2 rates and contract termination charges, and moving Eastern's customers onto Mass.
3 Electric's rates.
4 Finally, David J. Hoffman and Richard J. Levin of Mercer Management
5 Consulting provide the analysis of synergies and savings that were identified as part of
6 our analysis leading to the merger decision. These savings support the recovery of the
7 acquisition premium and transaction costs associated with the merger.
8
9 III. Terms, Conditions, and Structure of the Transaction.
10 Q. Mr. Jesanis, would you please summarize the transaction between NEES and EUA?
11 A. The transaction is set forth in the merger agreement included as Exhibit MEJ-1. Pursuant
12 to the EUA Agreement, Research Drive will merge with and into EUA with EUA
13 becoming a wholly owned subsidiary of NEES. EUA shareholders will receive $31 per
14 share in cash, which will be increased at a rate of $.003 each day beginning six months
15 after EUA shareholder approval of the EUA acquisition. The merger agreement contains
16 terms and conditions which are typical to a merger transaction. Closing of the merger is
17 subject to obtaining approval of EUA shareholders and obtaining required regulatory
18 approvals.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 7 of 40
1 Q. How will the acquisition affect EUA's utility subsidiaries?
2 A. At the time of closing, there will be no immediate impact on EUA's utility subsidiaries.
3 For example, Eastern, currently a subsidiary of EUA, will remain so, with EUA
4 becoming a subsidiary of NEES. However, as soon as practicable thereafter, we intend to
5 merge the operating companies of EUA with the operating companies of NEES. We
6 propose that Eastern merge with Mass. Electric, Montaup merge with NEP, and
7 Blackstone Valley and Newport merge with Narragansett. Finally, we expect to combine
8 the operations of the two service companies, NEPSCO and EUA Service Corporation.
9 Therefore, with the exception of the addition of EUA's unregulated companies, the
10 corporate structure resulting from completion of the operating company consolidations
11 will look essentially the same as the current NEES corporate structure. A diagram
12 showing the proposed corporate structures immediately after the acquisition of EUA and
13 after the later consolidation of the operating companies is provided in Exhibit MEJ-2.
14 Even though the consolidation of the operating utility subsidiaries will occur after
15 NEES's acquisition of EUA, we are requesting the Department's approval of all steps and
16 financings necessary to complete the full consolidation of EUA and the utility
17 subsidiaries as well as the proposed rate plan for the consolidation of Mass. Electric and
18 Eastern customers.
19
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 8 of 40
1 IV. Rate Plan.
2 Q. Please describe the proposed rate plan for Mass. Electric and Eastern customers following
3 the merger.
4 A. The rate plan has four elements. First, we propose to put all Eastern customers on Mass.
5 Electric's rates on January 1, 2001. Second, we propose to freeze the distribution
6 component of the rates for the combined Mass. Electric/Eastern for up to four years after
7 January 1, 2001. Third, we will implement service quality standards for the combined
8 company. Finally, we propose a mechanism to recover the acquisition premium for the
9 NEES-EUA transaction and a portion of the acquisition for the NEES-National Grid
10 transaction. Each of these elements is discussed below.
11 1. Rate Consolidation. First, we propose to put all Eastern customers on Mass.
12 Electric's delivery rates effective with the first billing cycle in January, 2001.
13 When combined with the second element of the rate plan, the distribution rate
14 freeze, Eastern customers will save $23 million in 2001 or 14.2 percent of total
15 retail delivery service charges to Eastern's customers. See Exhibit MEJ-3, page 1.
16 Both Mass. Electric's and Eastern's delivery rates are composed of separate
17 charges for distribution, Renewables and Demand Side Management,
18 transmission, and transition. Under the proposed plan, Eastern's customers will
19 be placed directly on Mass. Electric's existing distribution rates. The individual
20 transmission expenses and contract termination charge costs that were billed from
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 9 of 40
1 NEP to Mass. Electric and from Montaup to Eastern before consolidation will be
2 blended into consolidated transmission and transition factors after the merger of
3 Mass. Electric and Eastern.
4 The consolidation reduces average rates to Eastern's customers by 14.2
5 percent. As shown on Exhibit MEJ-3, page 4, Mass. Electric's customers will
6 also experience a rate decrease in 2001. However, as the result of the averaging
7 of the contract termination charge, the transition component of Mass. Electric's
8 rates is higher than it would have been otherwise. This increase is offset in part
9 by the lower transmission factor that results from blending Montaup's lower
10 transmission charge with NEP's to arrive at a consolidated transmission rate
11 applicable to the combined Mass. Electric. The net result is a slight increase of
12 $0.00062 per kilowatthour or 1.4 percent to Mass. Electric's customers from the
13 rates that would have otherwise been charged in 2001. See Exhibit MEJ-3, pages
14 1 and 4.
15 2. Distribution Rate Freeze. The economic effect of this blending of the transition
16 charge is more than offset by the second component of the rate plan -- a
17 distribution rate freeze. The freeze is proposed for four years beyond the
18 distribution rate freeze in Mass. Electric's and Eastern's Restructuring Settlements
19 which expire on December 31, 2000. The freeze consists of the two extensions
20 discussed below.
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 10 of 40
1 a. NEES-EUA: Two-Year Extension. Mass. Electric commits as
2 part of the NEES-EUA transaction to freeze the distribution component of
3 its rates for two years beyond the rate freeze currently in place under
4 Mass. Electric's Restructuring Settlement in D.P.U./D.T.E. Docket No.
5 96-25. The distribution rate freeze will apply to both Mass. Electric's and
6 Eastern's customers under the consolidated rate plan. Thus, it provides
7 significantly greater benefits than the rate freeze in the Essex County Gas
8 Co. acquisition, Docket D.T.E. 98-27 (1998), that applied only to the rates
9 of the acquired company, Essex County Gas, but not its Massachusetts
10 affiliate, Boston Gas Company. As shown on Exhibit MEJ-4, page 1, line
11 4, the freeze produces lower average rates for Mass. Electric in 2002, more
12 than offsetting the effects associated with the blending of the transition
13 charge. As a result, total delivery rates to Mass. Electric's existing
14 customers are lower as the result of the merger in 2002, the second year of
15 the EUA rate freeze.
16 Under the Restructuring Settlement, the distribution component of
17 Mass. Electric's rates has been frozen since March 1, 1998. Through this
18 new commitment, the freeze will be extended from December 31, 2000
19 through December 31, 2002. This means that, if the EUA merger is
20 completed, distribution rates to Mass. Electric's customers, which are
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Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 11 of 40
1 among the lowest in the state, will have remained at the same level for
2 almost five years. The Company would retain only the ability to adjust
3 rates to reflect exogenous events occurring during the rate freeze period
4 such as changes to local, state, and federal tax laws, regulations or
5 precedents, and changes to accounting rules and practices. The return on
6 equity cap and floor in the restructuring settlement would not apply to the
7 extended rate freeze. Assuming distribution rates would have otherwise
8 increased at an inflation rate of 2.2 percent per annum, the cumulative
9 value of the rate plan for the customers of the consolidated Mass. Electric
10 is approximately $38 million through December 31, 2002. See Exhibit
11 MEJ-4, page 1, line 12.
12 The two year distribution rate freeze shares the savings from the
13 NEES-EUA merger. As described more fully later in my testimony, we
14 believe that the merger will allow the combined system to reduce annual
15 costs by $35 million. In contrast, the distribution rate freeze eliminates
16 two inflationary increases that would otherwise add $28 million additional
17 revenues to the base distribution charges of the combined companies.
18 Thus, the NEES-EUA merger allows us to meet and extend the rate
19 targets imposed as a result of industry restructuring and to continue to
20 confer substantial economic benefits on customers from regulated
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 12 of 40
1 operations following industry restructuring. These rate benefits from
2 regulated operations are in addition to the benefits produced by the
3 competitive retail market for power supplies that provided the rationale for
4 industry restructuring.
5 b. NEES-National Grid: An Additional Two Year Extension. We
6 intend to continue this pattern of savings from consolidations and
7 efficiency gains through the National Grid merger that was described to
8 the Department in our March 10, 1998 filing. We believe that the National
9 Grid merger will allow us to produce significant additional savings
10 through improved operations, further efficiency gains, the adoption of best
11 practices, and improved scale economies. To reflect and share these
12 anticipated savings, Mass. Electric proposes to extend the distribution rate
13 freeze an additional two years through December 31, 2004 contingent
14 upon the closing of the NEES-National Grid merger. This provides Mass.
15 Electric's customers price stability for regulated service for almost seven
16 years following the introduction of retail choice. The value of the rate
17 plan will grow to over $50 million per year by 2004 and will total
18 approximately $128 million over the rate freeze period. See Exhibit MEJ-
19 4, page 1, line 12.
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 13 of 40
1 The distribution rate freeze represents the most significant element
2 of these savings. As shown on page 2, lines 21 and 22 of Exhibit MEJ-4,
3 the savings associated with the distribution rate freeze total $45 million in
4 2004 and $106 million over the 4 year period. Because of the length of
5 the rate freeze and the potential that inflation may exceed current
6 projections by a significant amount, we propose to add an adjustment in
7 the event that inflation occurring during the extended rate freeze in
8 calendar years 2003 and 2004 exceeds 3.0 percent. Specifically, the
9 average distribution rate at the Consolidation Date is 2.549 cents per
10 kilowatthour as shown in Exhibit MEJ-3, page 1, line 4. This amount will
11 be adjusted by the actual inflation rate in accordance with the
12 methodology illustrated in Exhibit MEJ-5, which compares actual
13 inflation as measured by the Consumer Price Index Deflator - All Urban
14 Consumers ("CPI-U") to 3.0 percent, and adjusts distribution rates in
15 effect in 2003 for 75 percent of the excess over 3.0 percent. The
16 adjustment would be calculated at the end of September, 2002 prior to the
17 first year of the extended rate freeze, and the adjustment, if any, would
18 be rolled into distribution rates as a permanent increase. The process
19 would be followed again for the end of September, 2003 for the following year,
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 14 of 40
1 2004 which is the last year of the rate freeze. This adjustment would be in
2 addition to any adjustments for other exogenous factors.
3 3. Service Quality Plan. These distribution rate freezes confer substantial savings in
4 the price of regulated distribution service for Mass. Electric's customers. The
5 Department has made it clear that these savings should not come at the expense of
6 quality service. We agree. Mr. Reilly addresses in his testimony the service
7 quality plan that we will be implementing to maintain and improve service,
8 customer satisfaction, and reliability. These efforts will continue the
9 commitments of both Eastern and Mass. Electric to provide the best service in the
10 state at the lowest rates in the state.
11 Distribution service represents only 2.5 cents per kilowatthour of Mass.
12 Electric's current average rate. The significant savings from industry
13 restructuring lie in the power supply component of the bill. Standard Offer
14 Service provided by Mass. Electric ends in February 2005, two months after the
15 end of the proposed distribution rate freeze. At the time it ends, Mass. Electric's
16 base standard service charge will be 5.1 cents per kilowatthour. Our most
17 significant challenge over this period is to provide the infrastructure, billing, and
18 data transfer systems necessary for the supply market to provide the economic
19 benefits to customers that we all expect from industry restructuring. The mergers
20 with EUA and National Grid will provide us with the savings and financial
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Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 15 of 40
1 resources necessary to accomplish this task within the constraints of our current
2 rates. If we are successful, the savings from the competitive market will greatly
3 exceed the savings under the rate plan. Our customers will doubly benefit from
4 the mergers that we have proposed.
5 4. Recovering the Costs of Consolidation. The final element of the proposed rate plan
6 focuses on Mass. Electric's financial integrity and the rate setting process
7 following the period of the distribution rate freeze. As set forth later in my
8 testimony, there are significant costs associated with producing the savings that
9 stem from the consolidation of NEES and EUA and NEES and National Grid.
10 These costs for the NEES-EUA transaction are quantified in this filing and
11 compared directly to the savings from the consolidation. As I explain below, the
12 savings from the NEES-EUA consolidation exceed the acquisition premium and
13 the transaction costs of the NEES-EUA acquisition. As a result, the transaction
14 meets the Department's standards for merger approval, and the acquisition
15 premium and costs of the transaction should be recovered in rates. Accordingly,
16 we are proposing to amortize for ratemaking purposes the EUA acquisition
17 premium and transaction costs that are allocated to Mass. Electric over 20 years as
18 shown on Exhibit MEJ-6. We are also proposing to retain 50 percent of the
19 savings from the EUA acquisition above and beyond the amortization of the EUA
20 acquisition premium and transaction costs to recover a portion of the acquisition
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 16 of 40
1 premium and transaction costs paid by National Grid to acquire NEES.
2 The remaining 50 percent of the excess savings will flow through to customers
3 following the rate freeze producing a reduction in distribution rates over the level
4 that customers would have experienced absent the merger.
5
6 Q. How will the sharing mechanism work?
7 A. The annual savings from the consolidation of the companies will equal $35 million per
8 year in the first full year after the rate freeze. These savings are expected to grow by
9 inflation over the long term. Of this amount, we expect that approximately 72 percent or
10 $25.2 million will flow to the consolidated Mass. Electric. These savings provide the
11 basis for the sharing plan.
12 Under our plan, the future annual savings will be fixed and determined in this
13 proceeding. At the time of any future Mass. Electric distribution rate proceeding, Mass.
14 Electric would be allowed to include in its cost of service the annual amortization of the
15 EUA acquisition premium and transaction costs, because the annual amortization is less
16 than the savings produced by the merger. As shown in Exhibit MEJ-6, the Massachusetts
17 portion of the annual amortization expense for the EUA transaction is $16,421,000 for 20
18 years and zero thereafter. Under our proposal, the amortization would first be subtracted
19 from the annual savings and 50 percent of the remaining savings would then be applied to
20 recover the NEES-National grid acquisition premium and transaction costs. For example,
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 17 of 40
1 if the Department found that the EUA consolidation produced $35 million of annual
2 savings in 2005 when the distribution rate freeze ends, and that $25,176,000 would be
3 allocated to Mass. Electric, Mass. Electric could include in its first cost of service
4 following the rate freeze, an annual amortization of the EUA-NEES acquisition premium
5 equal to $16,421,000 plus one half of the remaining savings to apply against the NEES-
6 National Grid acquisition premium. Thus, 50 percent of $8,755,000 ($25,176,000 -
7 $16,421,000 = $8,755,000) equal to 4,377,500 would be applied against the National
8 Grid premium and transaction costs, and $4,377,500 will be reflected in a lower cost of
9 service.
10 The amount of savings available for the 50/50 sharing mechanism grows over
11 time as the savings grow by inflation, and amortization of the EUA acquisition premium
12 is eliminated after 20 years. Exhibit MEJ-7 illustrates the calculation based on an
13 assumed level of inflation equal to 2.2 percent, and shows the annual sharing amounts.
14 The actual level of sharing will be based on actual inflation experience over the period.
15 Under our proposal, except for the adjustment to reflect actual inflation, these amounts
16 would be fixed for the NEES-EUA transaction in this proceeding.
17
18 Q. Does the share of savings that is applied against the National Grid acquisition premium
19 and transaction costs match the amortization of the premium for accounting purposes?
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 18 of 40
1 A. No. As we have explained, the ratemaking treatment for the acquisition premium and
2 transaction costs is different from the accounting treatment. As with the EUA acquisition
3 premium and transaction costs, the National Grid acquisition premium and transaction
4 costs will be pushed down to the NEES companies, including Mass. Electric, and
5 amortized for accounting purposes over 20 years. The sharing mechanism postpones rate
6 recovery of the portion of the National Grid acquisition premium recovered through the
7 proposed sharing mechanism to a later period.
8
9 Q. What is the portion of the NEES-National Grid premium that is recovered through this
10 mechanism?
11 A. The present values of the savings from the NEES-EUA merger, the amortization of the
12 EUA acquisition premium and transaction costs, and the remaining savings are shown on
13 Exhibit MEJ-8. As that exhibit shows, the net present value of the Massachusetts portion
14 of the merger savings in excess of the EUA recovery is $249 million. Fifty percent of
15 this present value or $125 million is the recovery of the NEES-National Grid premium.
16 This amount will be deducted from the present value of the amortization of the NEES-
17 National Grid premium allocated to Mass. Electric and will not be recovered in any other
18 way.
19
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
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1 Q. Would this sharing mechanism be applied to future acquisitions?
2 A. Yes. Our goal is to generate further savings through future consolidations in the
3 Northeast. Under our plan, 50 percent of the savings in excess of the acquisition
4 premium and transaction costs allocated to Massachusetts customers will also be applied
5 to recover the NEES-National Grid acquisition premium and the transaction costs. As we
6 explained in the NEES-National Grid informational filing, the National Grid acquisition
7 of NEES is essential for the consolidation of other low cost utilities in the Northeast.
8 Even if these consolidations involve acquisitions outside of Massachusetts, savings will
9 flow to Mass. Electric automatically without any associated acquisition premium or
10 transaction costs. For example, as shown on Exhibit MEJ-8, a portion of the savings
11 from the EUA transaction is automatically flowing to New Hampshire customers, but the
12 acquisition costs are not, because EUA has no operations in New Hampshire. These
13 benefits are the direct result of this and future consolidations. If we successfully
14 implement other mergers in the future, Mass. Electric's customers will share the benefits
15 of these consolidations even if they occur outside of Massachusetts. As in this case,
16 Mass. Electric would demonstrate the savings and the sharing at the outset through a
17 synergy study.
18
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 20 of 40
1 Q. Would the 50 percent sharing apply to savings from ongoing efficiency gains?
2 A. No. Ongoing efficiencies will be generated through an array of activities beyond
3 consolidations. We propose to maintain flexibility to design incentives and sharing
4 mechanisms tailored to specific issues and problems. A simple sharing mechanism may
5 not produce the correct economic incentive for specific operations and programs. For
6 example, our DSM incentive has been based upon both a sharing the value produced by
7 the program and our performance and commitment to DSM programs. Other program-
8 specific incentive designs may be necessary in the future to encourage capital investment
9 to reduce operating costs, losses, or congestion, or to further specific public policy
10 objectives.
11
12 Q. Will there be a cap on recovery of the NEES-National Grid acquisition premium?
13 A. Yes. Mass. Electric's recovery will stop when the portion of the acquisition premium and
14 transaction costs associated with the National Grid transaction that is allocated to Mass.
15 Electric has been recovered. As explained above, the EUA transaction reduces the
16 present value of this recovery by $125 million. Future transactions will be applied to
17 reduce the premium in the same way. When the premium is fully offset, recovery of the
18 National Grid premium will cease.
19
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 21 of 40
1 V. Benefits Created by the NEES Acquisition of EUA
2 Q. Would you summarize the benefits created through the NEES acquisition of EUA?
3 A. The acquisition of EUA by NEES will result in the creation of substantial benefits which
4 can be used to provide improved service at lower rates to customers, greater opportunities
5 for employees, a premium to EUA shareholders, and an opportunity for NEES and
6 National Grid shareholders to earn reasonable returns on their investments in the
7 companies.
8 The benefits to customers will be delivered through the proposed rate plan
9 described above. These benefits are financed in part by the savings produced by the
10 NEES-EUA consolidation. The acquisition and consolidation produce synergies which
11 are typical of utility combinations. These synergies build on efficiencies already
12 achieved by Mass. Electric and Eastern, which are already the lowest cost utilities in the
13 state.
14
15 Q. How will the cost savings you described be achieved?
16 A. The cost savings will come from a variety of categories. Approximately 70 percent of the
17 savings will come from eliminating approximately 250 positions from the combined
18 organization. These reductions will come from across the organization. Administrative
19 areas such as accounting and finance, where significant redundancies exist between the
20 two companies, will be reduced. EUA's and NEES' customer service operations will be
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 22 of 40
1 integrated to handle increased volumes at a lower unit cost. The unit cost of field
2 operations will also be reduced through standardization and mutual support. The
3 remainder of the operating savings will come from disposing of duplicate facilities,
4 realizing greater purchasing power, and eliminating redundant administrative costs, such
5 as corporate governance expense. Mr. Hoffman testifies at length on these savings.
6
7 Q. What is your estimate of savings that will be achieved?
8 A. Based on the analysis performed by NEES and Mercer Management, the savings will be
9 about $31.1 million per year by the end of the distribution rate freeze period. For reasons
10 I describe below, I believe that the estimate developed by Mercer Management is
11 conservative and that we will achieve total savings of $35 million per year by the end of
12 the rate freeze period. These savings will grow with inflation over time. As shown on
13 Exhibit MEJ-8, the present value of the savings after amortization of the EUA acquisition
14 premium and transaction costs will be at least $356 million. Mass. Electric's share of that
15 amount is $249 million.
16
17 Q. Please describe the goals of the NEES/EUA integration process.
18 A. In my view, there are two overriding goals to the integration process. First, the
19 integration process is critical to achieving the efficiency gains upon which the transaction
20 was predicated. Second, it is equally important to combine the two organizations in a
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Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 23 of 40
1 way that maintains or improves service quality. The integration process is providing us
2 the opportunity to review our business practices to identify additional opportunities to
3 streamline operations. The integration process also provides us the opportunity to
4 compare business processes and adopt best practices where they can improve service to
5 customers.
6
7 Q. How is the integration effort organized?
8 A. Following the announcement of the NEES-EUA transaction, the two companies created a
9 transition team charged with consolidating the companies in a manner which creates more
10 cost savings than were assumed in the Mercer analysis. The transition team is led by
11 Thomas E. Rogers, Vice President and Director of Corporate Planning for NEPSCO, who
12 directed the sale of our non-nuclear generating business, and Mr. Powderly of EUA, who
13 was responsible for integration activities following EUA's acquisition of Newport
14 Electric. The transition team has formed over 60 individual sub-teams covering all
15 aspects of the business. Each of these teams is charged with the task of identifying
16 savings and efficiency gains.
17
18 Q. What is the schedule for the integration effort?
19 A. The various transition teams have been established and are meeting regularly. For
20 planning purposes, we are targeting October 1, 1999, as the completion date for the
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Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 24 of 40
1 process so that we will be ready to move forward with implementation as soon as the
2 necessary regulatory approvals are in hand.
3
4 Q. How do you expect that the integration efforts will lead to an improvement on Mercer's
5 estimate of $30 million in annual savings?
6 A. One example of my expectation of better performance is within administrative functions.
7 The Mercer analysis concluded that the combined NEES-EUA companies would need 18
8 percent more personnel in administrative functions than NEES presently has today when
9 the combined company has 22 percent more customers. Given that we will be merging
10 the operating companies into a structure that is nearly identical to NEES's structure, I do
11 not believe that we will need 18 percent more accountants, information systems
12 professional, lawyers and rate analysts when we have no more utility companies in our
13 holding company creating accounting statements, making rate filings or requiring
14 information system resources. Reducing the incremental administrative needs by half
15 will increase savings by $3-5 million per year at the end of the rate freeze. I further
16 believe that Mercer's estimates in customer service and distribution operations understate
17 the benefits we will achieve from the larger scale of the combined NEES-EUA system.
18
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 25 of 40
1 Q. Are there other savings that are not included in your analysis?
2 A. Yes. We believe that the NEES-National Grid merger will produce additional savings
3 and efficiency gains. We are now evaluating integration possibilities between NEES and
4 National Grid that will implement best practices. These efforts will produce savings for
5 NEES and for the newly acquired EUA companies. Equally important, we expect that
6 over time National Grid's significantly larger scale, both in financial and operational
7 terms, will enhance our ability to be at the leading edge of developments in transmission
8 and distribution technology, information systems and capital markets. The increased
9 expertise and resources will enhance our ability to provide customers of both NEES and
10 EUA with high quality transmission and distribution service at reasonable costs. The
11 benefits that will accrue to EUA from the NEES-National Grid integration process are not
12 reflected in our savings estimates for the NEES-EUA merger. Rather, the NEES-
13 National Grid savings will be demonstrated in a separate proceeding.
14 In addition, the savings study performed by Mr. Hoffman excludes certain cost
15 savings which are typically counted in other utility mergers. For example, most utility
16 mergers include as savings the costs of building one rather than two sets of new
17 information systems (usually customer or financial) at some time in the future. Both
18 NEES and EUA have older customer information systems. The cost of replacing these
19 systems would currently be in excess of $10 million per company. We did not include
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 26 of 40
1 these costs in our study because of the difficulty in pinpointing the timeframe in which
2 the savings will occur. Nevertheless, the savings are real and will provide future benefits.
3 Finally, as Ms. Zschokke testifies, we expect the higher credit ratings of the
4 NEES companies to lead to financing savings as the debt of the EUA companies is
5 refinanced over time.
6
7 Q. Can the annual savings included in your analysis be achieved absent the proposed
8 acquisition?
9 A. No. NEES and EUA have superb long-term records of managing costs. One measure of
10 this record is the rates charged to customers. As shown on Exhibit MEJ-9, NEES and
11 EUA customers in Massachusetts enjoy lower rates than the customers of any other
12 investor owned utility system in the Commonwealth. Residential customers of other
13 investor-owned utilities pay as much as 49% more than those of Mass. Electric and 33%
14 more than those of Eastern, and medium sized commercial customers pay as much as
15 66% more than Mass. Electric and 46% more than Eastern.
16 Another measure of cost efficiency is the number of employees required to serve
17 each 1,000 customers. Prior to the combination, NEES (at 2.4 employees/1,000
18 customers) and EUA (at 2.8 employees/1,000 customers) are significantly more efficient
19 than Boston Edison Company, the next largest utility in Massachusetts (which has 3.4
20 employees/1,000 customers). EUA's performance is particularly noteworthy because it
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 27 of 40
1 has achieved this record of performance despite the fact that it has less than half the
2 customers of Boston Edison. Both NEES and EUA have met their obligations to reduce
3 their costs on a stand alone basis. The combination of NEES, EUA and National Grid
4 represents the best opportunity to continue the track record of NEES and EUA in
5 controlling costs for the benefit of customers.
6
7 Q. How will EUA shareholders benefit from the combination?
8 A. The benefits to EUA shareholders stem from the consideration received for their shares at
9 closing. The base consideration of $31 per share is equal to 105 percent of the $29-1/16
10 market value of the shares on the last trading day before the merger was announced and
11 approximately 169 percent of EUA's book value per share of $18.29 as of December 31,
12 1998. The purchase is equal to a 23 percent premium over the market price on December
13 4, 1998, the last trading day before the BEC Energy-Commonwealth Energy merger was
14 announced. As explained earlier, the purchase price is subject to adjustment depending
15 on the timing of the closing. The purchase price will be paid in cash. Mr. Powderly
16 further describes the basis for EUA's conclusion that the price to be paid is fair to EUA
17 shareholders.
18
19 Q. Why did you use the December 4, 1998 closing price in determining the value to
20 shareholders?
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Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 28 of 40
1 A. Beginning on December 7, 1998 with the announcement of the BEC Energy -
2 Commonwealth Energy merger, EUA's share began rising substantially above the range
3 in which they had traded in recent months. Based on the long-term previous performance
4 of EUA shares in the market, I believe that this price appreciation is the result of
5 speculation that EUA would enter into some kind of merger agreement at a price
6 significantly higher than the trading price on December 4, 1998.
7
8 Q. What about the benefits to employees?
9 A. Although the merger is expected to reduce employment by about 250 positions in the
10 combined companies, we believe that these employee reductions can be achieved
11 predominantly through attrition or voluntary early retirement and without significant
12 involuntary layoffs. The efficiency gains are essential to the viability of our companies in
13 the restructured utility industry. For remaining employees, the merger and the NEES-
14 National Grid transaction represent a superb opportunity for growth as we move forward
15 as the United States base of operations for a large international group. The expanded
16 opportunities in this country will stem from National Grid's express intention to expand
17 and consolidate its operations here in this country. The fulfillment of this plan ensures
18 that NEES and EUA employees will remain active in the industry restructuring debate in
19 the United States. National Grid's expanding foreign operations will also provide
20 opportunities for employees abroad.
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 29 of 40
1 Q. Are NEES and EUA taking steps to mitigate the loss of positions following the NEES-
2 EUA merger?
3 A. Yes. In anticipation of the merger's approval, we have placed a limitation on hiring for
4 our company. The NEES companies expect to have a significant number of vacant
5 positions by the time the transaction closes. Natural attrition at EUA is expected to add
6 more positions. We are making every effort to leave these positions vacant until
7 employees affected by the acquisition have an opportunity to be considered for a position.
8 Beyond vacancies and attrition, we can economically offer 200 to 250 NEES and EUA
9 employees a voluntary early retirement program. Through these measures, we expect to
10 meet our workforce reduction targets without having a significant impact on individual
11 employees.
12 NEES has also agreed in the merger agreement to honor EUA's collective
13 bargaining agreements and to provide non-union employees joining the NEES companies
14 with compensation and benefits in the aggregate at least equivalent to those obtained
15 prior to the merger for a year following closing. EUA employees joining the NEES
16 system will find that the compensation and benefit philosophies of the two companies are
17 very similar, allowing us to merge benefit plans without significant disruption to
18 employees.
19
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Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 30 of 40
1 VI. The Acquisition Premium and Transaction Costs.
2 Q. What are the costs associated with NEES's acquisition of EUA?
3 A. NEES is acquiring EUA at a premium of approximately $260 million above the book
4 value of EUA's shares. The exact amount will be determined at closing based on EUA's
5 financial results prior to closing and any endorsements required to conform EUA's banks
6 of account to NEES practices. Because the acquisition of EUA is for cash, the conditions
7 for pooling of interest accounting are not met in this transaction and therefore, purchase
8 accounting must be used. Under Generally Accepted Accounting Principles ("GAAP")
9 for purchase accounting, the premium is recorded as goodwill on the acquired company's
10 accounts. The premium will be allocated to each of the EUA operating companies
11 following the closing and added to their balance sheets as goodwill. The goodwill will be
12 amortized over 20 years for ratemaking purposes.
13 In addition to the acquisition premium, we expect that the transaction costs and
14 the cost of integrating EUA into NEES and achieving our savings targets will be
15 approximately $64 million. Mr. Hoffman provides support for our cost estimates.
16
17 Q. How will these costs be allocated among the EUA subsidiaries?
18 A. A "fair value" study will be conducted around the time of closing the merger to
19 determine the allocation of the purchase price among the EUA subsidiaries. The
20 acquisition premium and transaction costs will be allocated in two steps. First, the
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New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 31 of 40
1 acquisition premium will be allocated to the unregulated subsidiaries based on the
2 difference between their market value and their book value. This adjustment brings the
3 value of the unregulated firms up to the value reflected in the acquisition. For the
4 purpose of this filing, we have estimated this allocation based on the underlying book
5 value of the unregulated firms. Because the book value of an unregulated enterprise does
6 not bear any direct relationship to its market value, the actual allocation will be
7 determined in the valuation study.
8 The second step of the analysis allocates the remainder of the acquisition premium
9 among the regulated companies. This analysis includes the allocation of the transaction
10 and integration costs which are in this transaction all related to regulated operations.
11 Because of the similar operating structures of NEES and EUA, we believe that savings
12 achieved by Mass. Electric/Eastern will approximate its size relative to the combined
13 Rhode Island companies. Therefore, we propose that the portion of the allocation
14 premium that is allocated to the regulated businesses be allocated between Eastern and
15 the two Rhode Island subsidiaries on the basis of a three-year average of kilowatthour
16 deliveries to Rhode island and Massachusetts customers of the consolidated utility
17 following the merger. The integration costs, which are entirely related to the regulated
18 subsidiaries, would be allocated among them in a similar manner.
19 This allocation matches the allocation of savings from the transaction, and the
20 economic value that is produced by the consolidation and reflected in the purchase price.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 32 of 40
1 Given that transmission and distribution remain regulated businesses priced at the cost of
2 providing service, the value added by the transaction is related to the underlying savings
3 produced by the consolidation. As the result of rate design and service company
4 allocations, these savings will generally be based on kilowatthour deliveries to retail
5 customers. The allocation of the acquisition premium and transaction costs follows this
6 methodology.
7
8 Q. Have you allocated any transaction costs or acquisition premium to Montaup/NEP?
9 A. Not in the analysis included in this filing. The primary savings associated with the EUA
10 transaction will be realized in distribution to retail delivery customers. Retail delivery
11 and its associated cost of service represent the bulk of the costs on the system and will
12 represent the most significant source of our savings, directly and indirectly through lower
13 administrative and general expense per customer service. This approach also matches the
14 allocation of the acquisition premium for other utilities whose transmission and
15 distribution rates remain unbundled in the same operating company.
16 Moreover, to the extent transmission savings exist, they will flow to retail
17 customers automatically through NEP's formula rate in proportion to Mass. Electric's
18 retail deliveries. NEP's transmission charges are based on demands at the time of NEP's
19 peak, and although NEP's rate includes deliveries to both affiliated and non-affiliated
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 33 of 40
1 customers, the allocation of acquisition costs parallels the kilowatthour allocation. Our
2 proposed allocation also maintains the Department's jurisdiction over the issue.
3 This approach also matches the allocation of the acquisition premium for other
4 utilities whose transmission and distribution rates remain bundled in the same operating
5 company.
6
7 Q. Do you have an estimate of the acquisition costs to be allocated to Eastern?
8 A. Yes. Eastern would be allocated $171,028,000 of acquisition premium which, when
9 adjusted for income taxes, produces a revenue requirement of $281,409,000. In addition
10 to this amount, Eastern would be allocated $47,007,000 of transaction costs producing a
11 total revenue requirement of $328,416,000. With a 20 year amortization period, the
12 annual revenue requirement is estimated at $16,421,000. This compares to about $25
13 million for Massachusetts' share of savings in the last year of the rate freeze. Exhibit
14 MEJ-6, page 1 illustrates the allocation of the costs of the transaction. The savings grow
15 with inflation over time, but the amortization of the acquisition premium and transaction
16 costs does not. As explained earlier, 50 percent of the excess of savings each year will be
17 applied to recover the NEES-National Grid premium, and following the rate freeze, the
18 remaining 50 percent of excess savings will be reflected in the cost of service to Mass.
19 Electric's customers.
20
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 34 of 40
1 Q. Please explain Mass. Electric's proposal to retain savings to pay the premium paid by
2 National Grid to acquire NEES.
3 A. As we described in the informational filing made with the Department describing the
4 National Grid-NEES merger, one of the benefits of the National Grid-NEES merger was the
5 facilitation of consolidation of transmission and distribution companies by low-cost
6 companies such as NEES. The benefits from NEES's acquisition of EUA are the first
7 step in realizing the vision behind the National Grid-NEES merger. Therefore, we are
8 proposing that a portion of the benefits from the NEES-EUA acquisition be shared
9 between customers and National Grid-NEES. The sharing mechanism we propose is fair
10 and efficient. It provides customers with $90 million of up-front value through the
11 extension of the rate freeze, (Exhibit MEJ-4, page 1, line 12 ($128,418,140 - $38,325,170
12 = $90,092,970)), and with matching savings throughout the remainder of the period. The
13 proposal puts the risk on the Company to realize the savings during the rate freeze period,
14 and significantly postpones the recovery for this portion of the National Grid premium.
15 In short, the proposal is fair and efficient. It assures that Mass. Electric's customers are
16 better off economically because of the merger with National Grid and EUA, and the
17 future consolidations that will be produced from our new, larger and more financially
18 sound organization.
19
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 35 of 40
1 Q. Wouldn't the benefits of the EUA acquisition be achieved without the National Grid-
2 NEES merger?
3 A. Without the National Grid-NEES merger, the full benefits of the EUA acquisition would
4 not be realized. First, it is unlikely that NEES would have agreed to acquire EUA at this
5 time absent the National Grid-NEES merger agreement. As described in NEES's proxy
6 statement dated March 26, 1999, over the course of 1998, the management and board of
7 directors of NEES determined that finding a strategic partner such as National Grid was
8 in the Company's best interest. As I have explained, the National Grid merger is
9 essential for a low cost utility like Mass. Electric to compete in the consolidation of the
10 industry. An agreement to acquire EUA by NEES prior to NEES finding a strategic
11 partner could have significantly impaired or delayed NEES's ability to find and reach
12 agreement with a strategic partner. Under these circumstances, an acquisition of EUA by
13 NEES would have been deferred for a year or longer and perhaps not have occurred at all.
14 Second, while EUA had alternatives to an acquisition by NEES, in my opinion,
15 those alternatives would not have produced the level of savings or the rate reductions to
16 EUA customers that can be achieved in this proposed acquisition. I believe that EUA's
17 alternatives generally involved mergers with or acquisitions by higher-cost regional
18 utilities. Those utilities do not possess the track record to operate their own service
19 territories at the efficiency levels of NEES or EUA. Therefore they cannot produce the
20 economic benefits by combining with EUA than NEES can achieve. In addition, to the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 36 of 40
1 extent savings are achieved, EUA customers are less likely to benefit from these savings
2 since they would most likely be applied to reducing the rates of the acquiring company.
3 EUA's customers could actually be faced with higher costs as the acquiring company
4 combined its higher cost operations with EUA's low-cost operations.
5 The EUA acquisition by NEES represents the first tangible benefits of the
6 National Grid-NEES merger. Therefore, a portion of the savings should be used to
7 compensate National Grid for its investment in NEES.
8
9 Q. Does the proposed rate plan have any potential accounting ramifications?
10 A. Yes. Presently, both NEES and EUA apply Financial Accounting Standard No. 71
11 (FAS 71) to their regulated operations. Pursuant to FAS 71, regulated entities are
12 required to record regulatory assets and liabilities to reflect certain differences between
13 accounting and ratemaking principles. If the NEES-EUA and NEES-National Grid
14 transactions are completed under the rate plan proposed in this docket, Mass.
15 Electric/Eastern and NEP/Montaup may be required to discontinue use of FAS 71,
16 effective upon consummation of the NEES-National Grid merger.
17
18 Q. Why might these companies be required to discontinue use of FAS 71?
19 A. In order to apply FAS 71, a regulated entity must meet certain criteria, including the
20 criteria that the entity's rates are based on its costs of service. It is my understanding that
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 37 of 40
1 in interpreting FAS 71, that the accounting profession considers long-term fixed rate
2 plans to be inconsistent with the criteria of FAS 71. The extension of our current rate
3 freeze by an additional four years may require Mass. Electric/Eastern to discontinue use
4 of FAS 71. In the case of NEP/Montaup, their ability to continue to use FAS 71 for costs
5 being recovered through contract termination charges depends on their continued
6 recovery as part of cost-based rates. Because the underlying distribution companies may
7 no longer qualify to use FAS 71, NEP/Montaup may also be required to discontinue use
8 of FAS 71.
9
10 Q. What impact would the discontinuation of FAS 71 have on the financial statements of
11 NEES's affected subsidiaries including Mass. Electric?
12 A. There are several principal impacts. First, in establishing the initial balance sheet of
13 Mass. Electric/Eastern and NEP/Montaup, following the consummation of the mergers,
14 regulatory assets would not be recognized. The impact of not recognizing regulatory
15 assets would be to increase the goodwill account by the amount of the regulatory assets.
16 In addition, because the operation of FAS 71 would be discontinued, future differences
17 between accounting and ratemaking principles would not lead to the creation of
18 regulatory assets and liabilities.
19 The discontinuation of FAS 71 could cause other differences in accounting to
20 occur as well. Mass. Electric/Eastern and NEP/Montaup have traditionally adhered to the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 38 of 40
1 accounting rules included in the FERC Uniform System of Accounts, which set of rules
2 have been adopted by the Department with limited exceptions. While those rules are in
3 most cases the same accounting rules followed by unregulated companies, there may be
4 some exceptions. For example, the companies would no longer record AFDC, but would
5 instead record capitalized interest calculated in accordance with accounting standards for
6 unregulated businesses.
7 In addition, while we have described previously the amount of goodwill that we
8 expect to be allocated to the companies and the amortization period for such goodwill for
9 ratemaking purposes, those amounts could differ for accounting purposes.
10
11 Q. Would the discontinuation of FAS 71 affect rates?
12 A. No. The recovery of regulatory assets today reflects ratemaking, rather than accounting
13 principles. While goodwill would be increased as a result of discontinuing FAS 71, the
14 definition of the acquisition premium to be recovered through rates would not include
15 goodwill resulting from regulatory assets otherwise being recovered through rates.
16
17 VII. Compliance With Department's Merger Standards.
18 Q. Is the merger consistent with the standards established by the Department for transactions
19 of this kind?
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 39 of 40
1 A. Yes. The Department set forth its merger standards in Docket 93-167-A, pp. 7-9 (1994)
2 and has recently applied them in Eastern Enterprises acquisition of Essex County Gas
3 Company, Essex County Gas Co., Docket D.T.E. 98-27, pp. 8-9 (1998) and in Northern
4 Indiana Public Service Company's acquisition of Bay State Gas Company, Bay State Gas
5 Co., Docket D.T.E. 98-31, pp. 9-10 (1998). In those orders, the Department established
6 several criteria for consideration. Mr. Powderly explains how this transaction and the
7 Eastern consolidation comply with the Department's standards.
8
9 VIII. Other Regulatory Approvals.
10 Q. Mr. Jesanis, what other regulatory approvals are necessary before the transaction can be
11 closed?
12 A. Federal approval is required from the SEC under the Holding Company Act. In addition,
13 the merger requires approval by FERC under Section 203 of the Federal Power Act.
14 FERC will also approve the consolidation of NEP and Montaup's transmission rates
15 under Section 205 of the Federal Power Act. A Nuclear Regulatory Commission
16 approval under the Atomic Energy Act, will be required to transfer Montaup's nuclear
17 entitlements to NEP as part of the merger. Approval of state commissions in Connecticut,
18 Vermont, and New Hampshire where Montaup owns property may also be required. The
19 Rhode Island Public Utilities Commission, like the Department, has direct jurisdiction
20 over the rate plan for the Rhode Island companies. The Rhode Island Division of Public
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of M. E. Jesanis
Page 40 of 40
1 Utilities and Carriers has jurisdiction over the consolidation of the Rhode Island
2 companies. Finally, the merger requires a Hart Scott Rodino filing with the Department
3 of Justice and the Federal Trade Commission. Our filings with the SEC and FERC will
4 be provided to the Department when they are made. The other filings will be provided on
5 request, except for the Hart Scott Rodino filing, which is treated confidentially.
6
7 Q. What is the estimated time schedule for those proceedings?
8 A. We hope to complete all regulatory proceedings on the merger this year and implement
9 the merger of NEES and EUA during the fourth quarter of this year. Consolidation of the
10 operating companies will be completed as soon as possible thereafter, and the rate plan
11 will be implemented on January 1, 2001 after the distribution rate freezes in both the
12 Mass. Electric and Eastern restructuring settlements expire.
13
14 Q. Does this complete your testimony?
15 A. Yes.
</TABLE>
<PAGE>
EXHIBITS OF M. E. JESANIS
MEJ-1 NEES-EUA Merger Agreement
MEJ-2 NEES-EUA: Simplified Corporate Organization, Post-Closing
MEJ-3 Rate Comparison for Eastern and Mass. Electric in 2001
MEJ-4 Economic Impact of Rate Freeze Extensions
MEJ-5 Illustration of Calculation of Inflation Adjustment to
Distribution Rates in 2003 and 2004
MEJ-6 Eastern Acquisition Premium and Transaction Cost Amortization
MEJ-7 Sharing of Savings Following NEES/EUA Merger
MEJ-8 Present Value Analysis of Acquisition Costs and Savings from
NEES-EUA Consolidation
MEJ-9 Rate Comparison by Utility
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-1
Exhibit MEJ-1
NEES-EUA Merger Agreement
See Separate Volume
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-2
Exhibit MEJ-2
NEES-EUA Simplified Corporate Organization, Post-Closing
<PAGE>
Exhibit MEJ-2
Simplified Corporate Structure
for Regulated Operating Companies
(Plan for Full Consolidation)
------------------------------------------------------
-----------------------
| National Grid |
| Group |
-----------------------
| |
|
| |
|
| |
---------- -----------
| NEES | <- - - - - - - - - - - - - - - - - -| EUA |
---------- -----------
| | |
| | ---------------|
| | ----------------- -------------------- |
| |----| Mass. Electric | < - - | Eastern Edison | ------ |
| | ----------------- -------------------- |
| | | |
| | | |
----------- | | --------------- ----------- |
| Granite | | |----| New England | < - - | Montaup | |
| State |---| | Power | ----------- |
| Electric | | -------------- - - - - - - - - - - - |
----------- | | -------------------- | |
| | | Blackstone Valley |- |--|
| --------------- | -------------------- | |
|----| Narragansett | < - - -| | |
--------------- | ------------- | |
| | Newport |-----------|--|
| -------------- |
- - - - - - - - -
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-3
Exhibit MEJ-3
Rate Comparison for Eastern and Mass. Electric in 2001
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\Mej-3rev.wk4 New England Electric System
PAGE 1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit MEJ-3, Revised
Page 1 of 4
Massachusetts Electric Company
Eastern Edison Company
Effect on Individual Billing Components in 2001
Mass. Electric Eastern Total
-------------- ------- -----
<S> <C> <C> <C>
DISTRIBUTION WITHOUT MERGER
(1) Average Rate 2.557 2.803 2.592
(2) Projected GWh Sales 17,131 2,803 19,934
------- ------ ------
(3) Revenue $438,039,670 $78,568,090 $516,607,760
- -------------------------------------------------------------------------------------------------------------------
DISTRIBUTION WITH MERGER
(4) Average Rate 2.502 2.838 2.549
(5) Projected GWh Sales 17,131 2,803 19,934
------- ------ ------
(6) Revenue $428,617,620 $79,549,140 $508,166,760
- --------------------------------------------------------------------------------------------------------------------
(7) BENEFIT TO TOTAL CUSTOMERS $9,422,050 ($981,050) $8,441,000
====================================================================================================================
TRANSMISSION WITHOUT MERGER
(8) Average Rate 0.559 0.291 0.521
(9) Projected GWh Sales 17,131 2,803 19,934
------- ------ ------
(10) Revenue $95,762,290 $8,156,730 $103,919,020
- --------------------------------------------------------------------------------------------------------------------
TRANSMISSION WITH MERGER
(11) Average Rate 0.518 0.518 0.518
(12) Projected GWh Sales 17,131 2,803 19,934
------- ------ ------
(13) Revenue $88,738,580 $14,519,540 $103,258,120
- --------------------------------------------------------------------------------------------------------------------
(14) BENEFIT TO TOTAL CUSTOMERS $7,023,710 ($6,362,810) $660,900
====================================================================================================================
TRANSITION WITHOUT MERGER
(15) Average Rate 1.070 2.300 1.243
(16) Projected GWh Sales 17,131 2,803 19,934
------- ------ ------
(17) Revenue $183,301,700 $64,469,000 $247,770,700
- --------------------------------------------------------------------------------------------------------------------
TRANSITION WITH MERGER
(18) Average Rate 1.250 1.250 1.250
(19) Projected GWh Sales 17,131 2,803 19,934
------- ------ ------
(20) Revenue $214,137,500 $35,037,500 $249,175,000
- --------------------------------------------------------------------------------------------------------------------
(21) BENEFIT TO TOTAL CUSTOMERS ($30,835,800) $29,431,500 ($1,404,300)
====================================================================================================================
(22) TOTAL BENEFIT (COST) TO CUSTOMERS ($14,390,040) $22,087,640 $7,697,600
(23) TOTAL RETAIL DELIVERY RATE W/O MERGER (INCL. .370(CENT)DSM/RENEW) 4.556 5.764 4.726
(24) TOTAL RETAIL DELIVERY RATE W/ MERGER (INCL. .370(CENT)DSM/RENEW) 4.640 4.976 4.687
(25) % BENEFIT (COST) TO CUSTOMERS -1.84% 13.67% 0.82%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\Mej-3rev.wk4 New England Electric System
PAGE 2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit MEJ-3
Page 2 of 4
Massachusetts Electric Company
Eastern Edison Company
Effect on Individual Billing Components in 2001
<S> <C> <C>
(1) Mass. Electric: Exhibit TMB-1, Line (1) Eastern: Exhibit TMB-2, Revised, Line (1)
(2) Mass. Electric: Per NEP's December 1, 1998CTC Eastern: Per EUA's February 12, 1999 RVC Filing
Reconciliation Filing
(3) Line (1) x Line (2)
(4) Mass. Electric: Exhibit TMB-8, Revised, Line (1) Eastern: Exhibit TMB-9, Revised Line (1) and Exhibit TMB-7,
Revised, Total
Company Average Distribution Rate on Mass. Electric's
Distribution Rates
(5) Line (2)
(6) Line (4) x Line (5)
(7) Line (3) - Line (6)
(8) Mass. Electric: Exhibit TMB-1, Line (2) Eastern: Exhibit TMB-2, Revised, Line (2)
(9) Line (2)
(10) Line (8) x Line (9)
(11) Mass. Electric: Exhibit TMB-8, Revised Line (2) Eastern: Exhibit TMB-9, Revised, Line (2)
(12) Line (2)
(13) Line (11) x Line (12)
(14) Line (10) - Line (13)
(15) Mass. Electric: Exhibit TMB-1, Revised, Line (3) Eastern: Exhibit TMB-2, Revised, Line (3)
(16) Line (2)
(17) Line (15) x Line (16)
(18) Mass. Electric: Exhibit TMB-8, Revised, Line (3) Eastern: Exhibit TMB -9, Revised, Line (3)
(19) Line (2)
(20) Line (18) x Line (19)
(21) Line (17) - Line (20)
(22) Line (7) + Line (14) + Line (21)
(23) Line (1) + Line (8) + Line (15)
(24) Line (4) + Line (11) + Line (18)
(25) [Line (23) - Line (24)] / Line (23)
</TABLE>
<PAGE>
Eastern Edison Company
Avg cents per kWh
Exhibit MEJ-3
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Four time periods, as listed below.
Y-axis (left side of chart): Average cents per kWh (listed in increments of 1
cent between and including 0 and 7 cents per kWh).
[Bar Chart lists five sets of rates for Eastern Edison Company (i) distribution,
(ii) DSM and Renewables, (iii) transmission, (iv) transition, and (iv) total
rates. Total rates equal the sum of distribution, DSM and Renewables,
transmission and transition rates.]
<TABLE>
<CAPTION>
Time DSM &
Period Distrib. Renew. Transmission Transition Total
<S> <C> <C> <C> <C> <C>
4/1999 2.74 0.41 0.30 2.10 5.55
2000 2.74 0.41 0.29 2.38 5.82
2001
Pre-Merger 2.80 0.37 0.29 2.30 5.76
2001
Post-Merger 2.84 0.37 0.52 1.25 4.98
</TABLE>
Future prices are subject to adjustment, but the total rates are capped in
accordance with the Massachusetts statute.
Page 3 of 4
<PAGE>
Massachusetts Electric Company
Avg cents per kWh
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Four time periods, as listed below.
Y-axis (left side of chart): Average cents per kWh (listed in increments of 1
cent between and including 0 and 6 cents per kWh).
[Bar Chart lists five sets of rates for Eastern Edison Company (i) distribution,
(ii) DSM and Renewables, (iii) transmission, (iv) transition, and (iv) total
rates. Total rates equal the sum of distribution, DSM and Renewables,
transmission and transition rates.]
<TABLE>
<CAPTION>
Time DSM &
Period Distrib. Renew. Transmission Transition Total
<S> <C> <C> <C> <C> <C>
3/1999 2.50 0.41 0.64 1.33 4.88
2000 2.50 0.41 0.55 1.32 4.78
2001
Pre-Merger 2.56 0.37 0.56 1.07 4.56
2001
Post-Merger 2.50 0.37 0.52 1.25 4.64
</TABLE>
Future prices are subject to adjustment, but the total rates are capped in
accordance with the Massachusetts statute.
Page 4 of 4
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-4
Exhibit MEJ-4
Economic Impact of Rate Freeze Extensions
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\Mej-4rev.wk4 New England Electric System
SUMMARY Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit MEJ-4, Revised
Page 1 of 4
Massachusetts Electric Company
Eastern Edison Company
Effects of Merger and Rate Consolidation
Benefit (Cost) to Customers
2001 2002 2003 2004 Total
---- ---- ---- ---- -----
<S> <C> <C> <C> <C> <C>
MASS. ELECTRIC
(1) Distribution $9,422,050 $19,257,390 $29,573,040 $40,671,590 $98,924,070
(2) Transmission $7,023,710 $7,286,580 $7,569,290 $7,883,480 $29,763,060
(3) Transition ($30,835,800) ($27,758,400) ($19,363,300) ($19,708,700) ($97,666,200)
------------ ------------ ------------ ------------ -----------
(4) Total Net Effect ($14,390,040) ($1,214,430) $17,779,030 $28,846,370 $31,020,930
(5) Cumulative Net Effect ($14,390,040) ($15,604,470) $2,174,560 $31,020,930
-----------------------------------------------------------------------------------------------------
EASTERN
(6) Distribution ($981,050) $765,450 $2,590,200 $4,509,120 $6,883,720
(7) Transmission ($6,362,810) ($6,577,200) ($6,820,860) ($7,085,760) ($26,846,630)
(8) Transition $29,431,500 $28,066,500 $21,009,400 $18,739,200 $97,246,600
----------- ----------- ----------- ----------- -----------
(9) Total Net Effect $22,087,640 $22,254,750 $16,778,740 $16,162,560 $77,283,690
(10) Cumulative Net Effect $22,087,640 $44,342,390 $61,121,130 $77,283,690
-----------------------------------------------------------------------------------------------------
COMBINED MASS. ELECTRIC
(11) Total Net Effect $7,697,600 $21,040,320 $34,557,770 $45,008,930 $108,304,620
(12) Cumulative Net Effect $7,697,600 $28,737,920 $63,295,690 $108,304,620
</TABLE>
(1) Page 2, Line (3) - Line (13)
(2) Page 3, Line (3) - Line (13)
(3) Page 4, Line (3) - Line (13)
(4) Line (1) + Line (2) + Line (3)
(5) Accumulation of Line (4)
(6) Page 2, Line (7) - Line (17)
(7) Page 3, Line (7) - Line (17)
(8) Page 4, Line (7) - Line (17)
(9) Line (6) + Line (7) + Line (8)
(10) Accumulation of Line (9)
(11) Line (4) + Line (9)
(12) Accumulation of Line (11)
<PAGE>
<TABLE>
<CAPTION>
C:\eua files on disk\Mej-4rev.wk4 New England Electric System
DISTRIBUTION Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit MEJ-4, Revised
Page 2 of 4
Massachusetts Electric Company
Eastern Edison Company
Estimated Value of Distribution Rate Freeze
Over 4 Additional Years
2001 2002 2003 2004 Cumulative
---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C>
DISTRIBUTION WITHOUT MERGER
MASS. ELECTRIC
(1) Average Distribution Rate 2.557 2.613 2.670 2.729
(2) Projected GWh Sales 17,131 17,349 17,603 17,917
------ ------ ------ ------
(3) Revenue $438,039,670 $453,329,370 $470,000,100 $488,954,930 $1,850,324,070
(4) Cumulative Revenue $438,039,670 $891,369,040 $1,361,369,140 $1,850,324,070
EASTERN
(5) Average Distribution Rate 2.803 2.865 2.928 2.992
(6) Projected GWh Sales 2,803 2,835 2,878 2,928
----- ----- ----- -----
(7) Revenue $78,568,090 $81,222,750 $84,267,840 $87,605,760 $331,664,440
(8) Cumulative Revenue $78,568,090 $159,790,840 $244,058,680 $331,664,440
TOTAL OF INDIVIDUAL COMPANIES
(9) Total Revenue $516,607,760 $534,552,120 $554,267,940 $576,560,690 $2,181,988,510
(10) Cumulative Total Revenue $516,607,760 $1,051,159,880 $1,605,427,820 $2,181,988,510
- --------------------------------------------------------------------------------------------------------------------------
DISTRIBUTION WITH MERGER
MASS. ELECTRIC
(11) Average Distribution Rate 2.502 2.502 2.502 2.502
(12) Projected GWh Sales 17,131 17,349 17,603 17,917
------ ------ ------ ------
(13) Revenue $428,617,620 $434,071,980 $440,427,060 $448,283,340 $1,751,400,000
(14) Cumulative Revenue $428,617,620 $862,689,600 $1,303,116,660 $1,751,400,000
EASTERN
(15) Average Distribution Rate 2.838 2.838 2.838 2.838
(16) Projected GWh Sales 2,803 2,835 2,878 2,928
----- ----- ----- ----
(17) Revenue $79,549,140 $80,457,300 $81,677,640 $83,096,640 $324,780,720
(18) Cumulative Revenue $79,549,140 $160,006,440 $241,684,080 $324,780,720
TOTAL OF INDIVIDUAL COMPANIES
(19) Total Revenue $508,166,760 $514,529,280 $522,104,700 $531,379,980 $2,076,180,720
(20) Cumulative Total Revenue $508,166,760 $1,022,696,040 $1,544,800,740 $2,076,180,720
- --------------------------------------------------------------------------------------------------------------------------
BENEFIT TO ALL CUSTOMERS
(21) Annual $8,441,000 $20,022,840 $32,163,240 $45,180,710 $105,807,790
----------- -----------
(22) Cumulative $8,441,000 $28,463,840 $60,627,080 $105,807,790
----------- -----------
- --------------------------------------------------------------------------------------------------------------------------
(1) Exhibit TMB-1, Line (1) (12) Per NEP's December 1, 1998 CTC Reconciliation Filing
(2) Per NEP's December 1, 1998 CTC Reconciliation Filing (13) Line(11) x Line (12)
(3) Line (1) x Line (2) (14) Accumulation of Line (13)
(4) Accumulation of Line (3) (15) Consolidated Rate Frozen for 5 years
(5) Exhibit TMB-2, Line (1) (16) Per EUA's February 12, 1999 RVC Filing
(6) Per EUA's February 12, 1999 RVC Filing (17) Line (15) x Line (16)
(7) Line (4) x Line (5) (18) Accumulation of Line (17)
(8) Accumulation of Line (7) (19) Line (13) + Line (17)
(9) Line (3) + Line (7) (20) Accumulation of Line (19)
(10) Accumulation of Line (9) (21) Line (9) - Line (19)
(11) Consolidated Rate Frozen for 5 years (22) Accumulation of Line (21)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\eua files on disk\Mej-4rev.wk4 New England Electric System
TRANSMISSION Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit MEJ-4, Revised
Page 3 of 4
Massachusetts Electric Company
Eastern Edison Company
Estimated Value of Combined Transmission Costs
Over 4 Years
2001 2002 2003 2004 Cumulative
---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C>
TRANSMISSION WITHOUT MERGER
MASS. ELECTRIC
(1) Average Transmission Rate 0.559 0.571 0.584 0.597
(2) Projected GWh Sales 17,131 17,349 17,603 17,917
------ ------ ------ ------
(3) Revenue $95,762,290 $99,062,790 $102,801,520 $106,964,490 $404,591,090
(4) Cumulative Revenue $95,762,290 $194,825,080 $297,626,600 $404,591,090
EASTERN
(5) Average Transmission Rate 0.291 0.297 0.304 0.311
(6) Projected GWh Sales 2,803 2,835 2,878 2,928
----- ----- ----- -----
(7) Revenue $8,156,730 $8,419,950 $8,749,120 $9,106,080 $34,431,880
(8) Cumulative Revenue $8,156,730 $16,576,680 $25,325,80 $34,431,880
TOTAL OF INDIVIDUAL COMPANIES
(9) Total Revenue $103,919,020 $107,482,740 $111,550,640 $116,070,570 $439,022,970
(10) Cumulative Total Revenue $103,919,020 $211,401,760 $322,952,400 $439,022,970
- --------------------------------------------------------------------------------------------------------------------------
TRANSMISSION WITH MERGER
MASS. ELECTRIC
(11) Average Transmission Rate 0.518 0.529 0.541 0.553
(12) Projected GWh Sales 17,131 17,349 17,603 17,917
------ ------ ------ ------
(13) Revenue $88,738,580 $91,776,210 $95,232,230 $99,081,010 $374,828,030
(14) Cumulative Revenue $88,738,580 $180,514,790 $275,747,020 $374,828,030
EASTERN
(15) Average Transmission Rate 0.518 0.529 0.541 0.553
(16) Projected GWh Sales 2,803 2,835 2,878 2,928
----- ----- ----- -----
(17) Revenue $14,519,540 $14,997,150 $15,569,980 $16,191,840 $61,278,510
(18) Cumulative Revenue $14,519,540 $29,516,690 $45,086,670 $61,278,510
TOTAL OF INDIVIDUAL COMPANIES
(19) Total Revenue $103,258,120 $106,773,360 $110,802,210 $115,272,850 $436,106,540
(20) Cumulative Total Revenue $103,258,120 $210,031,480 $320,833,690 $436,106,540
- --------------------------------------------------------------------------------------------------------------------------
BENEFIT TO ALL CUSTOMERS
(21) Annual $660,900 $709,380 $748,430 $797,720 $2,916,430
(22) Cumulative $660,900 $1,370,280 $2,118,710 $2,916,430
- --------------------------------------------------------------------------------------------------------------------------
(1) Exhibit TMB-1, Line (2) (12) Per NEP's December 1, 1998 CTC Reconciliation Filing
(2) Per NEP's December 1, 1998 CTC Reconciliation Filing (13) Line (11) x Line (12)
(3) Line (1) x Line (2) (14) Accumulation of Line (13)
(4) Accumulation of Line (3) (15) Consolidated Rate Frozen for 5 years
(5) Exhibit TMB-2, Revised, Line (2) (16) Per EUA's February 12, 1999 RVC Filing
(6) Per EUA's February 12, 1999 RVC Filing (17) Line (15) x Line (16)
(7) Line (4) x Line (5) (18) Accumulation of Line (17)
(8) Accumulation of Line (7) (19) Line (13) + Line (17)
(9) Line (3) + Line (7) (20) Accumulation of Line (19)
(10) Accumulation of Line (9) (21) Line (9) - Line (19)
(11) Exhibits TMB-8, Revised, and TMB-9, Revised, Line (22) Accumulation of Line (21)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\eua files on disk\Mej-4rev.wk4 New England Electric System
TRANSITION Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit MEJ-4, Revised
Page 4 of 4
Massachusetts Electric Company
Eastern Edison Company
Estimated Value of Combined Transition Charge
Over 4 Years
2001 2002 2003 2004 Cumulative
---- ---- ---- ---- ----------
<S> <C> <C> <C> <C> <C>
TRANSITION WITHOUT MERGER
MASS. ELECTRIC
(1) Transition Charge 1.070 1.070 1.000 0.940
(2) Projected GWh Sales 17,131 17,349 17,603 17,917
------ ------ ------ ------
(3) Revenue $183,301,700 $185,634,300 $176,030,000 $168,419,800 $713,385,800
(4) Cumulative Revenue $183,301,700 $368,936,000 $544,966,000 $713,385,800
EASTERN
(5) Transition Charge 2.300 2.220 1.840 1.690
(6) Projected GWh Sales 2,803 2,835 2,878 2,928
----- ----- ----- -----
(7) Revenue $64,469,000 $62,937,000 $52,955,200 $49,483,200 $229,844,400
(8) Cumulative Revenue $64,469,000 $127,406,000 $180,361,200 $229,844,400
TOTAL OF INDIVIDUAL COMPANIES
(9) Total Revenue $247,770,700 $248,571,300 $228,985,200 $217,903,000 $943,230,200
(10) Cumulative Total Revenue $247,770,700 $496,342,000 $725,327,200 $943,230,200
- ---------------------------------------------------------------------------------------------------------------------------
TRANSITION WITH MERGER
MASS. ELECTRIC
(11) Transition Charge 1.250 1.230 1.110 1.050
(12) Projected GWh Sales 17,131 17,349 17,603 17,917
------ ------ ------ ------
(13) Revenue $214,137,500 $213,392,700 $195,393,300 $188,128,500 $811,052,000
(14) Cumulative Revenue $214,137,500 $427,530,200 $622,923,500 $811,052,000
EASTERN
(15) Transition Charge 1.250 1.230 1.110 1.050
(16) Projected GWh Sales 2,803 2,835 2,878 2,928
----- ----- ----- -----
(17) Revenue $35,037,500 $34,870,500 $31,945,800 $30,744,000 $132,597,800
(18) Cumulative Revenue $35,037,500 $69,908,000 $101,853,800 $132,597,800
TOTAL OF INDIVIDUAL COMPANIES
(19) Total Revenue $249,175,000 $248,263,200 $227,339,100 $218,872,500 $943,649,800
(20) Cumulative Total Revenue $249,175,000 $497,438,200 $724,777,300 $943,649,800
- ---------------------------------------------------------------------------------------------------------------------------
BENEFIT TO ALL CUSTOMERS
(21) Annual (Difference due to ($1,404,300) $308,100 $1,646,100 ($969,500) ($419,600)
rounding vs. truncating
methodologies in CTC/RVC
calculations)
(22) Cumulative ($1,404,300) ($1,096,200) $549,900 ($419,600)
- ---------------------------------------------------------------------------------------------------------------------------
(1) Exhibit TMB-1, Line (3) (12) Per NEP's December 1, 1998 CTC Reconciliation Filing
(2) Per NEP's December 1, 1998 CTC Reconciliation Filing (13) Line (11) x Line (12)
(3) Line (1) x Line (2) (14) Accumulation of Line (13)
(4) Accumulation of Line (3) (15) Consolidated Rate Frozen for 5 years
(5) Exhibit TMB-2, Line (3) (16) Per EUA's February 12, 1999 RVC Filing
(6) Per EUA's February 12, 1999 RVC Filing (17) Line (15) x Line (16)
(7) Line (4) x Line (5) (18) Accumulation of Line (17)
(8) Accumulation of Line (7) (19) Line (13) + Line (17)
(9) Line (3) + Line (7) (20) Accumulation of Line (19)
(10) Accumulation of Line (9) (21) Line (9) - Line (19)
(11) Exhibits TMB-8 and TMB-9, Line (3) (22) Accumulation of Line (21)
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-5
Exhibit MEJ-5
Illustration of Calculation of Inflation Adjustment to
Distribution Rates in 2003 and 2004
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\Mej-5.wk4 New England Electric System
INFLAT ADJ 3 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit MEJ- 5
Page 1 of 1
Massachusetts Electric Company
Illustration of Calculation Inflation Adjustment to Distribution Rates
in 2003 and 2004
3% Annual Annual Benchmark Illustrative
Annual CPI Percentage Inflation in 75% of Distribution Distribution
End of Month Inflation Index Change Excess of 3% Excess Rate Adjustment
(1) (2) (3) (4) (5) (6) (7) (8)
<S> <C> <C> <C> <C> <C> <C> <C>
September 2001 136.6 2/
September 2002 140.9 2/
Annual Total 3.000% 1/ 3.148% 3/ 0.148% 4/ 0.111% 5/ 2.549 6/ 0.002 7/
September 2002 140.9 2/
September 2003 144.8 2/
Annual Total 3.000% 1/ 2.768% 3/ n/a 2.551 8/ n/a
- ----------------------------------------------------------------------------------------------------------------------------------
1/ Annual rate of 3% for inflation benchmark
2/ Historical Consumer Price Index - All Urban Consumers (CPI-U) obtained from the Bureau of Laor Statistics
3/ Percentage change between prior month's CPI-U and current month's CPI-U
4/ Difference between actual inflation (3/) and assumed inflation benchmark of 3% (1/)
5/ 75% x excess inflation in 4/
6/ Exhibit MEJ-3, Page 3
7/ 75% of excess inflation in 5/ multiplied by benchmark distribution rate in 6/
8/ Prior year net distribution charge (6/) + (7/) as current year's distribution benchmark
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-6
Exhibit MEJ-6
Eastern Acquisition Premium and Transaction Cost Amortization
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit MEJ-6
Page 1 of 3
NEES/EUA Acquisition Premium
Amortization of Acquisition Premium and Transaction Costs
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
Allocation to States 12/
--------------------------------
Massachusetts Rhode Island
Total (Eastern Edison)
<S> <C> <C> <C> <C>
1 ACQUISITION PREMIUMS: 100.00% 73.91% 26.09%
2 Total Acquisition Premium 1/ $260,000
3 Less: Allocation to Unregulated Subsidiaries 2/ 28,600
4 Net Acquisition Premium to Regulated Subsidiaries 3/ $231,400 $171,028 $60,372
5
6 Times Tax Gross-Up Factor 4/ 1.6454 1.5384
7
8 Acquisition Premium at Revenue Requirement 5/ $374,285 $281,409 $92,876
9
10 Amortization Period (Years) 6/ 20 20 20
11
12 Amortization per year for Acquisition Premiums 7/ $18,714 $14,070 $4,644
13
14
15 TRANSACTION COSTS:
16 Total Estimated Transaction Costs 8/ $63,600 $47,007 $16,593
17
18 Amortization Period (Years) 9/ 20 20 20
19
20 Amortization per year for Transaction Costs 10/ $3,180 $2,351 $829
21
22 TOTAL AMORTIZATION PER YEAR 11/ $21,894 $16,421 $5,473
Notes:
1/ Exhibit MEJ-6, Page 3, Line 15.
2/ Allocation of costs to unregulated subsidiaries. (Exhibit MEJ-6, Page 3, Line 35 times Line 2.)
3/ Line 1 minus Line 2.
4/ For Massachusetts: 1 plus Federal Income Tax (FIT) Rate divided by 1 minus FIT rate plus State Income Tax (SIT) rate divided
by 1 minus SIT rate divided by 1 minus FIT rate (1+(35%/(1-35%))+((6.5%/(1-6.5%)/(1-35%))). For Rhode Island: 1 plus Federal
Income Tax (FIT) Rate divided by 1 minus FIT rate. (1+(35%/(1-35%))).
5/ Line 4 times Line 6.
6/ Proposed amortization period for Acquisition Premiums.
7/ Line 8 divided by Line 10.
8/ Total Estimated Transaction costs to complete NEES/EUA merger.
9/ Proposed amortization period for Transaction Costs.
10/ Line 16 divided by Line 18.
11/ Line 12 plus Line 20.
12/ Exhibit MEJ-6, Page 2, Column (f).
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket ____
Exhibit MEJ-6
Page 2 of 3
NEES/EUA Acquisition Premium
Allocation of Acquisition Premium and Transaction Costs
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
1998 1997 1996 Total 3 Year Ave.
MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation
to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage
Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/
<S> <C> <C> <C> <C> <C> <C>
1 Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328
2 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938
3 Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 73.91%
4
5 Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333
6 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965
7 Newport Electric 542,466 536,209 525,372 1,604,047
8 Total Rhode I 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 26.09%
9
Grand Total 26,109,893 25,430,615 25,192,103 76,732,611 25,577,537 100.00%
Notes:
1/ 1998 FERC Form 1, Pages 300-301.
2/ 1997 FERC Form 1, Pages 300-301.
3/ 1996 FERC Form 1, Pages 300-301.
4/ Sum of Columns (a) through (c).
5/ Column (d) divided by three.
6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)).
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit MEJ-6
Page 3 of 3
NEES/EUA Acquisition Premium
Amortization of Acquisition Premium and Transaction Costs
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
<S> <C>
1 Calculation of Acquisition Premium:
2 Acquisition Price Per Share $31.00 1/
3
4 Outstanding EUA Common Shares
5 as of December 31, 1998 20,435,997 2/
6
7 Total Acquisition Cost $633,516 3/
8
9
10 EUA Consolidated Net Book Value
11 as of December 31, 1998 $373,674 4/
12
13 Total Acquisition Premium $259,842 5/
14
15 Total Acquisition Premium (Rounded) $260,000 6/
16
17
18 Calculation of Allocation to Unregulated Subsidiaries:
19
20 Net Book Value of Unregulated Subsidiaries as of
21 December 31, 1998:
22
23 EUA Cogenex $48,361
24 EUA Energy Inv. (24,204)
25 EUA Energy Services (34)
26 EUA Ocean State 16,546
27 EUA Telecommunications (131)
28 Total Net Book Value of Unregulated Subsidiaries 40,538 7/
29
30 Net Book Value of EUA Consolidated
31 as of December 31, 1998 (In Thousands) 373,674 8/
32
33 Percentage of Unregulated Subsidiaries to Total 10.85% 9/
34
35 Percentage (Rounded) 11.00% 10/
Notes:
1/ Acquisition Price per Share per NEES/EUA Merger Agreement.
2/ EUA common shares outstanding as of December 31, 1998 per EUA annual report.
3/ Line 2 times Line 5.
4/ Net Book Value (Common Equity) as of December 31, 1998 per EUA annual report before any adjustments required under purchase
accounting rules.
5/ Line 7 minus Line 11.
6/ Line 13 rounded to tens on millions.
7/ Net Book Value (Common Equity) as of December 31, 1998 before any adjustments required under purchase accounting rules.
8/ Net Book Value (Common Equity) as of December 31, 1998 before any adjustments required under purchase accounting rules.
9/ Line 28 divided by Line 31.
10/ Line 33 rounded to nearest whole percent.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-7
Exhibit MEJ-7
Sharing of Savings Following NEES/EUA Merger
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket ____
Exhibit MEJ-7
Page 1 of 1
NEES/EUA Acquisition Premium
Sharing of Savings following NEES/EUA Merger
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
Massachusetts Sharing of Net Savings
Massachusetts Apportionment ----------------------
Anticipated Apportionment of EUA Acquisition Massachusetts National Grid Massachusetts
Savings (71.93%) Premium Recovery Net Savings Premium Customers
Year Column (a) 1 Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/
---- ------------ ------------- ---------------- -------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
1 2005 $35,000 $25,176 $16,421 $8,755 $4,377 $4,378
2 2006 35,770 25,729 16,421 9,308 4,654 4,654
3 2007 36,557 26,295 16,421 9,874 4,937 4,937
4 2008 37,361 26,874 16,421 10,453 5,227 5,226
5 2009 38,183 27,465 16,421 11,044 5,522 5,522
6 2010 39,023 28,069 16,421 11,648 5,824 5,824
7 2011 39,882 28,687 16,421 12,266 6,133 6,133
8 2012 40,759 29,318 16,421 12,897 6,449 6,448
9 2013 41,656 29,963 16,421 13,542 6,771 6,771
10 2014 42,572 30,622 16,421 14,201 7,101 7,100
11 2015 43,509 31,296 16,421 14,875 7,438 7,437
12 2016 44,466 31,984 16,421 15,563 7,782 7,781
13 2017 45,444 32,688 16,421 16,267 8,134 8,133
14 2018 46,444 33,407 16,421 16,986 8,493 8,493
15 2019 47,466 34,142 16,421 17,721 8,861 8,860
16 2020 48,510 34,893 16,421 18,472 9,236 9,236
17 2021 and beyond 49,577 35,661 0 35,661 17,831 7/ 17,830 7/
Notes:
1/ Anticipated Savings from NEES/EUA Merger in 2005 dollars escalated by
inflation of 2.2% per year.
2/ Column (a) times Massachusetts Savings Apportionment factor. (Exhibit
MEJ-8, Page 2, Line 3, column (f)).
3/ Exhibit MEJ-6, Page 1, Line 22. 4/ Column (b) minus Column (c).
5/ Proposed Merger Savings Sharing (Column (d) times 50%).
6/ Column (d) minus Column (e).
7/ Increases by inflation beginning in 2021.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-8
Exhibit MEJ-8
Present Value Analysis of Acquisition costs and Savings from
NEES-EUA Consolidation
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket ____
Exhibit MEJ-8
Page 1 of 2
NEES/EUA Acquisition Premium
Net Present Value of Estimated Savings and Acquisition Premium
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
Allocation to States 15/
--------------------------------------------
Massachusetts Rhode Island New Hampshire
Total (Eastern Edison)
Net Present Value of Merger Savings: 100.00% 71.93% 25.39% 2.68%
- ----------------------------------- ------- ----- ----- -----
<S> <C> <C> <C> <C>
Estimated Annual Savings 1/ $30,716 $22,094 $7,799 $823
Estimated After Tax Cost of Capital 2/ 7.50% 7.50% 7.50% 7.50%
Less: Estimated Inflation Rate 3/ 2.20% 2.20% 2.20% 2.20%
---- ---- ---- ----
Net Discount Rate 4/ 5.30% 5.30% 5.30% 5.30%
Net Present Value of Estimated Annual
Savings 5/ $579,547 $416,868 $147,151 $15,528
======== ======== ======== =======
Net Present Value of Merger Costs:
- ---------------------------------
Annual Amortization of Acquisition
Premium 6/ $18,714 $14,070 $4,644
Net Present Value of Amortization
of Acquisition
Premiums using 7.50% Discount
Rate 7/ $190,780 $143,436 $47,343
-------- -------- -------
Annual Amortization of Transaction
Premium 8/ $3,180 $2,351 $829
Net Present Value of Amortization
of Acquisition
Premiums using 7.50% Discount
Rate 9/ $32,418 $23,967 $8,451
------- ------- ------
Total Net Present Value of Merger
Costs 10/ $223,198 $167,403 $55,794
======== ======== =======
Net Present Value of Excess
Merger Savings 11/ $356,349 $249,465 $91,357 $15,528
Sharing of Excess Merger Savings 12/ 50% 50% 50% 50%
--- --- --- ---
Allocation of Excess Merger
Savings to National
Grid Acquisition Premium 13/ $178,174 $124,732 $45,679 $7,764
-------- -------- ------- ------
Allocation of Excess Merger
Savings to Customers 1 $178,175 $124,733 $45,678 $7,764
======== ======== ======= ======
Notes:
1/ $35 million of estimated savings in 2005 discounted to 1999 dollars by inflation rate of 2.2%.
2/ Estimated after tax cost of capital. 3/ Estimated annual inflation rate.
4/ Line 4 minus Line 5.
5/ Line 2 divided by Line 6.
6/ Exhibit MEJ-6, Page 1, Line 12.
7/ Net Present Value of amortization of Acquisition Premium over 20 years.
8/ Exhibit MEJ-6, Page 1, Line 20.
9/ Net Present Value of amortization of Transaction Costs over 20 years.
10/ Line 15 plus Line 21.
11/ Line 8 minus Line 23.
12/ Proposed Sharing of Excess Savings between customers and shareholders.
13/ Line 25 times Line 27.
14/ Line 25 minus Line 30.
15/ Exhibit MEJ-8, Page 2, Column (f).
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket ____
Exhibit MEJ-8
Page 2 of 2
NEES/EUA Acquisition Premium
Allocation of Acquisition Premium and Transaction Costs
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
1998 1997 1996 Total 3 Year Ave.
MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation
to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage
Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/
------------- ------------ ------------- ------------ ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328
Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938
---------- ---------- ---------- ----------
Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 71.93%
----------- ----------- ----------- -----------
Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333
Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965
Newport Electric 542,466 536,209 525,372 1,604,047
-------- -------- -------- ---------
Total Rhode Island 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 25.39%
---------- ---------- ---------- -----------
Granite State Electric 718,452 693,879 699,569 2,111,900
-------- -------- -------- ---------
Total New Hampshire 718,452 693,879 699,569 2,111,900 703,967 2.68%
-------- -------- -------- ---------- -------- -----
Grand Total 26,828,345 26,124,494 25,891,672 78,844,511 26,281,504 100.00%
----------- ----------- ----------- ----------- ----------- -------
Notes:
1/ 1998 FERC Form 1, Pages 300-301.
2/ 1997 FERC Form 1, Pages 300-301.
3/ 1996 FERC Form 1, Pages 300-301.
4/ Sum of Columns (a) through (c).
5/ Column (d) divided by three.
6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)).
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit MEJ-9
Exhibit MEJ-9
Rate Comparison by Utility
<PAGE>
Comparison of Massachusetts "Delivery" Rates
Residential Customer (500 kWh Usage)
(Cents per kWh)
Exhibit MEJ-9
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to residential customers
(listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of seven Massachusetts utilities
(i) distribution rates, (ii) transmission rates, (iii) transition rates, and
(iv) total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
MECO 4.1 0.7 1.3 6.1
EECO 4.2 0.3 2.1 6.6
Camb 4.0 1.3 1.4 6.7
WMeco* 5.1 0.3 2.8 8.2
Fitchburg* 5.4 0.5 2.5 8.4
BECO 5.6 0.3 2.8 8.7
Comm Elec 5.5 0.4 3.2 9.1
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of April 1, 1999.
Page 1 of 5
<PAGE>
Comparison of Massachusetts "Delivery" Rates
Average G-1 Customer (6 kW Demand and 1,500 kWh Usage)
(Cents per kWh)
Exhibit MEJ-9
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to average G-1 customers
(listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of seven Massachusetts utilities
(i) distribution rates, (ii) transmission rates, (iii) transition rates, and
(iv) total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Camb 2.6 1.2 1.4 5.2
MECO 4.8 0.7 1.3 6.8
EECO 4.8 0.3 2.1 7.2
Comm Elec 4.3 0.4 3.2 7.8
WMeco* 4.8 0.3 2.8 7.9
Fitchburg* 5.5 0.5 2.4 8.4
BECO 5.8 0.4 2.7 8.9
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of April 1, 1999.
Page 2 of 5
<PAGE>
Comparison of Massachusetts "Delivery" Rates
Average G-2 Customer (50 kW Demand and 16,700 kWh Usage)
(Cents per kWh)
Exhibit MEJ-9
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to average G-2 customers
(listed in increments of 2.0 cents between and including 0.0 and 8.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of seven Massachusetts utilities
(i) distribution rates, (ii) transmission rates, (iii) transition rates, and
(iv) total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
MECO 2.4 0.6 1.3 4.4
Camb Elec 2.1 1.1 1.4 4.5
EECO 2.7 0.3 1.8 4.8
WMeco* 3.0 0.3 2.8 6.1
Fitchburg* 4.2 0.4 2.2 6.8
BECO 4.3 0.4 2.4 7.1
Comm 3.8 0.4 3.2 7.3
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of April 1, 1999.
Page 3 of 5
<PAGE>
Comparison of Massachusetts "Delivery" Rates
Average G-3 Customer (610 kW Demand and 255,400 kWh Usage)
(Cents per kWh)
Exhibit MEJ-9
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to average G-3 customers
(listed in increments of 1.0 cent between and including 0.0 and 8.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of seven Massachusetts utilities
(i) distribution rates, (ii) transmission rates, (iii) transition rates, and
(iv) total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
MECO 1.8 0.6 1.3 3.7
Camb 1.2 1.2 1.4 3.8
EECO 1.8 0.3 2.2 4.3
Comm 1.4 0.3 3.2 4.9
Fitchburg* 3.1 0.4 1.7 5.2
WMeco* 2.1 0.3 2.9 5.3
BECO 2.3 0.3 2.8 5.4
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of April 1, 1999.
Page 4 of 5
<PAGE>
Comparison of Massachusetts "Delivery" Rates
Very Large C&I Customer (5,000 kW Demand and 2,000,000 kWh Usage)
(Cents per kWh)
Exhibit MEJ-9
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to very large C&I customers
(listed in increments of 1.0 cents between and including 0.0 and 6.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of seven Massachusetts utilities
(i) distribution rates, (ii) transmission rates, (iii) transition rates, and
(iv) total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
MECO 1.8 0.6 1.3 3.7
Camb 1.2 1.4 1.4 4.0
EECO 1.8 0.3 2.2 4.3
Comm Elec 1.1 0.3 3.2 4.7
WMeco* 1.7 0.3 3.0 5.0
Fitchburg* 3.1 0.4 1.7 5.2
BECO 2.3 0.3 2.8 5.4
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of April 1, 1999.
Page 5 of 5
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
ROBERT G. POWDERLY
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
ROBERT G. POWDERLY
Table of Contents
Page
I. Qualifications........................................................1
II. Purpose of Testimony..................................................4
III. Terms, Conditions, and Structure of the Transaction...................4
IV. Benefits to Customers, Employees and Shareholders.....................9
V. Compliance with the Department's Merger and Acquisition Standards....13
1. Effect on Rates.............................................14
2. Quality of Service..........................................14
3. Resulting Net Savings.......................................15
4. Effect on Competition.......................................15
5. Cost Allocation Issues......................................16
6. Financial Integrity of the Post-Merger Entity...............17
7. Societal Costs-Employment...................................17
8. Economic Development........................................18
9. Alternatives to Mergers or Acquisitions.....................18
VI. Conclusion...........................................................19
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 1 of 19
<S> <C>
1 I. Qualifications.
2 Q. Please state your name and business address.
3 A. My name is Robert G. Powderly and my business address is 750 West Center Street,
4 West Bridgewater, Massachusetts.
5
6 Q. By whom are you employed and in what capacity?
7 A. I am employed by EUA Service Corporation ("EUASC"). I am Executive Vice President
8 of Blackstone Valley Electric Company ("Blackstone"), Eastern Edison Company
9 ("Eastern"), Newport Electric Corporation ("Newport") and Montaup Electric Company
10 ("Montaup"). Additionally, I hold the same position for Eastern Utilities Associates
11 ("EUA"), the parent company of the above three retail affiliates and EUASC, the service
12 company for EUA's subsidiaries. My areas of responsibility for regulated companies in
13 the EUA system include Customer Service, Human Resources, Information Systems, and
14 Rates.
15
16 Q. Please summarize your educational background and your professional qualifications.
17 A. I was graduated from the College of the Holy Cross in 1969 with a Bachelor of Arts
18 degree in mathematics. After serving five years in the U. S. Navy, I attended
19 Northeastern University, and received a Master of Science in Accounting degree in 1975.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 2 of 19
1 While in the Navy, I was involved in the operation of naval nuclear propulsion units and
2 in 1973 I qualified as Engineer of Naval Nuclear Propulsion plants.
3 After graduate school, I was employed for almost four years by an international
4 public accounting firm (Ernst & Ernst, now called Ernst & Young). During this period,
5 my responsibilities included audits of publicly-held, regulated, and non-profit
6 organizations. In 1978, I joined EUASC as Audit Supervisor. My responsibilities were
7 to develop and implement a comprehensive audit program for the EUA system companies
8 and to report the results of that program to both management and the Audit Committee of
9 the Board of Trustees. After three years as Audit Supervisor, I was promoted to the
10 position of Manager of System Revenue Requirements. In this position, I was
11 responsible for the detailed coordination and preparation of rate cases for EUA's
12 companies. I participated personally in these cases in various ways, including testifying
13 on matters reflected in the cost of service or preparing cost-of-service adjustments under
14 the direction of company accounting witnesses. Effective August 1, 1985, I was
15 promoted to Assistant Vice President and I assumed responsibilities for special projects
16 in the areas of accounting, taxes, finance, and personnel. On April 15, 1986, I was named
17 Vice President of EUA Service Corporation wherein I assumed responsibility for the
18 EUA's Rate and Customer Service Departments. In March 1990, I was elected President
19 of Newport upon its acquisition by EUA. I was responsible for the integration of
20 operations of Newport and EUA. In April 1992, I was elected Executive Vice President
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 3 of 19
1 with EUA system responsibilities of Corporate Communications, Customer Service,
2 Information Systems, and Rates.
3 I am a Certified Public Accountant in the Commonwealth of Massachusetts. In
4 addition, I have participated in several professional and utility associations, such as the
5 American Institute of Certified Accountants, the Massachusetts Society of Certified
6 Public Accountants, both the Audit Committee and the Rate Research Committee of the
7 Edison Electric Institute, both the Audit Committee and Energy Management Committee
8 of the Electric Council of New England, and the National Association of Accountants.
9
10 Q. Do you serve on any other boards or committees?
11 A. Yes. I serve on the Board of Directors of Blackstone, Eastern, Newport, EUASC,
12 Montaup, and the Southeastern Massachusetts Manufacturing Partnership. Also, I am the
13 past chairperson of the Electric Council of New England and the Rhode Island Good
14 Neighbor Energy Fund and past Vice Chairperson of the United Way of Newport County.
15
16 Q. Have you previously testified before any regulatory commission?
17 A. Yes. I have testified before the Department of Telecommunications and Energy
18 ("Department") in Eastern's general rate cases. I have also testified before the Rhode
19 Island Public Utilities Commission in general rate cases filed by Blackstone and
20 Newport, and presented testimony before the Federal Energy Regulatory Commission on
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 4 of 19
1 behalf of Montaup, EUA's transmission and generation company. Additionally, I have
2 testified before legislative committees in Rhode Island and Massachusetts on the subject
3 matter of electric utility restructuring.
4
5 II. Purpose of Testimony.
6 Q. What is the purpose of your testimony?
7 A. The purpose of my testimony is twofold. The first is to explain the benefits of the merger
8 of EUA with New England Electric System ("NEES") for the customers, employees, and
9 shareholders of the EUA companies. The second is to describe how this merger meets
10 the standard of review for mergers and acquisitions established by the Department in
11 Mergers and Acquisitions, D.P.U. 93-167A, and in recent merger cases.
12
13 III. Terms, Conditions, and Structure of the Transaction.
14 Q. What is the corporate form of EUA?
15 A. EUA is a Massachusetts voluntary association and a registered holding company under
16 the Public Utility Holding Company Act of 1935 ("Holding Company Act"). EUA owns
17 the common equity of three electric companies, Eastern, Blackstone, and Newport.
18 Eastern owns the common equity of Montaup. EUA also owns the common equity of
19 EUASC, the entity that provides nearly all professional, technical, and scientific services
20 to EUA affiliates. EUA owns the common equity of non-regulated subsidiaries,
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 5 of 19
1 including EUA Cogenex Corporation, EUA Energy Investment Corporation, and EUA
2 Ocean State Corporation.
3
4 Q. Mr. Powderly, would you please summarize the transaction between EUA and NEES?
5 A. Under the merger agreement, EUA shareholders will receive $31.00 for each share held
6 when the acquisition becomes effective. The cash payment will be subject to an increase
7 of $0.003 per share per day if the merger is not completed on or before the date following
8 six months after approval of the merger by EUA's shareholders. The precise structure of
9 the transaction will be a merger between Research Drive LLC ("Research Drive"), a
10 Massachusetts limited liability company which is owned by NEES, and EUA. Research
11 Drive will merge with and into EUA, with EUA becoming a wholly-owned subsidiary of
12 NEES. The Agreement and Plan of Merger, dated February 1, 1999, (the "Agreement")
13 contains terms and conditions which are typical of a merger transaction. A condition of
14 closing the merger is obtaining approval of the shareholders of EUA.
15
16 Q. Will the merger affect the corporate structure of the EUA operating companies?
17 A. Yes. At closing, EUA will become a wholly-owned subsidiary of NEES. Thereafter,
18 NEES and EUA plan, as part of this transaction, to merge both the holding companies
19 and to consolidate the underlying operating and service companies. Thus, Eastern will
20 merge with Massachusetts Electric Company ("Mass. Electric"), Montaup with New
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 6 of 19
1 England Power Company, and Blackstone and Newport with Narragansett Electric
2 Company. Finally, EUASC and New England Power Service Company ("NEPSCO")
3 will also be consolidated to lower administrative costs. In each case, the surviving entity
4 will be the existing NEES company.
5
6 Q. Will the merger affect the Department's jurisdiction over the EUA operating companies?
7 A. No. At all times, the Department will have the same jurisdiction over the EUA
8 subsidiaries and their ultimate successors as it has now.
9
10 Q. Please explain the impetus for EUA to seek a merger.
11 A. EUA began to consider a combination strategy as soon as it became apparent that the
12 electric utility industry would be restructured and generation deregulated at both the
13 federal and state levels. An integral part of restructuring, supported by both the
14 Department in its generic investigation in D.P.U. 96-100 and the Legislatures of
15 Massachusetts and Rhode Island, was the divestiture by the incumbent utilities of their
16 generation portfolios. In the divested environment, EUA determined, as did other electric
17 utilities, that our skills and assets were best focused on the transmission and distribution
18 business. At the same time, it became evident that if our transmission and distribution
19 companies were to realize greater efficiencies, cost reductions, and attractive returns,
20 EUA would have to grow by orders of magnitude. Put another way, without the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 7 of 19
1 generation business and with relatively small service territories, EUA lost important
2 economies of scale and scope. The reduced scale and scope of the organization after
3 divestiture would make it impossible to sustain the infrastructure necessary to maintain
4 same level of low-cost, high-quality service our customers have come to expect. Our
5 options would be to reallocate fixed costs over a significantly smaller, wires-only, sales
6 base or cut back on service. Maintaining or improving performance in providing
7 customer service, delivering safe, adequate, and reliable electricity at a low cost, and
8 fairly compensating our investors would not likely be the results of operating a small
9 wires-only business. Therefore, we concluded that the only acceptable affiliation must be
10 one that would produce these positive results for all our stakeholders.
11 Consolidation was clearly foreseen by the Department in Mergers and
12 Acquisitions, D.P.U. 93-197A, where the Department found that:
13 Changes in the structure of electricity and gas markets may alter
14 the efficient scale of operations for firms in these industries and
15 may cause a move toward consolidation in some instances. Order
16 at 5.
17
18 In an increasingly competitive market, mergers and acquisitions
19 may represent one of many measures that could achieve savings,
20 efficiencies, increased reliability and better quality of service for
21 Massachusetts utilities. Id. at 5.
22
23 Moreover, in Electric Industry Restructuring, D.P.U./D.T.E. 96-100, the Department
24 specifically incorporated this initial finding into its evaluation of restructuring proposals:
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 8 of 19
1 We reaffirm our policy, articulated in Mergers and Acquisitions,
2 D.P.U. 93-167, at 5, that we expect utilities to explore thoroughly
3 all cost-saving measures to achieve efficiencies, including mergers
4 and acquisitions, and we encourage all companies to consider
5 combinations that are consistent with our long range objectives of
6 fostering effective competition and driving down rates. Order at
7 82
8
9 Q. How did EUA identify potential business combination partners?
10 A. From late 1996 to early 1999, management and the Board continually evaluated the
11 various strategic options available to EUA as restructuring and the transition to
12 competition were taking place. Among the options considered were remaining a
13 relatively small, independent transmission and distribution company, growing the
14 company by acquiring other, smaller electric and/or gas companies within the region,
15 looking for a merger partner of similar size, and looking for a merger partner of larger
16 size. EUA retained its long-time advisor, Salomon Smith Barney, to assist us in our
17 review of alternatives and, if appropriate, to seek out potential merger or acquisition
18 partners. To meet financial and customer objectives, EUA would seek out a partner of a
19 size that would allow the resulting enterprise to achieve the economics of scale necessary
20 to increase efficiency and reduce costs. The most desirable partners would also have
21 characteristics such as being a low cost provider, a similar philosophy of system
22 operations, a strong customer service commitment, and a quality workforce. Discussions
23 with possible partners ensued.
24
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 9 of 19
1 Q. When did EUA reach a conclusion on its future?
2 A. On January 31, 1999 and February 1, 1999, the EUA Board held a special meeting to
3 review and consider the proposals received. After presentations by legal and financial
4 advisors and a full discussion and analysis, the Board unanimously determined that it was
5 in the best interests of all EUA stakeholders to enter into a business combination with
6 NEES and that the terms of the merger were fair to and in the best interests of EUA
7 shareholders; it authorized, approved, and adopted the plan of merger and the transaction
8 described in the Agreement. EUA was advised that NEES obtained the consent of
9 National Grid to enter into the Agreement and on the morning of February 1, 1999, at the
10 conclusion of the EUA Board meeting and prior to the opening of the financial markets,
11 EUA and NEES executed and delivered the Agreement.
12
13 IV. Benefits to Customers, Employees and Shareholders.
14 Q. Would you summarize the benefits of the merger for EUA customers?
15 A. Eastern's customers will realize quantifiable benefits almost immediately as a result of
16 the rate plan proposed by Mass. Electric. Put simply, all of Eastern's customers will be
17 moved to Mass. Electric's lower rates on January 1, 2001. The movement to Mass.
18 Electric's rates will save Eastern's customers approximately $23 million in the first year
19 of rate consolidation, or 14.2 percent over the retail delivery service rates that would
20 otherwise be in effect (See Exhibit MEJ-3). Eastern's customers will further benefit from
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 10 of 19
1 the distribution rate freeze of up to four years proposed by Mass. Electric under the rate
2 plan. Mr Jesanis's Exhibit MEJ-4 demonstrates that, during the four year period, the
3 economic benefits to Eastern's customers are $81 million as compared to the retail
4 delivery service rates that Eastern would have otherwise charged. These economic
5 benefits to customers are compelling. Moreover, the proposed rate plan assures that
6 economic benefits will not come at the sacrifice of quality service. Following the
7 acquisition, both Mass. Electric and Eastern will continue their commitment to maintain
8 the same high standards of service and reliability that their customers have come to
9 expect. Our historic commitment to our communities and local charities will also be
10 maintained. Eastern's record of quality service at low rates will be enhanced by this
11 transaction and we will join in Mass. Electric's exemplary performance of delivering low
12 rates, reliability, and innovation to our customers.
13 In addition to the distribution rate freeze, the merger will produce ongoing savings
14 and efficiency gains. The merger savings after the cost to achieve are projected by Mr.
15 Hoffman, Mr. Jesanis, and Ms. Zschokke to total at least $35 million per year in the first
16 full year after the rate freeze. These savings will endure and, as Mr. Hoffman
17 demonstrates, increase with inflation. Finally, Mr. Jesanis testifies that the NEES merger
18 with National Grid promises additional resources, scale, and the ability to implement
19 further consolidations in the Northeast. The benefits of savings from such future
20 consolidations and efficiencies gains would inure to Eastern's customers as well. The
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 11 of 19
1 promise of savings from future consolidations, together with the distribution rate freeze
2 and the savings from this transaction, provide compelling economic benefits to Eastern's
3 customers. After the merger, Eastern's customers will receive service from a wires
4 company several times larger than their former distribution company with more financial
5 and operational resources to deal with emerging issues regarding customer service and
6 reliability. Eastern's customers will enjoy lower rates and the benefit of rate stability
7 without sacrificing performance and reliability.
8
9 Q. How will the merger affect Eastern's employees?
10 A. As with most mergers, including ours, the achievable benefits are determined in major
11 part by the number and productivity of the employees retained by the surviving entity;
12 some workforce reduction is inevitable. One of EUA's chief concerns in seeking a
13 combination has been that its employees be treated fairly after the merger, a concern
14 shared by the Department as well. Several factors peculiar to this merger lead to the
15 conclusion that our employees will be treated fairly. First, as I describe below, the
16 number of necessary employee reductions is small. Second, we anticipate that most of
17 the employee reductions can be accomplished through attrition and voluntary early
18 retirement incentives. Third, we are combining with an organization that is structured
19 and operates much like EUA. Fourth, NEES has made clear its intention to grow its
20 transmission and distribution business and has the financial backing to do so. This
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 12 of 19
1 growth provides opportunities for our employees they would not otherwise have. Fifth,
2 National Grid is looking for candidates for assignment elsewhere in its operations; these
3 international job opportunities could also be very attractive to our employees. And last,
4 but not least, NEES has committed to honor EUA's labor contracts. For our non-union
5 workforce, NEES has agreed that for 12 months following the closing date,
6 compensation, benefits, and coverage shall not be less favorable, in the aggregate, than
7 those provided, in the aggregate, immediately prior to the closing date. Our employees
8 have heard directly from Richard P. Sergel, NEES's Chief Executive Officer, that their
9 opportunities in the post-merger organization will not be limited because they came from
10 EUA.
11 EUA has been steadfastly committed to maximizing the effectiveness of its
12 workforce through a combination of training and motivating employees and optimizing
13 their numbers. Consistent with that objective, we have reduced our electric company and
14 EUASC populations from 1,343 at the end of 1990 to 946 at the end of 1998 (a 30
15 percent reduction), while improving the quality of service. Our stringent control of
16 personnel counts has positioned us in this merger so that we will be able to achieve
17 synergy savings and still treat our employees fairly. The pre-merger combined staffing is
18 about 4,100. Projected merger savings are based on a reduction from that figure of
19 approximately 250 employees, or about 6 percent of the combined total. We fully expect
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 13 of 19
1 to achieve these reductions almost entirely through attrition and voluntary early
2 retirement programs.
3
4 Q. Would you summarize the benefits of the merger for EUA shareholders?
5 A. The benefits to EUA shareholders are directly related to the consideration they will
6 receive for their shares at the closing of the merger. The base consideration of $31.00 per
7 share represents a 23 percent premium above the price of EUA shares on December 4,
8 1998, the last trading day before other regional merger announcements caused the price
9 of its shares to increase significantly, and a 5 percent premium above the closing price on
10 January 29, 1999. As explained earlier, the purchase price is subject to an upward
11 adjustment related to the timing of the closing, and will be paid in cash. EUA's Board
12 received an opinion from Salomon Smith Barney that the consideration being paid to our
13 common stockholders is fair. We will request shareholder approval at our annual meeting
14 this spring.
15
16 V. Compliance with the Department's Merger and Acquisition Standards.
17 Q. Please address each factor the Department will use to determine whether the acquisition
18 is "consistent with the public interest."
19 A. At the outset, I would note that although the Department has cautioned that the list of
20 factors set forth in Mergers and Acquisitions is not exhaustive, these factors have been
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 14 of 19
1 used when evaluating the merits of other merger cases. In the instant case, I will also rely
2 upon them to demonstrate the public interest benefits of this transaction as it relates to
3 this transaction.
4 1. Effect on Rates. The merger will provide compelling rate benefits for
5 Eastern's customers. The proposed rate plan for consolidating Eastern and Mass.
6 Electric rates and freezing the distribution rates thereafter is summarized by Mr.
7 Jesanis. The economic benefits of the plan are detailed by Ms. Burns. The effect
8 of this plan on Eastern's customers will be a $23 million, 14.2 percent reduction
9 in retail delivery service billings in the first year after the consolidation of rates,
10 assuming a January 1, 2001 effective date. Eastern's rates are already among the
11 lowest in Massachusetts. A rate reduction and a distribution rate freeze promote
12 the economic well being of customers in our service territory. Furthermore, with the
13 cost savings described by Mr. Hoffman, we have the foundation for keeping
14 rates low through lower costs in the future.
15 2. Quality of Service. Both Eastern and Mass. Electric are now operating
16 under performance standards established in their Restructuring Settlement
17 Agreements, which were approved by the Department in D.P.U./D.T.E. 96-24 and
18 96-25, respectively. These standards are discussed in the testimony of Mr. Reilly.
19 As Mr. Reilly explains, the standards will be consolidated and updated for the
20 combined companies. As the Department found in D.P.U/D.T.E 96-24 and 96-25,
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 15 of 19
1 these standards provide the required assurance that Eastern and Mass. Electric will
2 maintain their historic levels of reliability and customer service. Pursuant to the
3 Settlements, these standards are in effect until 2001 and may be revised by the
4 Department if it adopts more stringent standards applicable to the other
5 distribution companies operating in the Commonwealth. These performance
6 standards meet the Department' requirements for a Service Quality Standards
7 under its merger policy. D.T.E. 98-31 at 31, inter alia.
8 3. Resulting Net Savings. The savings from consolidation, economies of
9 scale and other efficiency gains as a result of the merger support the proposed rate
10 plan for the customers of the regulated transmission and distribution businesses of
11 EUA and NEES subsidiaries. In their testimony, David J. Hoffman and Richard
12 J. Levin project net savings that, when added to further savings projected by Mr.
13 Jesanis, total $35 million in the first year after the rate freeze and grow higher
14 over time. The savings exceed the requirements associated with the amortization
15 of the acquisition premium and the transaction costs and will produce benefits to
16 Eastern's customers.
17 4. Effect on Competition. Both Eastern and Mass. Electric provide only
18 regulated retail delivery services for which there is no relevant competition. Thus,
19 there can be no competitive impact or harm from the merger to the wires business
20 in our respective service territories. With regard to competitive generation
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of R. G. Powderly
Page 16 of 19
1 services, EUA and NEES have disposed of nearly all of their generation and thus
2 the merger does not significantly affect competition. I do envision, however, that
3 the proposed merger is likely to enhance the development of competition for
4 customers of both Eastern and Mass. Electric. Competitive suppliers will have
5 the opportunity to serve a larger base of customers under a single set of terms and
6 conditions and under a single load settlement process. This consolidation will
7 reduce the administrative and transaction costs for competitive suppliers and
8 reduced costs can be expected to result in both lower barriers to entry for
9 competitive suppliers and ultimately lower costs to customers.
10 5. Cost Allocation Issues. As part of the consolidation of the NEES and
11 EUA subsidiaries, EUASC will be merged into NEPSCO. The service company
12 allocations will continue to be subject to review by the Department in Mass.
13 Electric's rate cases. Cost allocations for the other NEES companies will
14 continue to be subject to the SEC's requirements under the Holding Company
15 Act, and the standards of conduct promulgated by the Department, other state
16 commissions, and FERC. These regulatory controls assure that costs will be
17 allocated appropriately among subsidiaries.
18 Mr. Jesanis has testified regarding allocation of the acquisition costs and
19 merger savings to the regulated EUA companies. As he explains, under the
20 proposed rate plan, EUA customers realize immediate and substantial savings in
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Testimony of R. G. Powderly
Page 17 of 19
1 their rates. Moreover, following the distribution rate freeze period, the remaining
2 costs of the NEES-EUA merger will be entirely offset by savings produced as a
3 result of the merger. This proposal provides a fair distribution of these benefits
4 between customers and shareholders while encouraging and supporting further
5 consolidations in accordance with the Department's policy.
6 6. Financial Integrity of the Post-Merger Entity. Ms. Zschokke's testimony
7 demonstrates that the merger of EUA and NEES will enhance the financial
8 resources and access to financial markets of the combined entity, and reduce the
9 financing costs of Eastern. The post-merger entity, at the holding company level,
10 will continue to be regulated by the SEC as a registered holding company under
11 the Holding Company Act. The financings of the Massachusetts electric
12 companies will continue to be supervised and regulated by the Department. This
13 level of regulatory oversight will not diminish for the merged companies.
14 7. Societal Costs-Employment. Earlier in my testimony, I discussed
15 generally employee benefits and how the merger will provide EUA employees
16 with significant new opportunities. As a result of long-standing programs of cost
17 control and efficiency enhancements, we anticipate achieving almost all of the
18 required personnel reductions though attrition and voluntary early retirement
19 programs with minimal impact on individual employees. Overall, this merger
20 will provide the region with financially strong, technically sophisticated
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Page 18 of 19
1 transmission and distribution companies, lower rates, and an ongoing
2 commitment to customer service.
3 8. Economic Development. Low rates and good customer service promote
4 economic development, business growth, and enhance job markets in
5 Massachusetts. As I have shown above, the combination of EUA and NEES will
6 produce low rates and quality service. Under the proposed rate plan, customers of
7 Eastern will see their retail delivery service rates reduced by approximately $23
8 million, or 14.2 percent, one year after completion of the merger, with the
9 distribution component frozen thereafter. In the longer term after the rate freeze,
10 the synergies between the companies will produce annual net savings of $35
11 million per year. These economic benefits will make our region more
12 competitive. In addition, we will be participating in economic development
13 activities in the larger Mass. Electric franchise area, creating additional
14 opportunities for our communities to attract jobs. Finally, the merger with NEES
15 and National Grid will allow us to be a center of activity for National Grid's
16 activity in the Northeast providing growth in our own operations.
17 9. Alternatives to Mergers or Acquisitions. I am not aware of alternatives to
18 this merger that would produce benefits comparable to those described in this
19 application. As a stand-alone entity, EUA would either have to reduce drastically
20 its cost of doing business or increase rates to compensate for the loss of its
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Page 19 of 19
1 generation business. The required cost reductions would have to come by way of
2 reducing services or reliability to inadequate levels. Equally unacceptable as an
3 alternative is an EUA expansion of its unregulated ventures as a means of
4 increasing financial resources and economies of scale. This course of action
5 would significantly increase EUA's risk profile and, ultimately, its equity capital
6 would come at a higher price. Finally, other potential merger partners for EUA do
7 not have contiguous service territories and low distribution rates and EUA-
8 reliability and EUA-customer satisfaction levels and similarity of operations and
9 low costs. Our partner, NEES, does. EUA's affiliation with NEES makes the
10 most sense -- for our customers, for our employees, and for our shareholders.
11
12 VI. Conclusion.
13 Q. Does the proposed transaction between NEES and EUA satisfy the Department's criteria
14 for merger and acquisition?
15 A. Yes. Measured by the Department's standards, this merger is consistent with the public
16 interest and should be approved as filed.
17
18 Q. Does this complete your testimony?
19 A. Yes.
</TABLE>
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
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)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
LAWRENCE J. REILLY
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
LAWRENCE J. REILLY
Table of Contents
Page
I. Qualifications....................................................... 1
II. Purpose of Testimony................................................. 4
III. Organization of NEES Distribution Companies.......................... 4
IV. Service Benefits from the Merger..................................... 7
V. Service Quality Performance Standards................................10
A. Introduction................................................10
B. Proposed Service Quality Performance Standards..............11
1. Reliability Performance Standard...................13
2. Customer Service Performance Standard..............15
3. Line Loss Standard.................................16
C. Implementation..............................................17
VI. Development of the Competitive Power Supply Market...................18
<PAGE>
<TABLE>
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Page 1 of 21
<S> <C>
1 I. Qualifications.
2 Q. Please state your name and business address.
3 A. My name is Lawrence J. Reilly. I have two business addresses: 55 Bearfoot Road,
4 Northborough, Massachusetts 05132; and 280 Melrose Street, Providence, Rhode Island
5 02907.
6
7 Q. By whom are you employed and in what position?
8 A. I am employed by New England Power Service Company ("NEPSCO"). I am President
9 and Chief Executive Officer of New England Electric System's ("NEES's") electricity
10 distribution subsidiaries: Massachusetts Electric Company and Nantucket Electric
11 Company (together "Mass. Electric" or the "Company"); The Narragansett Electric
12 Company ("Narragansett Electric"); and Granite State Electric Company ("Granite State
13 Electric"). I am also a Director of each of these companies.
14
15 Q. Please describe your educational background and training.
16 A. In 1978, I received a Bachelor of Arts degree magna cum laude from the State University
17 of New York at Albany. In 1982, I received the degree of Master in City and Regional
18 Planning from the John F. Kennedy School of Government at Harvard University where I
19 specialized in Energy and Environmental Policy. Also in 1982, I received a Juris Doctor
20 degree cum laude from Boston University School of Law.
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1 Q. Please describe your professional experience.
2 A. I joined NEPSCO as an Attorney in the Corporate Legal Department in 1982. In that
3 capacity I advised various NEES companies in the areas of finance and securities law as
4 well as in the areas of environmental licensing and permitting. In 1987, I became legal
5 counsel to, and Secretary of, Narragansett Electric, in Providence, Rhode Island. In that
6 capacity my responsibilities included advising Narragansett Electric on a variety of
7 regulatory and rate matters as well as permitting for the Manchester Street Station
8 Repowering Project. In July 1990, I became Director of Rates for NEPSCO with
9 responsibility for wholesale and retail rate matters for all of the NEES companies. In
10 1993, I was elected a Vice President and assumed additional responsibility for retail
11 revenue requirements. Effective June 1, 1996, I became President of Mass. Electric. I
12 became President of Granite State Electric and Narragansett Electric in January, 1997,
13 and October, 1997, respectively. In my capacity as Vice President and Director of Rates
14 and as President and CEO of the NEES electricity distribution companies I have been
15 actively involved with electric industry restructuring matters. My current areas of
16 responsibility for the NEES electricity distribution companies include transmission and
17 distribution system operations, customer service, and business service functions.
18
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1 Q. Do you serve on the boards of any other organizations?
2 A. Yes. I am a Director of the Massachusetts Technology Park Corporation, the quasi-
3 public entity responsible for, among other things, administering the renewable energy
4 trust fund established by the 1997 Massachusetts electric restructuring law. I also
5 currently serve as Chairman of the Massachusetts Alliance for Economic Development, a
6 privately funded non-profit organization dedicated to promoting economic growth in
7 Massachusetts. I am also on the Board of Grow Smart Rhode Island, a non-profit
8 organization focused on the interaction of economic growth, environment, and land use
9 issues. In addition, I serve on the Boards of the United Way of Central Massachusetts,
10 the United Way of Southeastern New England, the Foundation for Ocean State Public
11 Radio, the Worcester State Foundation, and as a Corporator of the Worcester Art
12 Museum.
13
14 Q. Have you previously testified before any regulatory commission?
15 A. Yes, I have previously testified before the Department of Telecommunications and
16 Energy ("Department"), the Rhode Island Public Utilities Commission, the New
17 Hampshire Public Utilities Commission, and the Federal Energy Regulatory
18 Commission.
19
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1 II. Purpose of Testimony.
2 Q. What is the purpose of your testimony?
3 A. The purpose of my testimony is four-fold. First, I will describe how the NEES
4 distribution companies are organized today to provide quality service to customers.
5 Second, I will describe the integration process that is underway with Eastern Utilities
6 Associates ("EUA") and the anticipated benefits for customers. Third, as required by the
7 Department, I will propose a specific set of service quality performance standards to be
8 put in place prospectively to ensure that the high quality service customers currently
9 enjoy will continue after the merger. Finally, I will outline a program that is currently
10 under development to foster a robust power supply market where customers can fully
11 realize the economic benefits of competition in the restructured industry.
12
13 III. Organization of NEES Distribution Companies.
14 Q. Mr. Reilly, will you please describe how the NEES distribution companies are organized
15 to provide service to customers.
16 A. The NEES distribution companies currently provide service to almost 1.4 million
17 customers in 209 cities and towns in Massachusetts, Rhode Island, and New Hampshire.
18 The breakdown of customers by distribution company is detailed on Exhibit LJR-1.
19 Although each of the distribution companies is a separate legal entity, to the extent
20 possible we operate them as an integrated organization. This allows us to operate more
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1 efficiently and provide better service to customers than if each company were managed
2 independently. For example, this method of operation allows us to implement best
3 practices uniformly across the system and provides us flexibility in terms of assigning
4 crews where needed most in response to major storms. Through this integrated
5 management we are able to achieve the efficiency gains that have historically been
6 available through the sharing of administrative functions such as accounting and legal
7 services through NEPSCO.
8 Because the three state service area of the combined organization covers almost
9 5000 square miles, we divide the territory up into six operating districts and a number of
10 operating satellites that are run from each district. Exhibit LJR-2 is a map showing the
11 current district boundaries within the service territory and the location of key facilities.
12 For the most part, each operating district includes a functional head for operations,
13 customer service, and business services. These individuals are responsible for service
14 performance and program implementation throughout their respective districts. In
15 general, where there is a need to be close to the customers (because of travel time or
16 because detailed knowledge of the local conditions is required), individuals work out of
17 the local district offices or satellite locations; where frequent local contact is not critical,
18 individuals tend to work in the central locations, principally, Northborough,
19 Westborough, and Providence. The degree to which each operating district is supported
20 centrally varies from function to function.
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1 Q. Please explain the split between district and central functions in the Operations area.
2 A. In Operations, the physical workers (linemen, underground workers, substation
3 maintenance workers) are assigned to a district or satellite location. Certain engineering
4 functions are performed locally while other engineering functions such as substation
5 design and standards are performed centrally. Operating functions handled centrally for
6 all system companies include: training; material supply; relay & telecommunications;
7 transmission line engineering; engineering laboratory; construction; environment; safety;
8 and property assets. In some cases there are individuals assigned to local district offices
9 to implement programs and polices that are administered centrally. Safety,
10 environmental management, and vegetation management are examples of areas that fall
11 into this category.
12
13 Q. How is responsibility divided between the field and central office in the customer service
14 area?
15 A. Meter reading is the clearest example of a function where it is most efficient to have the
16 workers located near the customers. The meter operations group, which is responsible for
17 installing, maintaining, exchanging, and testing meters, is also decentralized; however,
18 field personnel receive central support from the Meter Operations and Engineering Group
19 in Worcester. Supplier services along with load research and load estimation, which have
20 become increasingly important in the restructured environment, are located centrally in
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1 Northborough. Customer calls are handled in call centers located in Northborough and
2 Providence that are linked through telecommunications equipment which automatically
3 transfers calls between these two centers to minimize wait times for customers. This
4 arrangement also provides us access to two job markets for customer service
5 representatives and diversity of locations in the event of bad weather or a disaster at either
6 location.
7
8 Q. How is the Business Service function organized?
9 A. Each district office has a local Business Services Vice President and a staff of account
10 managers. The account managers handle service requests for our largest customers (200
11 kilowatts or greater demand per month) and are actively involved in the marketing of our
12 various Demand Side Management ("DSM") programs. DSM programs for residential
13 and small commercial and industrial customers are handled centrally from Northborough.
14 Special programs and new initiatives are also developed in Northborough and
15 implemented in close coordination with Business Services personnel in the field.
16
17 IV. Service Benefits from the Merger.
18 Q. Do you believe that the merger will create service benefits for the customers of both
19 companies?
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Page 8 of 21
1 A. Yes. Several factors lead us to conclude that the merger will improve service to
2 customers. First is geographic proximity. A map showing the relationship between the
3 NEES and EUA distribution companies is included as Exhibit LJR-3. As shown, the
4 service territories of these two companies are in very close proximity. It is this
5 geographic proximity that makes this merger so attractive from an operating perspective.
6 This merger goes a long way to rationalizing the service territories of the distribution
7 companies in southeastern New England and, with the integration of NEES and EUA
8 field and central functions, should enable us to provide comparable or better service at a
9 lower cost. Second, there is a long history of good working relationships between our
10 companies, including a history where a number of employees have moved between the
11 companies over time. Third, perhaps related to the first two items mentioned above, there
12 appears to be a very similar culture between the two companies -- one where quality
13 customer service and cost control are widely recognized objectives. In my opinion, all
14 three of these factors will facilitate a successful integration of the businesses.
15
16 Q. Are the companies also addressing service quality issues in the integration process for the
17 merger?
18 A. Yes. The proper integration of the companies is central to the effectiveness and
19 efficiency of our operations and the quality of our service following the merger. I am a
20 member of the integration steering committee that is responsible for the successful
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Page 9 of 21
1 integration of the companies. Our progress during the integration process has been
2 substantial. We have already found several ways to improve service and efficiency that
3 we will build upon as we complete the integration progress and following the merger.
4 The transition teams cover ten different disciplines and approximately sixty subgroups
5 have been established as part of the effort to focus on specific areas. The teams and the
6 areas they are responsible for are outlined on Exhibit LJR-4.
7
8 Q. What benefits of the merger have you identified to date?
9 A. Although it is still early in the process, it is apparent that several key benefits will flow
10 from the eventual consolidation of Eastern Edison Company ("Eastern") into Mass.
11 Electric. Specifically:
12 o The larger company will have more resources to draw upon in the event of storms
13 or natural disasters;
14 o Customer service costs and other costs associated with administering separate
15 rates and maintaining separate companies will be reduced;
16 o Eastern's customers will be provided 24 hour per day access to customer service
17 representatives for routine billing and payment inquires (currently such access is
18 limited to 7 a.m. to 9 p.m. Monday through Saturday);
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1 o The consolidation of Mass. Electric and Eastern will produce administrative
2 savings for the Department by reducing the number of regulated companies and
3 associated reporting requirements;
4 o The customers of Mass. Electric and Eastern will benefit from the rate plan
5 proposed as part of this filing; and
6 o The consolidation of Mass. Electric and Eastern will help in the development of
7 the competitive power supply market. This benefit and other actions we are
8 planning to take to help facilitate development of that market are discussed in
9 Section VI of my testimony below.
10
11 V. Service Quality Performance Standards.
12 A. Introduction.
13 Q. Please describe the Mass. Electric's Service Quality Performance Standards proposal.
14 A. After the merger, the Company is proposing a single set of Service Quality Performance
15 Standards that is consistent with the Performance Standards adopted pursuant to
16 Restructuring Settlements approved in D.P.U./D.T.E. 96-24 (Eastern) and 96-25 (Mass.
17 Electric). Mass. Electric's currently effective standards for reliability and customer
18 service are attached as Exhibit LJR-5. Eastern's currently effective standards, which are
19 generally consistent with Mass. Electric's, are attached as Exhibit LJR-6. The
20 benchmarks for both companies under each performance standard are based on averages
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Eastern Utilities Associates
Testimony of L. J. Reilly
Page 11 of 21
1 of historic performance, plus one standard deviation. Each standard carries a maximum
2 penalty of $1,000,000 for Mass. Electric and $250,000 for Eastern.
3
4 B. Proposed Service Quality Performance Standards.
5 Q. Please summarize the Company's proposed Service Quality Performance Standards.
6 A. The Company's proposed Service Quality Performance Standards represent a
7 continuation of the present, Department-approved performance standards for Mass.
8 Electric and Eastern, with the addition of three important changes. First, the benchmarks
9 for the proposed standards are based on the average of the combined historic data for
10 Mass. Electric and Eastern. Second, the historic data used for the benchmarks has been
11 updated to reflect a more recent time period than that used in the original standards.
12 Finally, the Company is proposing a maximum penalty under the standards of
13 $2,500,000. All other characteristics of the proposed standards are consistent with the
14 standards approved in D.P.U./D.T.E. 96-24 and 96-25. The proposed performance
15 standards marked to show changes are included in Exhibit LJR-7. A clean version is
16 included in Exhibit LJR-8
17
18 Q. Please describe the development of the benchmarks for the proposed standards.
19 A. Mass. Electric and Eastern compiled their historic data under each of the areas covered by
20 the standards and found that the data were generally comparable and consistent. For
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Eastern Utilities Associates
Testimony of L. J. Reilly
Page 12 of 21
1 example, both companies use similar definitions for service outages and conduct similar
2 customer satisfaction surveys. The comparability and consistency of the data allowed the
3 companies to create a composite benchmark for each standard using data from Mass.
4 Electric and Eastern.
5
6 Q. Please describe the time period covered by the historic data used to develop the
7 benchmarks.
8 A. After reviewing their historical records, we determined that data from more recent years
9 was generally more comparable and consistent than data from earlier periods.
10 Accordingly, we have limited the time period for data used in the development of the
11 benchmarks to no earlier than 1991. Thus, to set the benchmarks for the reliability and
12 customer service standards after the merger, Mass. Electric has used the average of
13 historic data for 1991 through 1998, plus one standard deviation.
14
15 Q. Does this updating cause the benchmarks to be more stringent?
16 A. Yes, it does.
17
18 Q. Please describe the maximum penalty under the proposed standards.
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1 A. The maximum penalty under both standards totals $2,500,000. This amount represents
2 the sum of the maximum penalties under the present standards for Mass. Electric and
3 Eastern.
4
5 Q. How does the proposal weight the two areas covered by the standards?
6 A. The total maximum penalty is split evenly between the two standards. Thus, each
7 standard has a maximum penalty of $1,250,000. The proposed standards preserve the
8 50/50 split in the present standards approved by the Department.
9
10 Q. How were the proposed penalty schedules under the standards developed?
11 A. The schedule of penalties under the proposed standards is designed in the same manner as
12 the schedules under the existing standards. The rationale behind the schedules is to
13 ensure that significant deviations from historic levels result in penalties under the
14 standards.
15
16 1. Reliability Performance Standard
17 Q. Please describe the proposed Reliability Service Quality Performance Standard.
18 A. As in the standard under the Restructuring Settlements, reliability of service is measured
19 by the duration of outages. The standard defines a customer interruption as the loss of
20 electric service to more than one customer for more than one minute. The duration of
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Eastern Utilities Associates
Testimony of L. J. Reilly
Page 14 of 21
1 outages per customer served is the total length of time in minutes that an average
2 customer is without service per year, as measured by the System Average Interruption
3 Duration Index (SAIDI).
4
5 Q. Please describe the development of the Duration of Outages Performance Standard.
6 A. Combining Mass. Electric's and Eastern's data for 1991 through 1998 results in an
7 average duration of outages (plus one standard deviation) of 96 minutes. Based on this
8 data, the companies are proposing a benchmark duration of outages of 96 minutes.
9 Exhibit LJR-9 provides the derivation of the duration of outages standard and its schedule
10 of penalties, with a maximum penalty of $1,250,000.
11
12 Q. Are any events excluded from reliability measurements?
13 A. Yes. Excluded from the companies' historic reliability measurements are severe weather
14 events, under-frequency load shedding events, and other extraordinary circumstances.
15 Severe weather events are defined as those resulting in the interruption of 10 percent or
16 more of the customers in a district at any given time during the storm. We are proposing
17 to use the same criteria for exclusion as under the present standards. The criteria for
18 exclusion of an event from reliability measurements is included in Exhibit LJR-8.
19
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1 2. Customer Service Performance Standard.
2 Q. Please describe the proposed Customer Service Performance Standard.
3 A. As in the existing standard under the Restructuring Settlements, we are proposing a
4 Customer Service standard based on overall residential customer satisfaction. The
5 standard has a maximum penalty of $1,250,000, or half of the total maximum penalty.
6
7 Q. How is customer satisfaction measured?
8 A. Mass. Electric and Eastern have historically commissioned an independent third party to
9 conduct a survey of customers to determine their overall level of satisfaction with the
10 companies. Comparable data for this survey is available from 1991.
11
12 Q. How have the surveys been conducted?
13 A. An independent market research firm conducts interviews with a representative sample of
14 customers. Several questions are asked as part of this interview, most of which change
15 annually. However, for the past several years, a consistent question has been asked
16 regarding customer satisfaction. For Mass. Electric, the question has been: "All things
17 considered, how would you rate Mass. Electric's service to you?" For Eastern, the
18 question has been: "I would like to know how you rate your electric company overall."
19 Respondents to both companies' surveys are asked to rate their service on a scale of 1 to
20 7, where 1 means poor and 7 means excellent. The responses in the top three categories
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Page 16 of 21
1 of satisfaction (i.e. 5, 6, and 7) are tabulated in Exhibit LJR-10 and form the basis for
2 developing the Customer Service Performance Standard.
3
4 Q. How is the proposed Customer Service Performance Standard established?
5 A. We are proposing a Customer Satisfaction Performance Standard based on the historical
6 results of the Mass. Electric's and Eastern's residential customer satisfaction surveys.
7 Using the average and standard deviation of data for 1991 through 1998, the proposed
8 Customer Service Performance Standard is 86 percent of responses in the top three
9 categories of customer satisfaction. Consistent with the existing performance standards,
10 we are proposing a sliding scale for penalties. Exhibit LJR-10 provides the calculation
11 and the schedule of penalties under this standard.
12
13 3. Line Loss Standard
14 Q. Is Mass. Electric proposing a line loss standard in this proceeding?
15 A. Not at this time. The Restructuring Settlements also required Mass. Electric and Eastern
16 to "propose ... a performance standard for the effective management of line losses." Both
17 Mass. Electric and Eastern filed such proposals with the Department. The Department,
18 however, has not ruled on these proposed standards and they have not been implemented.
19 In addition, both proposals were based on FERC Form 1 Sources and Disposition of
20 Energy data which is no longer available in a meaningful manner. For these two reasons,
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1 we have not included a distribution line losses standard in our proposal. Rather, we are
2 reviewing the line loss issue and data as part of the integration team process discussed
3 more fully above and, if feasible, will design an alternative to the line loss standard
4 that has already been developed that will reflect current data and provide a meaningful
5 incentive.
6
7 C. Implementation
8 Q. When will the proposed standards become effective?
9 A. We propose to have the proposed standards be effective for consolidated Mass. Electric
10 beginning on the effective date of the rate plan or January 1, 2001 (the "Consolidation
11 Date"). Before that date the current standards would remain in effect.
12
13 Q. How will rate adjustments be implemented pursuant to the Performance Standards?
14 A. Mass. Electric would file a Performance Standards Report with the Department by May
15 1, 2002 and every year thereafter. In these filings, Mass. Electric would provide the
16 following:
17 (1) a determination of the Mass. Electric's performance against each of the
18 Performance Standards based on actual data for the 12 months ending December
19 31 of the previous year;
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1 (2) a determination of the total penalty payment, if any, required under the plan by
2 summing the results of the Performance Standards; and
3 (3) a schedule showing the development of a per kilowatthour factor to credit
4 customers with any penalty payment required under the Performance Standards.
5 This factor would take effect at the time of Mass. Electric's next annual rate
6 adjustment and reflected over the following year.
7
8 VI. Development of the Competitive Power Supply Market.
9 Q. Earlier in your testimony you stated that you expected the consolidation of Mass. Electric
10 and Eastern to help in the development of the competitive power supply market. Please
11 explain why you believe this is to be the case.
12 A. Although it is certainly not the only barrier to development of a competitive market, the
13 multitude of distribution companies within the Commonwealth of Massachusetts has no
14 doubt retarded the growth of the competitive market in a number of ways. First, differing
15 distribution rates and availability clauses for providing distribution service complicate the
16 terrain for power suppliers considering entry into the market. Second, the patchwork
17 nature of the existing service territories complicates marketing efforts. Third, differing
18 electronic data interchange formats and testing requirements add to administrative
19 overheads for suppliers. The consolidation of Mass. Electric's and Eastern's rates for
20 delivery service, the contiguous nature of the expanded service territory, and one less
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1 point of contact for suppliers entering the market here should all help to reduce barriers to
2 entry into the competitive supply market.
3
4 Q. Why is reducing barriers to entry for suppliers entering the competitive market
5 important?
6 A. Prior to restructuring, the generation or supply component of customer bills accounted for
7 roughly two-thirds of the total cost of electricity. The significant potential for savings in
8 that portion of the bill was one of the factors that led to restructuring. Nothing has
9 changed in this area. Power supply costs are still the area where customers stand to save
10 the most money on their bills. Without regulation, however, there must be an efficient
11 and vigorous market for electricity supplies for customers to realize the full benefits of
12 competition.
13
14 Q. In your opinion what other barriers exist to the development of a robust competitive
15 power supply market?
16 A. Lack of information is certainly a problem on several levels. Not all customers are aware
17 of their options or have ready access to billing data needed to minimize supply costs.
18 Power marketers may also lack information about potential customers that could benefit
19 from their products.
20
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1 Q. What actions are you planning to take to reduce these barriers?
2 A. We have a number of initiatives under way to inform customers of their options in the
3 power supply market. We currently offer "Power Talk", a speakers bureau program for
4 customer groups of all kinds. We have implemented a comprehensive education program
5 that includes bill inserts, participation in state-wide education efforts with the Division of
6 Energy Resources ("DOER"), and participation in trade shows and shopping mall
7 displays. We are including information in "PowerLink", a newsletter for our business
8 customers, and are hosting breakfast meetings for our largest customers to highlight
9 opportunities available in the market. Under our "Power Connection" program, with a
10 customer's consent, we will provide billing data to all registered suppliers in electronic
11 format so that prospective suppliers can develop offers suited to the individual customers.
12 We are also distributing a software product called "Energy Smart" to our customers that
13 provides educational information to customers and is expected to eventually aid
14 customers who wish to shop for power supplies on-line.
15 We have also developed a series of optional metering services that are available to
16 any customer that wants detailed interval or real time demand and energy use data. To
17 assist power marketers in getting access to prospective customers, we intend to offer a
18 mailing service to all power marketers whereby we would mail their marketing
19 information to customer segments they determine without disclosing any customer data to
20 the power marketer.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of L. J. Reilly
Page 21 of 21
1 Q. How will the merger improve this effort?
2 A. As part of the integration process, we will continue to look for ways to improve our
3 outreach and education programs and make them more effective. The merger will assure
4 that the finally implemented programs will reach more customers, more efficiently. The
5 consolidation of Mass. Electric and Eastern will also facilitate marketers' efforts to reach
6 our customers with ideas and products that will provide our customers with more value at
7 lower prices.
8
9 Q. Does this conclude your testimony.
10 A. Yes.
</TABLE>
<PAGE>
EXHIBITS OF L. J. REILLY
LJR-1 Customers Served by NEES Distribution Company
LJR-2 Current Map of NEES Service Territory
LJR-3 Map of Combined NEES-EUA Service Territory
LJR-4 Integration Teams and Responsibilities
LJR-5 Mass. Electric's Present Performance Standards
LJR-6 Eastern's Present Performance Standards
LJR-7 Proposed Performance Standards After Consolidation Date (Marked to
Show Changes)
LJR-8 Proposed Performance Standards After Consolidation Date
LJR-9 Derivation of Duration of Outage Standard
LJR-10 Calculation of Customer Satisfaction Measure
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-1
Exhibit LJR-1
Customers Served by NEES Distribution Company
<PAGE>
S:\RADATA1\EASTED\Ljr-1.wk4 Narragansett Electric
PAGE 1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-_____
Exhibit LJR-1
Page 1 of 1
New England Electric System
Number of Customers per Distribution Company
Number of
Customers
---------
Massachusetts:
Massachusetts Electric Company 983,191
Nantucket Electric Company 10,169
------
Total Massachusetts 993,360
Rhode Island:
Narragansett Electric Company 336,029
New Hampshire:
Granite State Electric Company 37,114
------
3 State Total 1,366,503
=========
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-2
Exhibit LJR-2
Current Map of NEES Service Territory
<PAGE>
Exhibit LJR-2
Map of Existing NEES Service Territory
Two Maps
First Map: Reflects service territories, headquarters, customer service and
operations centers and operating satellites for Granite State, Mass. Electric,
Nantucket and Narragansett in Rhode Island, Massachusetts and New Hampshire.
Second Map: Reflects Narragansett service territory, headquarters and operating
satellites in Rhode Island.
<PAGE>
<TABLE>
<CAPTION>
Granite State Electric Massachusetts Electric
Company Company
Lebanon Western Merrimack Valley
<S> <C> <C> <C> <C>
Acworth Adams Mount Washington Amesbury
Alstead Alford New Marlboro Andover
Bath Athol New Salem Billerica
Canaan Barre North Adams Boxford
Charlestown Belchertown Northampton Chelmsford
Cornish Brimfield Orange Dracut
Enfield Charlemont Palmer Haverhill
Grafton Cheshire Petersham Lawrence
Hanover Clarksburg Phillipston Lowell
Lnagdon East Longmeadow Rowe Methuen
Lebanon Erving Royalton Newbury
Marlow Florida Sheffield Newburyport
Monroe Goshen Shutesbury North Andover
Orange Granby South Egremont Salisbury
Plainfield Great Barrington Stockbridge Tewksbury
Surry Hampden Templeton Tyngsboro
Walpole Hancock Wales West Newbury
Hardwick Ware Westford
Hawley Warren
Salem Heath Warwick North Shore
Derry Holland Wendell Beverly
Pelham Lenox West Stockbridge Essex
Salem Monroe Wilbraham Everett
Windham Monson Williamsburg Gloucester
Monterey Williamstown Hamilton
Lynn
Narrangansett Electric Malden
Company Central Manchester
Auburn New Braintree Medford
Southern Ayer North Brookfield Melrose
Charlestown Berlin Oakham Nahant
Coventry Bolton Oxford Revere
East Greenwich Brookfield Paxton Rockport
Exeter Charlton Pepperell Salem
Hopkinton Clinton Rutland Saugus
Narragansett Dudley Shirley Swampscott
North Kingstown Dunstable Southbridge Topsfield
Richmond East Brookfield Spencer Wenham
South Kingstown Gardner Sturbridge Winthrop
Warwick Grafton Sutton
West Greenwich Harvard Webster
West Warwick Hubbardston West Brookfield
Westerly Lancaster West Groton
Leicester Westminster
Providence Leominster Winchendon
Barrington Millbury Worcester
Bristol
Cranston Southeast
East Providence Attleboro Northborough
Foster Bellingham Northbridge
Glocester Blackstone Norton
Johnston Douglas Plainville
Little Compton Foxborough Quincy
North Providence Franklin Randolph
Providence Hingham Rehoboth
Scituate Holbrook Seekonk
Smithfield Hopedale Southborough
Tiverton Marlborough Upton
Warren Mendon Uxbridge
Milford Westborough
Milville Weymouth
Nantucket Wrentham
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-2
Exhibit LJR-3
Map of Combined NEES-EUA Service Territory
<PAGE>
Exhibit LJR-3
[Map of Combined NEES-EUA Service Territory]
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\Ljr-4.wk4 New England Electric System
TEAMS Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit LJR-4
Page 1 of 1
EUA/ NEES TRANSITION TEAMS
- ------------------------------------------------------------------------------------------------------------------------------
General Business Areas
- ------------------------------------------------------------------------------------------------------------------------------
HR &
Supply Retail Information Power Rate/Rev Accou- Communi- Consul-
Chain Companies Systems Company Treasury Req nting cations Legal Other tants
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
R Compen- EO- Retail Trans- Finance Revenue General External Legal Audit A&G Best
sation Central Appli- mission Require- Accounting and Employee Practices
& Benefits Operations cations Marketing ment and Communi-
Rates cations
HR-Labor EO-Central Corporate Trans- Risk Plant Corpo- Plan- Early
Engineering Applic- mission Manage- Accounting rate ning, Decisions
ations Planning ment Gover- Bud- Support
nance gets,
and
Re-
porting
Facil-
ities
HR-Culture EO-Field Divesti- Investor Service Revenue Organization
Integration Operations Operations tures Relations Contracts Accounting Planning
HR-Employee EO-Dispatch- Technology Nuclear Property Payroll Team
Relations ing Services Issues Tax Support
Asset
SCM- CS-Call Y2000 PPA/PS Taxes Separa-
Inventory Center A Power tion
Contracts
SCM-Goods CS-Meters IS Support NEPOOL Issues Records
Management
SCM-Accounts CS-Billing "Cut-over"Plan
Payables "Tier 1 Transition Teams
Health and CS-Credit
Safety & Collections
Benefit Plan RM&S-Demand
Funding Side Management
RM&S-Business Services
Telecommunication
Property
Environmental and Safety
External Affairs
- ---------------------------------------------------------------------------------------------------------------------------------
Transition Steering Committee
Chairmen: T. Rogers / R. Powderly
- ---------------------------------------------------------------------------------------------------------------------------------
DC Kennedy LJ Reilly DL Holt PG Flynn J. Zschokke TL Schwennese WR Richer SM Stevens MA Katz T. Rogers Mercer
Management
HE Stapleford JL McGrath Consultants
- ---------------------------------------------------------------------------------------------------------------------------------
B Hassan J Carney W Norko K Kirby C Hebert D. St.Pierre A.Camara F. Mason D Fazzone M Hirsh
- ---------------------------------------------------------------------------------------------------------------------------------
Key Coordination Areas
- ---------------------------------------------------------------------------------------------------------------------------------
Regulatory Unregulated NGG Coord:
Approvals Businesses
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-5
Exhibit LJR-5
Mass. Electric's Present Performance Standards
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit LJR-5
Page 1 of 3
MASSACHUSETTS ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Under the retail access tariffs, the Company shall establish
performance standards for reliability and customer service. The standards are
designed as a penalty-only approach, under which the Company would be penalized
if its performance did not meet the standards, and there would be no reward for
performance which exceeds the standard. The standards are set based on averages
of historic data, as shown on page 3 of this exhibit. In the event that the
Department establishes additional performance standards or performance standards
for reliability and customer satisfaction for all electric utilities in
Massachusetts that are more stringent than the standards set forth below, then
Mass. Electric shall implement the additional or more stringent standards.
SERVICE RELIABILITY PERFORMANCE STANDARD
The Service Reliability Performance Standard shall be set at a
duration of outages per customer served of 105 minutes. An outage is defined as
the loss of electric service to more than one customer for more than one minute.
The duration per customer served is the total length of time in minutes that an
average customer is without service per year. Excluded from reliability
measurements are extraordinary events such as severe storms and load shedding
events resulting from generation or transmission problems. An event excluded
from reliability measurements must meet one of the following criteria:
o The event resulted in customer outages that represent more than
ten percent (10%) of the customers in a district at any given
time during the event;
o The outages resulting from the event were as a result of the
failure of other companies' supply or transmission to
Massachusetts Electric Company customers and restoration of
service was beyond the control of the Company and its employees;
o The circumstances of the event were extraordinary, such as major
disasters, earthquakes, wildfires, floods, hurricanes, tornadoes,
ice storms, wind storms or other weather events beyond the
control of the Company.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit LJR-5
Page 2 of 3
MASSACHUSETTS ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
The schedule of customer credits under the Service Reliability
Performance Standard is as follows:
Duration
of Outages Customer
(minutes) Credit
Up to 105 $0
106 to 112 $125,000
113 to 118 $250,000
119 to 124 $500,000
More than 124 $1,000,000
CUSTOMER SERVICE PERFORMANCE STANDARD
The Customer Service Performance Standard shall be set at a customer
satisfaction level of 85 percent. The Company will commission annual surveys of
its customers to determine their overall level of satisfaction with the Company.
The Company's measurement of customer satisfaction under this standard shall be
based on the percentage of responses in the top three categories of customer
satisfaction under a seven point scale (1=poor and 7=excellent).
The schedule of customer credits under the Customer Service
Performance Standard is as follows: % of Responses In Top Three Categories
Customer (5,6,7) Credits
Less than 76% $1,000,000
76% to 78% $500,000
79% to 81% $250,000
82% to 84% $125,000
85% or more $0
<PAGE>
<TABLE>
<CAPTION>
C:\eua files on disk\Ljr-5.wk4 New England Electric System
STANDARDS Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit LJR-5
Page 3 of 3
MASSACHUSETTS ELECTRIC COMPANY
DEVELOPMENT OF PERFORMANCE STANDARDS
FOR SERVICE RELIABILITY AND CUSTOMER SERVICE
- ------------------------------------------------ ------------------------------------------------------
SERVICE RELIABILITY: CUSTOMER SERVICE:
DURATION OF OUTAGES CUSTOMER SATISFACTION
- ------------------------------------------------ ------------------------------------------------------
% of Respondents
Duration Satisfied or
of Outages Extremely
YEAR (minutes) YEAR Satisfied
<S> <C> <C> <C> <C>
1995 116 1995 * 93%
1994 90 1994 92%
1993 79 1993 87%
1992 74 1992 83%
1991 83 1991 90%
1990 65 1990 93%
1989 100 1989 90%
1988 105 1988 88%
1987 100 1987 91%
1986 86 1986 90%
Mean (Average) 89.8 Mean (Average) 89.5%
Sample Standard Deviation 15.5 Sample Standard Deviation 3.1%
- ------------------------------------------------ ------------------------------------------------------
PERFORMANCE STANDARD 105 PERFORMANCE STANDARD 85%
- ------------------------------------------------ ------------------------------------------------------
Duration per Customer Served (minutes) = * Survey question response changed from four point scale
Customer Minutes Interrupted (extremely satisfied, satisfied, somewhat dissatisfied, very
Number of Customers Served dissatisfied) to seven point scale (1 = poor and 7 = excellent). 1995
amount represents % of responses in top 3 categories, i.e. 5, 6, and 7.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-6
Exhibit LJR-6
Eastern's Present Performance Standards
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-___
Exhibit LJR-6
Page 1 of 4
EASTERN EDISON COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Under the retail access tariffs, Eastern Edison (Company) shall
establish performance standards for reliability and customer service. The
Company shall establish these performance standards to ensure that historic
levels of reliability and customer service are maintained. The standards are set
based on averages of historic data, as shown on page 3. In the event that the
Department establishes additional performance standards or performance standards
for reliability and customer satisfaction for all electric utilities in
Massachusetts that are more stringent than the standards set below, then Eastern
Edison shall implement the additional or more stringent standards.
SERVICE RELIABILITY PERFORMANCE STANDARD
The reliability measure selected measures Company performance at
minimizing outage duration and how quickly the Company responds to an outage
problem. This measure is calculated by most utilities making it an appropriate
benchmark of performance.
The Service Reliability Performance Standard shall be set at a
duration of outage per customer served of 81 minutes. The System Average
Interruption Duration Index (SAIDI) is the total length of time, in minutes, the
average customer is without service per calendar year. An event excluded from
reliability measurements must meet one of the following criteria:
o Any interruption of service lasting more than 24 consecutive
hours for more than 10% of the number of customers being served
at the time of the interruption and interruptions of less than
one minute;
o The outages resulting from the event were as a result of the
failure of other companies' supply or transmission to Eastern
Edison Company customers and restoration of service was beyond
the control of the Company and its employees;
o The circumstances of the event were extraordinary, such as major
disasters, earthquakes, wildfires, floods, hurricanes, tornadoes,
ice storms, wind storms or other weather events beyond the
control of the Company.
The schedule of penalties under Service Reliability Performance
Standard is as follows:
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-___
Exhibit LJR-6
Page 2 of 4
EASTERN EDISON COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Duration Eastern
of Outage Edison
(minutes) Penalty
up to 81 $0
82 to 88 $62,500
89 to 95 $125,000
96 to 102 $187,000
103 or more $250,000
CUSTOMER SERVICE PERFORMANCE STANDARD
The Customer Service Performance Standard shall be set at a customer
satisfaction level of 76 percent. The customer service measure selected is the
result of a Customer Attitude Survey. The Company will utilize the results of
the EUA Customer Attitude Survey produced by Cambridge Reports Research
International (CRRI) to track this measure. This survey is used as part of the
Company's "Teaming Up for Performance" employee incentive program.
The Company has historic data from 1991 through the present as a
benchmark. The Company's measurement is based on the percentage of responses in
the top three categories (categories 5,6, & 7) of customer satisfaction under a
seven point scale (1 = poor and 7 = excellent).
The schedule of penalties under Customer Service Performance Standard
is as follows:
Duration Eastern
of Outage Edison
(minutes) Penalty
less than 66% $250,000
67% to 69% $187,000
70% to 72% $125,000
73% to 75% $62,500
76% or more $0
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-___
Exhibit LJR-6
Page 3 of 4
EASTERN EDISON COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
PERFORMANCE STANDARDS: DURATION OF OUTAGE (SAIDI)
Historic Data
Duration of
Outage
Year (Minutes)
---- --------------
1996 97
1995 66
1994 77
1993 64
1992 49
1991 48
1990 71
1989 64
1988 56
1987 74
1986 74
Mean (Average) 67.3
Sample Standard Deviation 13.2
Performance Standard 81
Duration Eastern
of Outage Edison
(minutes) Penalty
--------- --------
up to 81 $0
82 to 88 $62,500
89 to 95 $125,000
96 to 102 $187,000
103 or more $250,000
SAIDI is defined as:
Total # of customer outage hours X 60
Average number of customers served
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-___
Exhibit LJR-6
Page 4 of 4
EASTERN EDISON COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
PERFORMANCE STANDARDS:
CUSTOMER ATTITUDE SURVEY
Historic Data
Of Responses
In Top Three
Categories
Year (5, 6, & 7)
---- -------------
1996 84%
1995 81%
1994 82%
1993 78%
1992 72%
1991 84%
Mean (Average) 80%
Sample Standard Deviation 4%
Performance Standard 76%
% of Responses
in Top Three Eastern
Categories Edison
(5, 6, & 7) Penalty
less than 66% $250,000
67% to 69% $187,000
70% to 72% $125,000
73% to 75% $62,500
76% or more $0
Customer Attitude Survey is based on the percentage of responses in the top
three categories (categories 5, 6, & 7) of customer satisfaction under a seven
point scale. (1 = poor and 7 = excellent)
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-7
Exhibit LJR-7
Proposed Performance Standards After Consolidation Date (Marked to
Show Changes)
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit LJR-7
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Under the retail access tariffs, the Massachusetts Electric Company
("Mass. Electric or "the Company") shall establish performance standards for
reliability and customer service. The standards are designed as a penalty-only
approach, under which the Company would be penalized if its performance did not
meet the standards, and there would be no reward for performance which exceeds
the standard. The standards are set based on averages of historic data, as shown
on page 3 of this exhibit. In the event that the Department establishes
additional performance standards or performance standards for reliability and
customer satisfaction for all electric utilities in Massachusetts that are more
stringent than the standards set forth below, then Mass. Electric shall
implement the additional or more stringent standards.
SERVICE RELIABILITY PERFORMANCE STANDARD
The Service Reliability Performance Standard shall be set at a
duration of outages per customer served of [[105]] [96] minutes. An outage is
defined as the loss of electric service to more than one customer for more than
one minute. The duration per customer served is the total length of time in
minutes that an average customer is without service per year. Excluded from
reliability measurements are extraordinary events such as severe storms and load
shedding events resulting from generation or transmission problems. An event
excluded from reliability measurements must meet one of the following criteria:
o The event resulted in customer outages that represent more than
ten percent (10%) of the customers in a district at any given
time during the event;
o The outages resulting from the event were as a result of the
failure of other companies' supply or transmission to
[[Massachusetts Electric]] Company customers and restoration of
service was beyond the control of the Company and its employees;
o The circumstances of the event were extraordinary, such as major
disasters, earthquakes, wildfires, floods, hurricanes, tornadoes,
ice storms, wind storms or other weather events beyond the
control of the Company.
The schedule of customer credits under the Service Reliability
Performance Standard is as follows:
Legend: [ ] = insertion
[[ ]] = deletion
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit LJR-7
Page 2 of 2
MASSACHUSETTS ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Duration
Of Outages Customer
(minutes) Credit
Up to [[105]] [96] $0
[[106]] [97] to [[112]] [103] $[[125,000]] [156,250]
[[113]] [104] to [[118]] [110] $[[250,000]] [312,500]
[[119]] [111] to [[124]] [117] $[[500,000]] [625,000]
More than [[124]] [117] $[[1,000]] [1,250,000]
CUSTOMER SERVICE PERFORMANCE STANDARD
The Customer Service Performance Standard shall be set at a customer
satisfaction level of [[85]] [86] percent. The Company will commission annual
surveys of its customers to determine their overall level of satisfaction with
the Company. The Company's measurement of customer satisfaction under this
standard shall be based on the percentage of responses in the top three
categories of customer satisfaction under a seven point scale (1=poor and
7=excellent).
The schedule of customer credits under the Customer Service
Performance Standard is as follows:
% of Responses
In Top Three
Categories Customer
(5,6,7) Credits
Less than 76% $[[1,000]] [1,250,000]
7[[6]][7]% to 7[[8]][9]% $[[500]] [625],000
[[79]][80]% to 8[[1]][2]% $[[250,000]] [312,500]
8[[2]][3]% to 8[[4]][5]% $[[125,000]] [156,250]
8[[5]]6% or more $0
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-8
Exhibit LJR-8
Proposed Performance Standards After Consolidation Date
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit LJR-8
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Under the retail access tariffs, the Massachusetts Electric Company
("Mass. Electric or "the Company") shall establish performance standards for
reliability and customer service. The standards are designed as a penalty-only
approach, under which the Company would be penalized if its performance did not
meet the standards, and there would be no reward for performance which exceeds
the standard. The standards are set based on averages of historic data, as shown
on page 3 of this exhibit. In the event that the Department establishes
additional performance standards or performance standards for reliability and
customer satisfaction for all electric utilities in Massachusetts that are more
stringent than the standards set forth below, then Mass. Electric shall
implement the additional or more stringent standards.
SERVICE RELIABILITY PERFORMANCE STANDARD
The Service Reliability Performance Standard shall be set at a
duration of outages per customer served of 96 minutes. An outage is defined as
the loss of electric service to more than one customer for more than one minute.
The duration per customer served is the total length of time in minutes that an
average customer is without service per year. Excluded from reliability
measurements are extraordinary events such as severe storms and load shedding
events resulting from generation or transmission problems. An event excluded
from reliability measurements must meet one of the following criteria:
o The event resulted in customer outages that represent more than
ten percent (10%) of the customers in a district at any given
time during the event;
o The outages resulting from the event were as a result of the
failure of other companies' supply or transmission to Company
customers and restoration of service was beyond the control of
the Company and its employees;
o The circumstances of the event were extraordinary, such as major
disasters, earthquakes, wildfires, floods, hurricanes, tornadoes,
ice storms, wind storms or other weather events beyond the
control of the Company.
The schedule of customer credits under the Service Reliability
Performance Standard is as follows:
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit LJR-8
Page 2 of 2
MASSACHUSETTS ELECTRIC COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
Duration
Of Outages Customer
(minutes) Credit
Up to 96 $0
97 to 103 $156,250
104 to 110 $312,500
111 to 117 $625,000
More than 117 $1,250,000
CUSTOMER SERVICE PERFORMANCE STANDARD
The Customer Service Performance Standard shall be set at a customer
satisfaction level of 86 percent. The Company will commission annual surveys of
its customers to determine their overall level of satisfaction with the Company.
The Company's measurement of customer satisfaction under this standard shall be
based on the percentage of responses in the top three categories of customer
satisfaction under a seven point scale (1=poor and 7=excellent).
The schedule of customer credits under the Customer Service
Performance Standard is as follows: % of Responses In Top Three Categories
Customer (5,6,7) Credits
Less than 76% $1,250,000
77% to 79% $625,000
80% to 82% $312,500
83% to 85% $156,250
86% or more $0
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-9
Exhibit LJR-9
Derivation of Duration of Outage Standard
<PAGE>
C:\eua files on disk\Ljr-9.WK4 New England Electric System
SAIDI-MA Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-___
Exhibit LJR-9
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
EASTERN EDISON COMANY
PROPOSED COMBINED PERFORMANCE STANDARDS FOR RELIABILITY
--------------------------------
SERVICE RELIABILITY:
DURATION OF OUTAGES (SAIDI)
--------------------------------
Duration
of Outages
Year (minutes)
1998 80
1997 84
1996 99
1995 108
1994 76
1993 77
1992 70
1991 78
Mean (Average) 84
Sample Standard Deviation 12.1
----------------------------------------------------------------
PERFORMANCE STANDARD BASELINE
Duration per Customer Served = 96
----------------------------------------------------------------
Duration per Customer Served (minutes) = Customer Minutes Interrupted
----------------------------
Average Number of Customers
Served
-------------------------------------------
SCHEDULE OF PENALTIES
-------------------------------------------
Duration of
Outages Customer
(Minutes) Credit
===================== ===========
Minimum Maximum
------- -------
up to 96 $0
97 103 $156,250
104 110 $312,500
111 117 $625,000
more than 117 $1,250,000
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-___
Exhibit LJR-9
Page 2 of 2
Massachsuetts Electric Company
Eastern Edison Company
Derivation of Combined Reliablity Standard
for Duration of Outages (SAIDI)
===========================================
Eastern Edison
Performance Standard = 81
-------------------------------------------
-------------------------------------------
Cust Hrs In# Cust Int.Ave. Cust SAIDI
-------------------------------------------
1991 139,418 195,816 174,204 48
1992 143,836 180,408 174,944 49
1993 188,591 243,817 176,070 64
1994 227,715 265,283 177,603 77
1995 196,281 211,833 179,346 66
1996 292,478 335,617 180,863 97
1997 236,748 250,976 182,672 78
1998 149,437 231,484 182,672 49
===========================================
Average 66
===========================================
STD 16
===========================================
Baseline 82
===========================================
===========================================
Massachusetts Electric (Including Nantucket
Electric in 1998)
Performance Standard = 105
-------------------------------------------
-------------------------------------------
Cust Hrs In# Cust Int.Ave. Cust SAIDI
-------------------------------------------
1991 1,290,690 991,154 929,885 83
1992 1,160,294 971,684 936,480 74
1993 1,246,980 922,246 942,710 79
1994 1,196,328 1,003,317 950,950 75
1995 1,852,848 1,296,755 961,035 116
1996 1,616,230 1,291,653 970,420 100
1997 1,396,605 1,126,221 984,875 85
1998 1,442,755 1,185,766 1,006,475 86
===========================================
Average 87
===========================================
STD 13
===========================================
Baseline 100
===========================================
===========================================
Massachusetts Composite
---------------------------------------------
---------------------------------------------
Cust Hrs Int # Cust Int. Ave. Cust SAIDI
---------------------------------------------
1991 1,430,108 1,186,970 1,104,089 78
1992 1,304,130 1,152,092 1,111,424 70
1993 1,435,571 1,166,063 1,118,780 77
1994 1,424,043 1,268,600 1,128,553 76
1995 2,049,129 1,508,588 1,140,381 108
1996 1,908,708 1,627,270 1,151,283 99
1997 1,633,353 1,377,197 1,167,547 84
1998 1,592,192 1,417,250 1,189,147 80
===============================================
Average 84
===============================================
STD 12.1
===============================================
Baseline 96.1
===============================================
Notes
-----
1. The Performance Standard is based on the average of historic data less
one standard deviation.
2. Mass. Electric data includes Nantucket Electric beginning in 1998.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit LJR-10
Exhibit LJR-10
Calculation of Customer Satisfaction Measure
<PAGE>
C:\eua files on disk\Ljr-10.WK4 New England Electric System
RELIAB-MA Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit LJR-10
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
EASTERN EDISON COMPANY
PROPOSED COMBINED PERFORMANCE STANDARDS FOR CUSTOMER SERVICE
--------------------------------
CUSTOMER SERVICE:
CUSTOMER SATISFACTION
--------------------------------
% of Respondents
Satisfied or
Extremely
Year Satisfied
1998 89%
1997 82%
1996 86%
1995 90%
1994 91%
1993 89%
1992 93%
1991 92%
Mean (Average) 89%
Sample Standard Deviation 3%
----------------------------------------------------------------
PERFORMANCE STANDARD BASELINE
Customer Satisfaction Index = 86%
----------------------------------------------------------------
Customer Satisfaction = percentage of responses in the top
three categories of customer satisfaction under the seven point
scale.
(1=poor and 7 = excellent)
-------------------------------------------
SCHEDULE OF PENALTIES
-------------------------------------------
% of Respondents
Satisfied or
Extremely Customer
Satisfied Credit
===================== ===========
Minimum Maximum
------- -------
86% or more $0
83% 85% $156,250
80% 82% $312,500
77% 79% $625,000
less than 76% $1,250,000
<TABLE>
<CAPTION>
C:\eua files on disk\Ljr-10.WK4 New England Electric System
RELIAB CALC Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit LJR-10
Page 2 of 2
Massachsuetts Electric/ Eastern Edison
Derivation of Combined Customer Satisfaction Standard
for Residential Customers - Top 3 Categories on a 7-Point Scale
======================================================================================
Eastern Edison - BROCKTON Eastern Edison - FALL RIVER
Performance Standard =76% Performance Standard =76%
--------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------
Percent Scale Value Total Percent Scale Value Total
5 6 7 5 6 7
--------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1991 31% 20% 33% 84% 26% 24% 31% 81%
1992 28% 21% 27% 76% 30% 22% 25% 77%
1993 27% 19% 31% 77% 25% 22% 33% 80%
1994 22% 23% 36% 81% 20% 18% 42% 80%
1995 21% 23% 35% 79% 22% 24% 41% 87%
1996 24% 21% 38% 83% 21% 17% 49% 87%
1997 24% 25% 36% 85% 18% 21% 42% 81%
1998 20% 19% 41% 80% 19% 17% 50% 86%
======================================================================================
Average 81% 82%
======================================================================================
STD 3.0% 3.5%
======================================================================================
Baseline 78% 79%
======================================================================================
======================================================================================
Massachusetts Electric MASSACHUSETTS COMPOSITE
--------------------------------
Performance Standard = 85% WEIGHTED AVERAGE
------------------------------------------- -----------
Percent Scale Value Total Total
5 6 7 Brockton Fall River Mass. Elec.
--------------------------------------------------------------------------------------
1991 90% 9% 4% 76% 89%
1992 83% 8% 4% 70% 82%
1993 87% 8% 4% 73% 86%
1994 92% 9% 4% 78% 90%
1995 20% 24% 49% 93% 8% 4% 78% 91%
1996 21% 24% 45% 90% 9% 4% 76% 89%
1997 18% 24% 53% 95% 9% 4% 80% 93%
1998 17% 25% 52% 94% 8% 4% 79% 92%
======================================================================================
Average 90.5% 89%
======================================================================================
STD 3.7% 3%
======================================================================================
Baseline 87% 86%
======================================================================================
CUSTOMER WEIGHT
---------------------------------------------------------------------------------------
Mass. % Weight % Weight % Weight
Eastern = Brockton + Fall River Elec Total Brockton Fall River Mass. Elec.
---------------------------------------------------------------------------------------
1991 174,204 118,459 55,745 929,885 1,104,089 11% 5% 84%
1992 174,944 118,962 55,982 936,480 1,111,424 11% 5% 84%
1993 176,070 119,728 56,342 942,710 1,118,780 11% 5% 84%
1994 177,603 120,770 56,833 950,950 1,128,553 11% 5% 84%
1995 179,346 121,955 57,391 961,035 1,140,381 11% 5% 84%
1996 180,863 122,987 57,876 970,420 1,151,283 11% 5% 84%
1997 182,672 124,217 58,455 984,875 1,167,547 11% 5% 84%
1998 182,672 124,217 58,455 997,016 1,179,688 11% 5% 85%
Notes
-----
1. EUA Surveys are conducted by Cambridge Reports
2. NEES Surveys were conducted by Cambridge Reports up to 1995. Now
conducted by Applied Marketing Science (1996 - 1998). In the years 1991
- 1995 survey question responses were based on a 4-point scale
(extremely satisfied, somewhat dissatisfied, very dissatisfied) and
percentages shown represent the top 2 categories on the 4-point scale.
3. The Performance Standard is based on the average of historic data less
one standard deviation. Massachusetts composite is based on a weighted
value by number of customers for each company in each year. Each
year's weight is the percentage of each company's number of customers
as a percent of the total number of customers.
</TABLE>
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99- ______
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
JENNIFER K. ZSCHOKKE
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99- ______
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
JENNIFER K. ZSCHOKKE
Table of Contents
Page
I. Qualifications 1
II. Purpose of Testimony and Summary of Filing 1
III. Consolidation of Distribution Companies 3
IV. Consolidation of Transmission Companies 7
V. Short-Term Financing for the Transition Period 9
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 1 of 10
<S> <C>
1 I. Qualifications
2 Q. Please state your name, title, and business address.
3 A. My name is Jennifer K. Zschokke. I am Manager of Finance for New England Power
4 Service Company (NEPSCO), a New England Electric System (NEES) Company. My
5 business address is 25 Research Drive, Westborough, MA 01582.
6
7 Q. Please describe your educational background and training.
8 A. I have earned a Bachelor of Arts degree in Management Science from Westminster
9 College and a Masters of Science in Finance from Boston College.
10
11 Q. Please describe your professional experience.
12 A. I joined NEPSCO in 1987 as an assistant financial analyst and have been promoted several
13 times within the Finance Department, most recently to Manager in 1998. My
14 responsibilities include the long and short-term financing of NEES and its subsidiaries. In
15 addition, the Finance Department provides a variety of financial advisory services to other
16 functions in the NEES System.
17
18 II. Purpose of Testimony and Summary of Filing
19 Q. What is the purpose of your testimony?
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 2 of 10
1 A. I will describe, from a financial perspective, the consolidation of the subsidiary companies
2 of NEES and Eastern Utilities Associates (EUA) which operate in the state of
3 Massachusetts. Specifically, I will explain the planned merger of Eastern Edison Company
4 (Eastern), an EUA distribution company, with and into Massachusetts Electric Company
5 (Mass. Electric), a NEES distribution company. Similarly, I will explain the planned
6 merger of Montaup Electric Company (Montaup), the EUA wholesale transmission
7 company, with and into New England Power Company (NEP), the NEES wholesale
8 transmission company. In addition, I will explain the financing benefits that will result
9 from the acquisition of EUA by NEES.
10 I will also address NEES's plan to include EUA and its regulated subsidiaries in the
11 NEES Moneypool, which is currently an efficient means for managing the daily cash
12 position of NEES and its subsidiaries.
13
14 Q. What approvals are you requesting from the Massachusetts Department of
15 Telecommunications and Energy (Department)?
16 A. The mergers require approval of the Department under Section 96 of Chapter 164. As I
17 will discuss later, Mass. Electric will be issuing preferred stock in exchange for the
18 preferred stock of Eastern and will be assuming liabilities for Eastern's pollution control
19 revenue bonds first mortgage and possibly its first mortgage bonds. I am advised by
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 3 of 10
1 counsel that this transaction requires authorization under Section 99. As explained in the
2 filing letter, further authority is also requested from the Department under Sections 9A,
3 14, 15, 15A, 16, 18 or 19 to the extent it is necessary.
4 As mentioned above, we are requesting that after the merger of NEES and EUA
5 the regulated subsidiaries of EUA be authorized to participate in the NEES Moneypool
6 which is authorized under Section 17A. Other approvals are also requested of the
7 Department as part of this filing, but are addressed by other witnesses.
8
9 Q. When do you propose to consolidate the operating subsidiaries?
10 A. Subject to the receipt of necessary regulatory approvals, our objective is to complete the
11 merger of the operating subsidiaries during the first half of 2000.
12
13 III. Consolidation of Distribution Companies
14 Mass Electric and Eastern
15
16 Q. Please describe the balance sheets of Mass. Electric and Eastern as of year end 1998.
17 A. Please see Exhibit JKZ-1 for Mass. Electric's year end 1998 balance sheet and JKZ-2 for
18 Eastern's year end 1998 balance sheet. Mass. Electric is noticeably larger than Eastern.
19 This is evidenced by the fact that assets and liabilities for Mass. Electric total $1.455
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 4 of 10
1 billion and are approximately three times the size of Eastern's total assets and liabilities of
2 $522 million. At year end 1998, Mass. Electric owned $1.143 billion of net utility plant
3 and Eastern owned $151 million (excluding its interest in Montaup), approximately a
4 seven fold differential. As for capital structure, Mass. Electric and Eastern have similar
5 capitalization ratios as of year end 1998.
6
7 Q. Please describe where Mass. Electric and Eastern fit into the organizational structure of
8 the NEES and EUA systems, respectively.
9 A. Mass. Electric is a direct subsidiary of NEES which is a holding company subject to the
10 Public Utility Holding Company Act of 1935 (Holding Company Act). Similarly, Eastern
11 is a direct subsidiary of EUA which is also a holding company subject to the Holding
12 Company Act. NEES owns 100% of the common stock of Mass. Electric and EUA holds
13 100% of the common stock of Eastern. Both Mass. Electric and Eastern operate solely in
14 Massachusetts for the purpose of distributing electricity to the retail customer.
15
16 Q. Do either Mass. Electric or Eastern have any subsidiaries?
17 A. Mass. Electric does not have any subsidiaries. However, within the EUA system today,
18 Eastern is the sole owner of Montaup's securities, including 100% of the common equity.
19 Therefore, Montaup is a wholly owned subsidiary of Eastern and an indirect subsidiary of
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 5 of 10
1 EUA.
2
3 Q. Are you aware of any changes in the EUA corporate organizational structure which may
4 occur prior to NEES's acquisition of EUA?
5 A. Yes. Eastern is contemplating a spin off its investment in Montaup to EUA. Thus, EUA
6 would hold Montaup's stock directly rather than indirectly through its ownership of
7 Eastern. The spinoff of Montaup by Eastern would i) complete the functional unbundling
8 of the generation business from the distribution business through the complete corporate
9 separation of Eastern and Montaup, ii) eliminate any risk that Eastern may have associated
10 with its direct ownership of Montaup pertaining to, for example, contingent liabilities and
11 nuclear ownership, iii) isolate Eastern's capital structure so that it applies to distribution
12 ratemaking only, and iv) simplify EUA's corporate structure. We will update the
13 Department during the proceeding as the details of this plan become available.
14
15 Q. What are the financial transactions necessary to consolidate Eastern with Mass. Electric?
16 A. Eastern would merge with and into Mass. Electric. Mass. Electric will assume the
17 obligation for repayment of Eastern's indebtedness. Mass Electric will issue preferred
18 stock to the holders of Eastern in exchange for their existing preferred stock. In addition,
19 we expect that Montaup will repay its debt and preferred stock held by Eastern.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 6 of 10
1 Q. Have you prepared a proforma balance sheet illustrating the impact of these transactions?
2 A. Yes. Exhibit JKZ-3 illustrates the impact of the merger of Eastern and Mass. Electric, the
3 spinoff of Montaup and the repayment by Montaup of its debt and preferred stock. As
4 permitted by accounting rules, the balance sheet of the combined entity will reflect the sum
5 of the balance sheets of the separate entities prior to the subsidiary merger.
6
7 Q. Are there any savings associated with the Eastern refinancing?
8 A. Yes. Because Mass. Electric is a larger company with higher credit ratings than Eastern,
9 Mass. Electric is able to access capital markets at rates generally lower than those Eastern
10 is able to obtain. Mass. Electric is rated "A1" by Moody's Investors Service, and "A+" by
11 Standard and Poor's, and "AA- " by Duff & Phelps Credit Rating Company. Eastern's
12 ratings are "Baa1", "BBB+", and "A-", respectively.
13
14 Q. How much do you expect the financing savings to be?
15 A. The difference between Eastern's cost of debt and Mass. Electric's, due solely to the
16 difference in credit rating is approximately 15 basis points in today's marketplace.
17 Historically this differential has been as high as 50 basis points. In addition to this spread,
18 Eastern would typically pay another 10 to 15 basis points more than Mass. Electric
19 because of the smaller size of its bond issuances and the overall illiquidity of those bonds.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 7 of 10
1 The total savings, which will be realized as Eastern's debt is refinanced, would be
2 approximately $300,000 to $400,000 per year.
3
4 IV. Consolidation of Transmission Companies
5 NEP and Montaup
6
7 Q. Please describe where NEP and Montaup fit into the organizational structure of the NEES
8 and EUA systems, respectively.
9 A. Similar to Mass. Electric, NEP is a direct subsidiary of NEES. This means that NEES
10 owns 100% of the common stock of NEP. Montaup is an indirect subsidiary of EUA
11 today; however, as I previously mentioned, Eastern is contemplating a spin off of 100% of
12 its ownership of the common stock of Montaup to EUA prior to the NEES's acquisition of
13 EUA.
14 NEP operates in several states, which include Massachusetts, Rhode Island, New
15 Hampshire, and Vermont. Montaup operates in Massachusetts and Rhode Island. Both
16 NEP and Montaup have minority interests in nuclear properties in Connecticut, Maine,
17 New Hampshire and Vermont as well as a fossil unit in Maine. Since the divestiture of
18 substantially all of its generating business in 1998, NEP is primarily a transmission
19 company. Montaup recently completed the sale of the Canal and Somerset generating
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 8 of 10
1 stations and anticipates closing on its share of Wyman 4 shortly. Therefore, Montaup is
2 primarily a transmission company going forward similar to NEP.
3 In addition, NEP and Montaup each recover through Contract Termination
4 Charges (CTC's), stranded costs associated with prior investments in the generating
5 business. NEP and Montaup collect CTC's from affiliated and nonaffiliated customers.
6 Mass. Electric pays 72.6% of NEP's, and Eastern pays 59.0% of Montaup's total stranded
7 costs recovered through CTC's. Mass. Electric and Eastern recover their costs associated
8 with the CTC from distribution customers through a Transition Charge authorized by the
9 Massachusetts Utility Restructuring Act of 1997 as well as a Federal Energy Regulatory
10 Commission (FERC) approved settlement with various state parties.
11
12 Q. Please describe the balance sheets of NEP and Montaup?
13 A. Please see Exhibit JKZ-4 and JKZ-5, respectively. At year end 1998, NEP's balance sheet
14 was approximately four times the size of Montaup's. NEP's assets and liabilities totaled
15 $2.415 billion and Montaup's assets and liabilities totaled $641 million. As of year end,
16 NEP owned $458 million of net utility plant, most of which is transmission and Montaup
17 owned about $341 million of net utility plant, which still included the Somerset units
18 subsequently sold on April 27, 1999. Both NEP and Montaup have significant regulatory
19 assets which represent the future collection of Contract Termination Charges. As for
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 9 of 10
1 capital structure, NEP and Montaup have similar capitalization ratios as of year end 1998.
2
3 Q. What are the financial transactions necessary to implement the consolidation of Montaup
4 and NEP?
5 A. Montaup will merge with and into NEP, and their balance sheets will be consolidated,
6 similar to the Mass. Electric/Eastern combination. We are assuming as part of this
7 transaction, NEP uses its cash on hand to pay off Montaup's debentures and preferred
8 stock currently held by Eastern. In addition, $147 million of common equity is expected
9 to be repaid to the parent.
10
11 Q. Have you prepared proforma financial statements for the merger of NEP and Montaup?
12 A. Yes. Exhibit JKZ-6 illustrates the impact of the merger of Montaup and NEP, and the
13 repayment by Montaup of its debt and preferred stock. As permitted by accounting rules,
14 the balance sheet of the combined entity will reflect the sum of the balance sheets of the
15 separate entities prior to the subsidiary merger.
16
17 V. Short-Term Financing for the Transition Period
18
19 Q. Please explain NEES's request to include EUA and its subsidiaries in the NEES
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of J. K. Zschokke
Page 10 of 10
1 Moneypool.
2 A. We are proposing that for the period between the NEES acquisition of EUA and the
3 merger of the subsidiaries, that the EUA regulated subsidiaries be granted approval to
4 participate in the NEES Moneypool both as borrowers and investors. The NEES
5 Moneypool is an efficient method of utilizing the excess cash of affiliated companies to
6 meet the needs of borrowing companies on a daily basis. This process reduces the
7 transaction costs that would otherwise be incurred if the affiliates were to invest or
8 borrow in the public markets. It also provides opportunities for those smaller companies
9 who do not have the ability to readily access public markets. The NEES Moneypool has
10 been in existence since 1981, and participation is authorized by the Department. For these
11 reasons, it is desirable to grant the same opportunities to the regulated EUA subsidiaries
12 once they are subsidiaries of NEES by amending the NEES Moneypool.
13
14 Q. Are there any other issues pertaining to the consolidation of the subsidiary companies?
15 A. No. This concludes my testimony.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
EXHIBITS
OF
JENNIFER K. ZSCHOKKE
JKZ-1 Massachusetts Electric Company 1998 Balance Sheet
JKZ-2 Eastern Edison Company 1998 Balance Sheet
JKZ-3 Proforma Balance Sheet Illustrating Mass. Electric and Eastern
Merger
JKZ-4 New England Power Company 1998 Balance Sheet
JKZ-5 Montaup Electric Company 1998 Balance Sheet
JKZ-6 Proforma Balance Sheet Illustrating NEP and Montaup Merger
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JKZ-1
Exhibit JKZ-1
Massachusetts Electric Company 1998 Balance Sheet
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit JKZ-1
Page 1 of 1
MASSACHUSETTS ELECTRIC COMPANY
1998 BALANCE SHEET
Dollars in Thousands
DECEMBER 31,
1998
Line ASSETS
1 Utility Plant, at original cost $1,626,569
2 Less: Accumulated Depreciation 499,975
-------
3 1,126,594
4 Construction Work in Progress 16,575
------
5 Net Utility Plant 1,143,169
6
7 Cash 6,994
8 Accounts Receivable, Associated Companies 6,629
9 Other Current Assets 256,535
10
11 Deferred Charges and Other Assets 41,235
------
12
13 TOTAL ASSETS 1,454,562
14
15
16 CAPITALIZATION AND LIABILITIES
------------------------------
17 Common Equity 508,203
18 Preferred Stock 10,674
19 Long-term Debt 353,329
-------
20 Total Capitalization 872,206
21
22 Long Term Debt due within one year 15,000
23 Short-term Debt 80,725
24 Other Current Liabilities 186,163
25
26 Deferred State and Federal Income Taxes 200,965
27 Unamortized Investment Tax Credits 14,377
28 Other Liabilities 85,126
29
30 TOTAL CAPITALIZATION AND LIABILITIES $1,454,562
31
32 CAPITALIZATION RATIOS
33 Common Equity 58%
34 Preferred Stock 1%
35 Long-term Debt 41%
36 Total Capitalization 100%
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JKZ-2
Exhibit JKZ-2
Eastern Edison Company 1998 Balance Sheet
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit JKZ-2
Page 1 of 1
EASTERN EDISON COMPANY
1998 BALANCE SHEET
Dollars in Thousands
DECEMBER 31,
1998
Line ASSETS
1 Utility Plant, at original cost $245,700
2 Less: Accumulated Depreciation 96,143
------
3 149,557
4 Construction Work in Progress 1,384
-----
5 Net Utility Plant 150,941
6
7 Investments in Subsidiary 266,499
8
9 Cash 25,798
10 Accounts Receivable, Associated
Companies 16,883
11 Other Current Assets 43,277
12
13 Deferred Charges and Other Assets 18,645
------
14
15 TOTAL ASSETS 522,043
16
17
18 CAPITALIZATION AND LIABILITIES
19 Common Equity 225,998
20 Preferred Stock 27,995
21 Long-term Debt 162,550
-------
22 Total Capitalization 416,543
23
24 Long Term Debt due within one year 0
25 Short-term Debt 0
26 Other Current Liabilities 69,269
27
28 Deferred State and Federal Income Taxes 20,076
29 Unamortized Investment Tax Credits 3,310
30 Other Liabilities 12,845
------
31
32 TOTAL CAPITALIZATION AND LIABILITIES $522,043
33
34 CAPITALIZATION RATIOS
---------------------
35 Common Equity 54%
36 Preferred Stock 7%
37 Long-term Debt 39%
---
38 Total Capitalization 100%
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JKZ-3
Exhibit JKZ-3
Proforma Balance Sheet Illustrating Mass. Electric and Eastern Merger
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit JKZ-3
Page 1 of 1
MASSACHUSETTS ELECTRIC COMPANY
EASTERN EDISON COMPANY
PROFORMA BALANCE SHEET - MERGED
Dollars in Thousands
<TABLE>
<CAPTION>
ACTUAL PRO-FORMA
------------------- -------------------------
MASS. IMPACT OF
ELECTRIC EASTERN NEP/MONTAUP MERGED
1998 1998 MERGER COMPANY
Line ASSETS
---- ------
<S> <C> <C> <C> <C> <C>
1 Utility Plant, at original cost $1,626,569 $245,700 $1,872,269
2 Less: Accumulated Depreciation 499,975 96,143 596,118
-------- ------- -------
3 1,126,594 149,557 1,276,151
4 Construction Work in Progress 16,575 1,384 17,959
------- ------ ------
5 Net Utility Plant 1,143,169 150,941 1,294,110
6
7 Investment in Subsidiary NA 266,499 (266,499) 0
8
9 Cash 6,994 25,798 38,757 (a) 71,549
10 Accounts Receivable, Associated
Companies 6,629 16,883 23,512
11 Other Current Assets 256,535 43,277 299,812
12
13 Deferred Charges and Other Assets 41,235 18,645 59,880
------- ------- ------
14
15 TOTAL ASSETS 1,454,562 522,043 (227,742) 1,748,863
16
17
18 CAPITALIZATION AND LIABILITIES
19 Common Equity 508,203 225,998 (147,017) (b) 587,184 (c)
20 Preferred Stock 10,674 27,995 0 38,669
21 Long-term Debt 353,329 162,550 0 515,879
-------- -------- - -------
22 Total Capitalization 872,206 416,543 (147,017) 1,141,732
23
24 Long Term Debt due within one year 15,000 0 15,000
25 Short-term Debt 80,725 0 (80,725) (a) 0
26 Other Current Liabilities 186,163 69,269 255,432
27
28 Deferred State and Federal
Income Taxes 200,965 20,076 221,041
29 Unamortized Investment Tax Credits 14,377 3,310 17,687
30 Other Liabilities 85,126 12,845 97,971
------- ------- ------
31
32 TOTAL CAPITALIZATION AND
LIABILITIES $1,454,562 $522,043 ($227,742) $1,748,863
33
34 CAPITALIZATION RATIOS
---------------------
35 Common Equity 58% 54% 51%
36 Preferred Stock 1% 7% 3%
37 Long-term Debt 41% 39% 45%
--- --- ---
38 Total Capitalization 100% 100% 100%
Notes:
(a) See Exhibit JKZ-6, Line 23. Proceeds from redemption of Montaup
debt and preferred use to paydown short-term debt and increase
cash.
(b) See Exhibit JKZ-5, Line 20.
(c) The merged balance sheet does not reflect the impact of
"push-down" accounting and the aquisition premium.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JKZ-4
Exhibit JKZ-4
New England Power Company 1998 Balance Sheet
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit JKZ-4
Page 1 of 1
NEW ENGLAND POWER COMPANY
1998 BALANCE SHEET
Dollars in Thousands
DECEMBER 31,
1998
Line ASSETS ----
---- ------
1 Utility Plant, at original cost $1,262,461
2 Less: Accumulated Depreciation 837,637
-------
3 424,824
4 Construction Work in Progress 33,289
------
5 Net Utility Plant 458,113
6
7 Investments (Including in Subsidiaries) 88,121
8
9 Cash 179,413
10 Accounts Receivable, Associated Companies 107,878
11 Other Current Assets 63,362
12
13 Regulatory Assets 1,512,562
14 Deferred Charges and Other Assets 5,339
15
16 TOTAL ASSETS 2,414,788
17
18
19 CAPITALIZATION AND LIABILITIES
------------------------------
20 Common Equity 520,896
21 Preferred Stock 1,567
22 Long-term Debt 371,765
-------
23 Total Capitalization 894,228
24
25 Long Term Debt due within one year 0
26 Short-term Debt 0
27 Other Current Liabilities 199,919
28
29 Deferred State and Federal Income Taxes 165,115
30 Unamortized Investment Tax Credits 30,870
31 Accrued Yankee Nuclear Plant Costs 242,138
32 Purchased Power Obligations 832,668
33 Other Liabilities 49,850
------
34
35 TOTAL CAPITALIZATION AND LIABILITIES $2,414,788
36
37 CAPITALIZATION RATIOS
---------------------
38 Common Equity 58%
39 Preferred Stock 0%
40 Long-term Debt 42%
---
41 Total Capitalization 100%
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JKZ-5
Exhibit JKZ-5
Montaup Electric Company 1998 Balance Sheet
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit JKZ-5
Page 1 of 1
MONTAUP ELECTRIC COMPANY
1998 BALANCE SHEET
Dollars in Thousands
DECEMBER 31
1998
Line ASSETS
1 Utility Plant, at original cost $496,203
2 Less: Accumulated Depreciation 156,158
-------
3 340,045
4 Construction Work in Progress 1,307
-----
5 Net Utility Plant 341,352
6
7 Investments in Subsidiaries 12,881
8
9 Cash 154
10 Accounts Receivable, Associated Companies 66,638
11 Other Current Assets 15,998
12
13 Unrecovered Regulatory Plant Costs 58,503
14 Deferred Charges and Other Assets 145,445
15
16 TOTAL ASSETS 640,971
17
18
19 CAPITALIZATION AND LIABILITIES
------------------------------
20 Common Equity 147,017
21 Preferred Stock 1,500
22 Long-term Debt 117,982
-------
23 Total Capitalization 266,499
24
25 Long Term Debt due within one year 0
26 Short-term Debt 0
27 Other Current Liabilities 69,759
28
29 Deferred State and Federal Income Taxes 99,567
30 Unamortized Investment Tax Credits 9,840
31 Other Liabilities 195,306
32
33 TOTAL CAPITALIZATION AND LIABILITIES $640,971
34
35 CAPITALIZATION RATIOS
---------------------
36 Common Equity 55%
37 Preferred Stock 1%
38 Long-term Debt 44%
---
39 Total Capitalization 100%
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JKZ-6
Exhibit JKZ-6
Proforma Balance Sheet Illustrating NEP and Montaup Merger
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit JKZ-6
Page 1 of 1
NEW ENGLAND POWER COMPANY
MONTAUP ELECTRIC COMPANY
PROFORMA BALANCE SHEET - MERGED
Dollars in Thousands
Actual Pro-Forma
------------------- -------------------------------
Redemption
of Montaup Repayment
NEP Montaup Debt and of Common Merged
1998 1998 Preferred Equity Company
Line Assets ---- ---- --------- --------- -------
---- ------
<S> <C> <C> <C> <C> <C> <C> <C>
1 Utility Plant, at original cost $1,262,461 $496,203 #########
2 Less: Accumulated Depreciation 837,637 156,158 993,795
3 424,824 340,045 764,869
4 Construction Work in Progress 33,289 1,307 34,596
5 Net Utility Plant 458,113 341,352 799,465
6
7 Investments (Including in Subsidiaries) 88,121 12,881 101,002
8
9 Cash 179,413 154 (119,482) (60,085) 0
10 Accounts Receivable, Associated Companies 107,878 66,638 174,516
11 Other Current Assets 63,362 15,998 79,360
12
13 Unrecovered Regulatory Plant Costs 1,512,562 58,503 1,571,065
14 Deferred Charges and Other Assets 5,339 145,445 150,784
15
16 Total Assets 2,414,788 640,971 (119,482) (60,085) 2,876,192
17
18
19 Capitalization and Liabilities
20 Common Equity 520,896 147,017 (147,017) 520,896 (a)
21 Preferred Stock 1,567 1,500 (1,500) 0 1,567
22 Long-term Debt 371,765 117,982 (117,982) 0 371,765
23 Total Capitalization 894,228 266,499 (119,482) (147,017) 894,228
24
25 Long Term Debt due within one year 0 0 0
26 Short-term Debt 0 0 86,932 86,932
27 Other Current Liabilities 199,919 69,759 269,678
28
29 Deferred State and Federal Income Taxes 165,115 99,567 264,682
30 Unamortized Investment Tax Credits 30,870 9,840 40,710
31 Accrued Yankee Costs 242,138 0 242,138
32 Purchased Power Obligations 832,668 0 832,668
33 Other Liabilities 49,850 195,306 245,156
34
35 $2,414,788 $640,971 (119,482) (60,085) 2,876,192
36
37
38 Total Capitalization and Liabilities
39
40 Capitalization Ratios
41 Common Equity 58% 55% 58%
42 Preferred Stock 0% 1% 0%
43 Long-term Debt 42% 44% 42%
44 Total Capitalization 100% 100% 100%
(a) The merged balance sheet does not reflect the impact of "push-down" accounting and the aquisition premium.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
Massachusetts Electric Company and
Eastern Edison Company Rate Plan
Filing In Support of Merger
Volume 2
Testimony & Exhibits of
David M. Webster
Theresa M. Burns
James J. Bonner, Jr.
April 30, 1999
Submitted to:
Massachusetts Department of
Telecommunications and Energy
Docket D.T.E. 99-_____
Submitted by:
NEES Logo
EUA Logo
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
DAVID M. WEBSTER
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
DAVID M. WEBSTER
Table of Contents
Page
----
I. Qualifications........................................................1
II. Purpose of Testimony..................................................3
III. Depreciation Rates....................................................3
IV. Storm Contingency Fund................................................4
V. Environmental Response Fund...........................................7
VI. Other Amortizations and Accounting Adjustments........................9
VII. Conclusion...........................................................10
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 1
<S> <C>
1 QUALIFICATIONS
2 Q. Please state your full name and business address.
3 A. David M. Webster, 25 Research Drive, Westborough, Massachusetts 01582.
4
5 Q. Please state your position.
6 A. I am a Principal Financial Analyst in the Rate Department of New England
7 Power Service Company ("NEPSCO"). NEPSCO provides engineering,
8 technical, accounting, and other services for the New England Electric System
9 ("NEES") Companies, including Massachusetts Electric Company ("Mass.
10 Electric") and Nantucket Electric Company.
11
12 Q. Please describe your educational background and training.
13 A. In 1986, I graduated with distinction from Southeastern Massachusetts University
14 with a Bachelor of Science degree in accounting.
15
16 Q. Please outline your professional experience.
17 A. In 1986, I was hired by NEPSCO as an Assistant Analyst in the Financial
18 Reporting Department. My responsibilities included assisting in the preparation
19 of the various external reporting requirements for NEES and subsidiaries. I was
20 promoted to Analyst in the Financial Analysis section in 1988. My responsibilities
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 2
1 included conducting various calculations and analysis in support of the closing of
2 the accounting books of record for the various NEES companies.
3
4 In 1991, I was promoted to Supervisor of the NEPSCO Accounting Department,
5 responsible for the monthly closing of the accounting books of record as well as
6 all internal and external reporting requirements. In 1992, my supervisory
7 responsibilities were expanded to include overseeing the monthly closing of two
8 additional NEES subsidiaries' books of record as well as all internal and external
9 reporting requirements.
10
11 In 1993, I was promoted to Supervisor of Wholesale Accounting, overseeing the
12 monthly closing and internal reporting requirements for the Wholesale Business
13 unit of NEES. In 1995, I was promoted to Manager of Wholesale Accounting and was
14 given additional responsibilities associated with the Wholesale Accounting
15 section.
16
17 In February 1997, I accepted an assignment to the Rate Department to provide
18 revenue requirement analyses for the NEES retail companies.
19
20 Q. Have you previously testified before a regulatory commission?
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 3
1 A. Yes, I have testified in proceedings before the Department, as well as regulatory
2 commissions in Rhode Island and New Hampshire.
3
4 II. PURPOSE OF TESTIMONY
5 Q. What is the purpose of your testimony?
6 A. As a result of the proposed merger, several accounting related issues need to be
7 addressed for the consolidated entity such as consolidation of depreciation rates,
8 storm contingency funds, recovery of hazardous waste expenditures and the
9 amortization of other items such as unfunded deferred taxes and deferred FAS 106
10 costs. My testimony describes the Company's proposals with regard to each of
11 these issues.
12
13 III. DEPRECIATION RATES
14 Q. What depreciation rates does the Company propose using for the combined
15 entity?
16 A. As described in the testimony of Ms. Zschokke, Mass. Electric will be the
17 surviving corporation, therefore the Company proposes to apply the depreciation
18 rates approved for Mass. Electric as part of the Electric Utility Industry
19 Restructuring Settlement Agreement ("Settlement Agreement") in Docket No.
20 D.P.U./D.T.E. 96-25, dated October 1, 1996. The depreciation rates approved in
21 the Settlement Agreement have been attached as Exhibit DMW-1.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 4
1 Q. What impact will applying Mass. Electric's settlement depreciation rates have on
2 the depreciation expense of the consolidated entity?
3 A. Since Eastern Edison's depreciation rates are slightly higher than Mass. Electric's
4 depreciation rates, applying Mass. Electric's depreciation rates to the combined
5 entity will decrease depreciation expense by approximately $700,000 per year.
6
7 Q. Please explain how the estimated decrease in depreciation expense was calculated.
8 A. As shown in Exhibit DMW-2, depreciation expense was calculated for both Mass.
9 Electric and Eastern Edison based upon their present rates and then based upon
10 Mass. Electric's present depreciation rates. In each case, these rates were applied
11 against depreciable distribution plant balances as of December 31, 1998.
12 This methodology resulted in a depreciation expense amount of approximately
13 $73.5 million, for the combined entity using the Mass. Electric depreciation rates,
14 compared to a consolidated depreciation expense of approximately $74.2 million
15 with each company applying their current depreciation rates.
16
17 IV. STORM CONTINGENCY FUND
18 Q. Please describe the how the storm contingency fund works.
19 A. A storm contingency fund is a reserve recorded on the Company's books to pay
20 for service restoration costs as a result of a major storm. A major storm is defined
21 as one where the incremental operations and maintenance costs of restoring
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 5
1 service exceeds a predetermined threshold amount for each utility. The fund is
2 only intended to reimburse each utility for operation and maintenance costs
3 associated with service restoration. The fund is not intended to reimburse the
4 utility for capital related costs. An annual contribution to the fund is embedded in
5 rates. Interest is also accumulated on the balance in the fund.
6
7 Q. Please describe Mass. Electric's storm fund.
8 A. As part of Mass. Electric's Settlement Agreement, the Department authorized
9 Mass. Electric to establish a storm contingency fund. Attached as Exhibit DMW-3
10 is the portion of the Settlement Agreement which establishes the parameters of the
11 storm contingency fund. As stated in Exhibit DMW-3, a major storm is defined
12 for Mass. Electric as one in which the incremental costs of service restoration
13 exceed $1.0 million. The storm fund was established when the Company
14 transferred $3.0 million to the storm fund from its Purchased Power Cost
15 Adjustment reconciliation account. Under the terms of the Settlement Agreement,
16 Mass. Electric was authorized to collect in rates $3.0 million annually for the
17 continued funding of the storm fund beginning on March 1, 1998, the date of
18 Retail Access. This level of funding shall continue until a modification is
19 approved by the Department. As of December 31, 1998, Mass. Electric had
20 accumulated a storm reserve balance of approximately $6.5 million.
21
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 6
1 Q. Please describe Eastern Edison's storm fund.
2 A. As part of Eastern Edison's Settlement Agreement in Docket No. D.P.U./D.T.E.
3 96-24, the Department authorized Eastern Edison to establish a storm contingency
4 fund. Attached as Exhibit DMW-4 is the portion of the settlement agreement
5 which establishes the parameters of the storm contingency fund. As stated in
6 Exhibit DMW-4, a major storm is defined for Eastern Edison as one in which the
7 incremental costs of service restoration exceed $250,000. On March 1, 1998, the
8 storm fund was established when Eastern Edison Company transferred $2.0
9 million to the storm fund from its Purchased Power Cost Adjustment
10 reconciliation account. Under the terms of Eastern Edison's restructuring
11 agreement, it is authorized to collect in rates $1.3 million annually for the
12 continued funding of the storm fund beginning on March 1, 1998, the date of
13 Retail Access. This level of funding will continue until a modification is
14 approved by the Department. As of December 31, 1998, Eastern Edison had
15 accumulated a storm reserve balance of approximately $3.3 million.
16
17 Q. Please describe the Company's proposal with respect to treatment of the storm
18 contingency funds.
19 A. As shown in Exhibit DMW-5, the Company proposes to combine the current
20 storm contingency fund balances and funding levels of Mass. Electric and Eastern
21 Edison. This will result in an accumulated storm contingency fund balance of
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 7
1 approximately $9.8 million, as of December 31, 1998 and an annual funding
2 level of $4.3 million. The Company proposes to adopt Mass. Electric's threshold
3 amount of $1.0 million per storm occurrence for the combined entity since its
4 threshold amount is larger than Eastern Edison's.
5
6 Also attached as Exhibits DMW-6 is the storm contingency fund guidelines from
7 the Mass. Electric's Settlement Agreement marked to show changes for the
8 combined company under the proposal described above. Exhibit DMW-7 is the
9 clean version of Exhibit DMW-6. The Company is requesting that the Department
10 approve Exhibit DMW-7.
11
12 V. ENVIRONMENTAL RESPONSE FUND
13 Q. Could you please describe the purpose of an environmental response fund?
14 A. Yes. The environmental response fund is a reserve recorded on the books of each
15 utility which is used to pay for the remediation of hazardous waste sites. For
16 Mass. Electric, the fund is primarily used for remediation of Mass. Electric's
17 manufactured gas facilities formerly owned by Mass. Electric or an affiliate of
18 Mass. Electric.
19
20 Q. Please describe Mass. Electric's environmental response fund.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 8
1 A. In M.D.P.U. 93-194, Mass. Electric was authorized to establish an environmental
2 response fund on its books for remediation of hazardous waste sites. Relevant
3 excerpts from the settlement approved in M.D.P.U. 93-194 establishing the
4 environmental response fund has been attached as Exhibit DMW-8.
5
6 The fund was initially created by a $30 million contribution from Mass. Electric's
7 shareholders. Mass. Electric was then authorized to collect $3.0 million annually
8 from customers for additional funding of the environmental response fund. This
9 contribution amount is adjusted annually, effective the first day of October each
10 year, by the change in the Gross Domestic Product Implicit Price Deflator over
11 the previous twelve months. Mass. Electric was also authorized to provide interest
12 on the accumulated balance in the fund using the same methodology as the
13 interest paid on customer deposits.
14
15 As of December 31, 1998, Mass. Electric had recorded on its books a net liability
16 for hazardous waste site remediation costs of approximately $47.1 million,
17 including accrued interest on the fund balance. The annual contribution level for
18 the year October 1, 1998 through September 30, 1999 is estimated to be
19 approximately $3.3 million.
20
21 Q. Does Eastern Edison currently have a hazardous waste fund?
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 9
1 A. No. It does not.
2
3 Q. What accounting treatment does Eastern Edison apply to hazardous waste costs?
4 A. Prior to 1995, Eastern Edison had a minimal amount of costs associated with
5 hazardous waste site remediation (less than $50,000 annually). However, during
6 the period January 1, 1995 through December 31, 1997, Eastern Edison incurred
7 approximately $1.1 million of hazardous waste clean-up costs at two sites. Eastern
8 Edison, for book purposes, deferred the clean-up costs for these sites and is
9 currently amortizing them over five years. As of December 31, 1998, Eastern
10 Edison had approximately $205,000 remaining of unamortized hazardous waste
11 site remediation costs. The amortization of these costs will be completed by the
12 end of the year 2000.
13
14 Q. What is the company's proposal with regard to the environmental response fund?
15 A. Mass. Electric proposes to charge Eastern Edison's environmental liabilities to the
16 hazardous waste fund upon completion of the merger to the same extent that
17 Mass. Electric's waste costs would be chargeable to the fund.
18
19 VI. OTHER AMORTIZATIONS AND ACCOUNTING ADJUSTMENTS
20 Q. Please explain the other amortization and accounting adjustments under the
21 Company's proposed rate plan.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D.M. Webster
Page 10
1 A. Currently Mass. Electric and Eastern Edison have certain deferrals that are
2 currently being recovered in rates. These amortizations include recovery of
3 unfunded deferred taxes and deferred FAS 106 costs as well as other regulatory
4 assets. The amortization of these items will be completed at various times during
5 the period of the rate plan.
6
7 Q. What is the Company's proposal with regards to these amortizations?
8 A. The Company proposes to consolidate the remaining deferral balances of each
9 item upon completion of the merger and continue the amortization until the
10 recovery of each item is complete. At that point the savings from the reduced
11 amortization offset the expected increase in other costs that will have occurred
12 during the rate freeze period.
13
14 Mass. Electric's current rates are based upon a test year ending March 31, 1996
15 and a projected rate year ended December 31, 1998. These rates do not include an
16 allowance for increases in costs through the end of the rate plan proposed by
17 the Company in this case.
18
19 VIII. CONCLUSION
20 Q. Does this conclude your testimony?
21 A. Yes, it does.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
EXHIBITS
OF
DAVID M. WEBSTER
Exhibit DMW-1 Summary of Depreciation Rates
Exhibit DMW-2 Incremental Impact of Depreciation Rate Changes
Exhibit DMW-3 Establishment of Mass. Electric Storm Contingency Fund
Exhibit DMW-4 Establishment of Eastern Edison Storm Contingency Fimd
Exhibit DMW-5 Summary of Storm Contingency Fund Balances
Exhibit DMW-6 Consolidated Storm Contingency Fund (Marked to Show Changes)
Exhibit DMW-7 Consolidation of Storm Contingency Funds (Clean Version)
Exhibit DMW-8 Mass. Electric Environmental Response Fund
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-1
Exhibit DMW-1
Summary of Depreciation Rates
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-1
Page 1 of 1
MASSACHUSETTS ELECTRIC COMPANY
AG Settlement
Attachment 5
MASSACHUSETTS ELECTRIC COMPANY
Cost of Service Supporting Schedule
Summary of Depreciation Study Rates
(000)
<TABLE>
<CAPTION>
Net
Depreciation Salvage Combined
Acct Accrual Accrual Accrual
No. Account Title Rate Rate Rate
1
<S> <C> <C> <C> <C>
2 353 Station Equipment 1.79% -0.04% 1.75%
3 355 Poles and Fixtures 2.03% -0.04% 1.99%
4 356 Overhead Conductors & Devices 1.86% -0.04% 1.82%
5 357 Underground Conduit 0.76% -0.04% 0.72%
6 358 Underground Conductors & Devices 1.15% -0.04% 1.11%
7 359 Roads and Trails 1.52% -0.04% 1.48%
8
9
10 361 Structures and Improvements 2.09% 0.74% 2.83%
11 362 Station Equipment 2.10% 0.74% 2.84%
12
13
14
15 364 Poles, Towers and Fixtures 3.32% 0.74% 4.06%
16 365 Overhead Conductors and Devices 3.16% 0.74% 3.90%
17 366 Underground Conduit 2.17% 0.74% 2.91%
18 367 Underground Conductors & Devices 2.37% 0.74% 3.11%
19 368 Line Transformers 3.71% 0.74% 4.45%
20 369 Services 3.22% 0.74% 3.96%
21 370 Meters 3.68% 0.74% 4.42%
22 372 Leased Property on Cust. Premises 7.81% 0.74% 8.55%
23
24 373 Street Lighting & Signal Systems 7.39% 0.74% 8.13%
25
26
27
28 390 Structures and Improvements 2.72% 0.20% 2.92%
29 391 Office Furniture and Equipment 6.67%1/
30 393 Stores Equipment 6.67%1/
31 394 Tools, Shop & Garage Equipment 6.67%1/
32 395 Laboratory Equipment 6.67%1/
33 397 Communications Equipment 6.67%1/
34 398 Miscellaneous Equipment 6.67%1/
35
36 1\ The depreciation study recommends the use of 15 year amortization
37 for all categories of general plant with the exception of A/C# 390.
38
39
40
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-2
Exhibit DMW-2
Incremental Impact of Depreciation Rate Changes
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-2
Page 1 of 4
Massachusetts Electric Company
Incremental Impact of Depreciation Rate Changes
1 Applying Mass. Electric Applying Each Company's Incremental
2 Depreciation Rates for Depreciation Rates for Increase/
3 Function Combined Entity Combined Entity (Decrease)
4 -------- ----------------------- ----------------------- -----------
<S> <C> <C> <C> <C>
5 Distribution Plant $70,277,862 1/ $70,993,351 2/ ($715,489)
6
7 Transmission Plant $277,893 3/ $347,340 4/ ($69,447)
8
9 General Plant $2,914,920 5/ $2,812,827 6/ $102,093
10
11 Total $73,470,675 $74,153,518 ($682,843)
=========== =========== =========
Notes:
1/ Exhibit DMW-2, Page 2, Column (b), Line 49.
2/ Exhibit DMW-2, Page 2, Column (b), Line 51.
3/ Exhibit DMW-2, Page 3, Column (b), Line 45.
4/ Exhibit DMW-2, Page 3, Column (b), Line 47.
5/ Exhibit DMW-2, Page 4, Column (b), Line 48.
6/ Exhibit DMW-2, Page 4, Column (b), Line 50.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-2
Page 2 of 4
Massachusetts Electric Company
Incremental Impact of Depreciation Rate Changes
1 Massachusetts Eastern
2 PUC Electric Edison
3 Distribution Account Deprec. Rates Deprec. Rates
------------ ------- ------------- -------------
<S> <C> <C> <C>
4 361 2.83% 1.98%
5 362 2.84% 2.59%
6 364 4.06% 5.24%
7 365 3.90% 4.41%
8 366 2.91% 1.72%
9 367 3.11% 3.49%
10 368 4.45% 4.65%
11 369 3.96% 4.40%
12 370 4.42% 3.57%
13 373 8.13% 8.78%
14
15 Mass. Electric Eastern Edison
16 12/31/98 Plant Depreciation Depreciation
17 Depreciable Plant Balance Rates Rates
18 Mass. Electric 1/ Column (a) Column (b) Column (c)
----------------- ---------- -------------- --------------
<S> <C> <C> <C> <C>
19 361 $8,608,358 $243,617 $170,445
20 362 $170,058,118 $4,829,651 $4,404,505
21 364 $263,442,408 $10,695,762 $13,804,382
22 365 $376,534,102 $14,684,830 $16,605,154
23 366 $94,725,017 $2,756,498 $1,629,270
24 367 $173,368,214 $5,391,751 $6,050,551
25 368 $215,285,252 $9,580,194 $10,010,764
26 369 $88,514,512 $3,505,175 $3,894,639
27 370 $73,188,383 $3,234,927 $2,612,825
28 373 $82,381,918 $6,697,650 $7,233,132
29 ---------- ----------
30 Total $61,620,055 $66,415,667
31 ----------- -----------
32 Mass. Electric Eastern Edison
33 12/31/98 Plant Depreciation Depreciation
34 Depreciable Plant Balance Rates Rates
35 Eastern Edison 2/ Column (a) Column (b) Column (c)
----------------- ---------- -------------- --------------
<S> <C> <C> <C> <C>
36 361 $1,438,026 $40,696 $28,473
37 362 $21,840,403 $620,267 $565,666
38 364 $41,288,534 $1,676,314 $2,163,519
39 365 $39,792,789 $1,551,919 $1,754,862
40 366 $9,943,321 $289,351 $171,025
41 367 $26,112,335 $812,094 $911,320
42 368 $36,185,965 $1,610,275 $1,682,647
43 369 $17,478,576 $692,152 $769,057
44 370 $12,225,902 $540,385 $436,465
45 373 $10,139,657 $824,354 $890,262
46 --------- ----------
47 Total $8,657,807 $9,373,296
48 ---------- ----------
49 Total Depreciation $70,277,862 $75,788,963
50
51 Baseline 3/ $70,993,351 $70,993,351
52 ----------- -----------
53 Variance ($715,489) $4,795,612
Notes:
1/ Mass. Electric's 1998 FERC Form 1, Page 207, Column (g), lines 56 through 68.
2/ Eastern Edison's 1998 FERC Form 1, Page 207, Column (g), lines 56 through 68.
3/ Line 30 Column (b) plus Line 47 Column (c)
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-2
Page 3 of 4
Massachusetts Electric Company
Incremental Impact of Depreciation Rate Changes
1 Massachusetts Eastern
2 PUC Electric Edison
3 Transmission Account Deprec. Rates Deprec. Rates
------------ ------- ------------- -------------
4<S> <C> <C> <C>
5 352 1.90% 1.85%
6 353 1.75% 2.69%
7 354 3.32% 2.75%
8 355 1.99% 2.79%
9 356 1.82% 2.67%
10 357 0.72% 0.00%
11 358 1.11% 0.00%
12 359 1.48% 1.27%
13
14 Mass. Electric Eastern Edison
15 12/31/98 Plant Depreciation Depreciation
16 Depreciable Plant Balance Rates Rates
17 Mass. Electric 1/ Column (a) Column (b) Column (c)
----------------- ---------- ------------- --------------
18<S> <C> <C> <C> <C>
19 352 $0 $0 $0
20 353 488,282 8,545 13,135
21 354 0 0 0
22 355 2,958,000 58,864 82,528
23 356 1,956,204 35,603 52,231
24 357 84,935 $612 0
25 358 250,648 2,782 0
26 359 67,155 $994 853
27 --- ---
28 Total $107,400 $148,747
29 ------- -------
30
31 Mass. Electric Eastern Edison
32 12/31/98 Plant Depreciation Depreciation
33 Depreciable Plant Balance Rates Rates
34 Eastern Edison 2/ Column (a) Column (b) Column (c)
----------------- ---------- ------------- --------------
35<S> <C> <C> <C> <C>
36 352 $196,761 $3,738 $3,640
37 353 2,394,252 41,899 64,405
38 354 273,231 9,071 7,514
39 355 3,530,308 70,253 98,496
40 356 2,419,470 44,034 64,600
41 357 0 0 0
42 358 0 0 0
43 359 101,185 1,498 1,285
44 ------ ------
45 Total $170,493 $239,940
-------- --------
46 Total Depreciation $277,893 $388,687
47
48 Baseline 3/ $347,340 $347,340
-------- --------
49 Variance ($69,447) $41,347
Notes:
- -----
1/ Mass. Electric's 1998 FERC Form 1, Page 207, Column (g), lines 45 through 52.
2/ Eastern Edison's 1998 FERC Form 1, Page 207, Column (g), lines 45 through 52.
3/ Line 26 Column (b) plus Line 42 Column (c).
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-2
Page 4 of 4
Massachusetts Electric Company
Incremental Impact of Depreciation Rate Changes
1 Massachusetts Eastern
2 PUC Electric Edison
3 General Account Deprec. Rates Deprec. Rates
------- ------- ------------- -------------
<S> <C> <C> <C>
4 390 2.92% 2.66%
5 391 6.67% 4.26%
6 392 0.00% 3.13%
7 393 6.67% 4.22%
8 394 6.67% 3.00%
9 395 6.67% 2.63%
10 396 0.00% 3.13%
11 397 6.67% 5.10%
12 398 6.67% 8.41%
13
14 Mass. Electric Eastern Edison
15 12/31/98 Plant Depreciation Depreciation
16 Depreciable Plant Balance Rates Rates
17 Mass. Electric 1/ Column (a) Column (b) Column (c)
----------------- ---------- ------------- -------------
<S> <C> <C> <C> <C>
18 390 $40,245,879 $1,175,180 $1,070,540
19 391 1,378,544 91,949 58,726
20 392 1,519,116 101,325 64,107
21 393 0 0 0
22 394 8,308,271 554,162 249,248
23 395 2,735,716 182,472 71,949
24 396 0 0 0
25 397 4,057,655 270,646 206,940
26 398 584,668 38,997 49,171
27 ------- -------
28 Total 2,414,731 1,770,681
29 ---------- ----------
30
31 Mass. Electric Eastern Edison
32 12/31/98 Plant Depreciation Depreciation
33 Depreciable Plant Balance Rates Rates
34 Eastern Edison 2/ Column (a) Column (b) Column (c)
----------------- ---------- ------------- -------------
35 390 $9,125,340 266,460 $242,734
36 391 824,842 55,017 35,138
37 392 11,068 0 346
38 393 139,283 9,290 5,878
39 394 775,835 51,748 23,275
40 395 512,204 34,164 13,471
41 396 11,271 0 353
42 397 857,830 57,217 43,749
43 398 394,201 26,293 33,152
44 ------- -------
45 Total $500,189 $398,096
46 -------- --------
47
48 Total Depreciation $2,914,920 $2,168,777
49
50 Baseline 3/ $2,812,827 $2,812,827
51 ---------- ----------
52 Variance $102,093 ($644,050)
Notes:
1/ Mass. Electric's 1998 FERC Form 1, Page 207, Column (g), lines 72 through 81.
2/ Eastern Edison's 1998 FERC Form 1, Page 207, Column (g), lines 72 through 81.
3/ Line 28 Column (b) plus Line 45 Column (c).
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-3
Exhibit DMW-3
Establishment of Mass. Electric Storm Contingency Fund
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-3
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
ELECTRIC INDUSTRY RESTRUCTURING--OFFER OF SETTLEMENT
ESTABLISHMENT OF STORM CONTINGENCY FUND--POLICIES AND PROCEDURES
Massachusetts Electric Company (Mass. Electric or the Company) shall
establish a storm contingency fund to pay for the incremental costs incurred
by the Company as a result of major storms. Major storms shall be defined as
those storms with incremental costs of over $1.0 million occurring after the
date the settlement proposal is approved by the Department of Public
Utilities. The fund shall be established and maintained as follows:
1. Mass. Electric will pre-fund the storm contingency fund effective August
1, 1996 through a $3 million transfer from the Purchased Power Cost
Adjustment reconciliation account. Interest will accrue immediately on the
balance of the fund and will be accounted for as described in item 3 below.
Beginning on the date the Retail Access Rates in Attachment 2 become
effective and through the duration of the effective period of the Retail
Access Rates included in Attachment 2 to this settlement proposal, Mass.
Electric shall collect $3 million annually through base rates. The
accounting entry to record monthly contributions to the fund will be the
following, provided that the fund is in a positive position:
DR Account 924 Property insurance-storm contingency
CR Account 254 Storm contingency reserve
The storm fund will be in a positive position when the cumulative amount
collected through rates exceeds amounts disbursed from the fund to pay for
major storm costs.
2. Upon the occurrence of a major storm, all incremental costs incurred as a
result of the storm shall be offset against the balance in Account 254. If
the incremental costs of major storms exceeds the balance in Account 254,
such excess (i.e., a negative fund balance) shall be debited to Account 182,
Deferred charges-storm fund. As long as the fund balance remains negative,
the monthly entry to record the collection of storm fund proceeds will be:
DR Account 924 Property insurance-storm contingency
CR Account 182 Deferred charges-storm fund
Incremental costs are defined as the costs which Mass. Electric will incur
as a direct result of a storm which are over and above Mass. Electric's
normal costs of doing business.
These costs shall include such things as overtime paid to employees to
restore service to customers, rest time wages incurred as a result of storm
restoration (as stipulated in union contracts), outside vendor costs,
lodging and meal charges, material and supply charges, and other. The storm
fund is not intended to reimburse Mass. Electric for incremental capital
costs.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-3
Page 2 of 2
3. Interest shall be accrued on any positive or negative balance in the
fund, calculated in accordance with the Terms and Conditions for interest
expense calculated on customer deposits. If the fund is in a positive
position, the entry on Mass. Electric's books will be:
DR Account 431 Interest expense
CR Account 254 Storm contingency reserve
If the fund is in a negative position, the entry on Mass. Electric's books
will be:
DR Account 182 Deferred charges-storm fund
CR Account 419 Interest income
4. After the occurrence of a major storm, Mass. Electric will account for
all amounts charged to the fund, and provide such accounting to the
Department of Public Utilities and the Attorney General.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-4
Exhibit DMW-4
Establishment of Eastern Edison Storm Contingency Fund
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-4
Page 1 of 3
Eastern Edison Company
Establishment of Storm Contingency Fund
and
Policies and Procedures
Eastern Edison Company (Eastern Edison or the Company) shall establish
a storm contingency fund to pay for the incremental costs incurred by the
Company as a result of major storms. A major storm shall be defined as a
storm with incremental costs exceeding $250,000. Effective January 1, 1998,
retail rates will be deemed to provide for a $1.3M accrual annually.
Eastern will report to the M.D.P.U. anytime it is drawing funds from this
account to cover incremental costs greater than $250,000. Interest on the
account balance (positive or negative) will be accrued monthly at Eastern
Edison's short term borrowing rate.
Incremental costs are defined as the costs which Eastern will incur as
a direct result of a storm which are over and above Eastern Edison's normal
costs of doing business. These costs shall include such items as overtime
paid to employees to restore service to customers, rest time wages incurred
as a result of storm restoration (as stipulated in union contracts or
company policies), outside vendor costs, lodging and meal charges, material
and supply charges, and other. The storm fund is not intended to reimburse
Eastern for incremental capital costs.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-4
Page 2 of 3
The fund shall be established and maintained as follows:
1. Eastern will pre-fund the storm contingency fund through a $2 million
transfer from the reserve established from Montaup's 1996 PCAC refund.
Interest will accrue immediately on the balance of the fund and will be
accounted for as described in item 3 below. Beginning on the date the
Retail Access Rates become effective, Eastern Edison's base rates shall be
deemed to collect $1.3 million annually to be contributed to the storm
contingency fund and continuing until these rates are superseded by new
rates resulting from a base rate revenue requirement rate proceeding. The
accounting entry to record monthly contributions to the fund will be the
following, provided that the fund is in a positive position:
DR Account 924 Property insurance-storm contingency
CR Account 254 Storm contingency reserve
The storm fund will be in a positive position when the cumulative
amount collected through rates exceeds amounts disbursed from the fund to
pay for major storm costs.
2. Upon the occurrence of a major storm, all incremental costs incurred as a
result of the storm shall be offset against the balance in Account 254. If
the incremental costs of major storms exceeds the balance in Account 254,
such excess (i.e., a negative fund balance) shall be debited to Account 182,
Deferred charges-storm fund. As long as the fund balance remains negative,
the monthly entry to record the collection of storm fund proceeds will be:
DR Account 924 Property insurance-storm contingency
CR Account 182 Deferred charges-storm fund
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ____
Exhibit DMW-4
Page 3 of 3
3. Interest shall be accrued on any positive or negative balance in the
fund, calculated in accordance with the Terms and Conditions for interest
expense calculated on customer deposits. If the fund is in a positive
position, the entry on Eastern Edison's books will be:
DR Account 431 Interest expense
CR Account 254 Storm contingency reserve
If the fund is in a negative position, the entry on Eastern Edison's books
will be:
DR Account 182 Deferred charges-storm fund
CR Account 419 Interest income
4. After the occurrence of a major storm, Eastern Edison will account for
all amounts charged to the fund, and provide such accounting to the
Department of Public Utilities and the Attorney General.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-5
Exhibit DMW-5
Summary of Storm Contingency Fund Balances
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-5
Page 1 of 1
<TABLE>
<CAPTION>
Massachusetts Electric Company
Summary of Storm Contingency Fund Balances
Massachusetts Eastern Combined
Electric Edison Entity
<S> <C> <C> <C>
1. Balance in Storm Fund as of
2. December 31, 1998 $6,446,735 1/ $3,346,004 2/ $9,792,739
3.
4. Annual Storm Fund Contributions
5. Collected through Revenue $3,000,000 3/ $1,300,000 4/ $4,300,000
6.
7. Deductible Amount per each
8. Storm Occurrence $1,000,000 $250,000 $1,000,000
</TABLE>
Notes:
1/ Mass. Electric's 1998 FERC Form 1, page 232.
2/ Eastern Edison's 1998 FERC Form 1, page 232.
3/ Annual Deferral Recovery per Settlement Agreement in M.D.P.U. Nos. 96-100
and 96-25.
4/ Annual Deferral Recovery per Settlement Agreement in M.D.P.U. Nos. 96-100
and 96-24.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-6
Exhibit DMW-6
Consolidated Storm Contingency Fund (Marked to Show Changes)
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. _____
Exhibit DMW-6
Page 1 of 2
Massachusetts Electric Company
NEES/EUA Merger Proceeding
Consolidation of Storm Contingency Funds--Polices and Procedures
Massachusetts Electric Company (Mass. Electric or the Company) shall [maintain]
[[establish]] a storm contingency fund to pay for the incremental costs incurred
by the Company as a result of major storms. Major storms shall be defined as
those storms with incremental costs of over $1.0 million [[occurring after the
date the settlement proposal is approved by the Department of Public
Utilities]]. The fund shall be established and maintained as follows:
1. Mass. Electric will [consolidate the existing storm contingency fund balances
of Mass. Electric and Eastern Edison upon the completion of the merger]
[[prefund the storm contingency fund effective August 1, 1996 through a $3
million transfer from the Purchased Power Cost Adjustment reconciliation
account]]. Interest will accrue immediately on the balance of the fund and will
be accounted for as described in item 3 below. Beginning on the [Rate
Consolidation date, planned for January 1, 2001,] [[the Retail Access Rates in
Attachment 2 become effective and through the duration of the effective period
of the Retail Access Rates included in attachment 2 to this settlement
proposal,]] Mass. Electric shall collect $[4.3] [[3]] million annually through
base rates. The accounting entry to record monthly contributions to the fund
will be the following, provided that the fund is in a positive position:
DR Account 924 Property insurance-storm contingency
CR Account 254 Storm contingency reserve
The storm fund will be in a positive position when the cumulative amount
collected through rates exceeds amounts disbursed from the fund to pay for major
storm costs.
2. Upon the occurrence of a major storm, all incremental costs incurred as a
result of the storm shall be offset against the balance in Account 254. If the
incremental costs of major storms exceeds the balance in Account 254, such
excess (i.e. a negative fund balance) shall be debited to Account 182, Deferred
charges-storm fund. As long as the fund balance remains negative, the monthly
entry to record the collection of storm fund proceeds will be:
Legend: [ ] = insertion
[[ ]] = deletion
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No.
Exhibit DMW-6
Page 1 of 2
DR Account 924 Property insurance-storm contingency
CR Account 182 Deferred charges-storm fund
Incremental costs are defined as the costs which Mass. Electric will incur as a
direct result of a storm which are over and above Mass. Electric's normal costs
of doing business. These costs shall include such things as overtime paid to
employees to restore service to customers, rest time wages incurred as a result
of storm restoration (as stipulated in union contracts), outside vendor costs,
lodging and meal charges, material and supply charges, and other. The storm fund
is not intended to reimburse Mass. Electric for incremental capital costs.
3. Interest shall be accrued on any positive or negative balance in the fund,
calculated in accordance with the Terms and Conditions for interest expense
calculated on customer deposits. If the fund is in a positive position, the
entry on Mass. Electric's books will be:
DR Account 431 Interest expense
CR Account 254 Storm contingency reserve
If the fund is in a negative position, the entry on Mass. Electric's books will
be:
DR Account 182 Deferred charges-storm fund
CR Account 419 Interest income
4. After the occurrence of a major storm, Mass. Electric will account for all
amounts charged to the fund, and provide such accounting to the Department of
Public Utilities and the Attorney General.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-7
Exhibit DMW-7
Consolidation of Storm Contingency Funds (Clean Version)
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. _____
Exhibit DMW-7
Page 1 of 2
Massachusetts Electric Company
NEES/EUA Merger Proceeding
Consolidation of Storm Contingency Funds--Polices and Procedures
Massachusetts Electric Company (Mass. Electric or the Company) shall maintain a
storm contingency fund to pay for the incremental costs incurred by the Company
as a result of major storms. Major storms shall be defined as those storms with
incremental costs of over $1.0 million. The fund shall be established and
maintained as follows:
1. Mass. Electric will consolidate the existing storm contingency fund balances
of Mass. Electric and Eastern Edison upon the completion of the merger. Interest
will accrue immediately on the balance of the fund and will be accounted for as
described in item 3 below. Beginning on the Rate Consolidation date, planned for
January 1, 2001, Mass. Electric shall collect $4.3 million annually through base
rates. The accounting entry to record monthly contributions to the fund will be
the following, provided that the fund is in a positive position:
DR Account 924 Property insurance-storm contingency
CR Account 254 Storm contingency reserve
The storm fund will be in a positive position when the cumulative amount
collected through rates exceeds amounts disbursed from the fund to pay for major
storm costs.
2. Upon the occurrence of a major storm, all incremental costs incurred as a
result of the storm shall be offset against the balance in Account 254. If the
incremental costs of major storms exceeds the balance in Account 254, such
excess (i.e. a negative fund balance) shall be debited to Account 182, Deferred
charges-storm fund. As long as the fund balance remains negative, the monthly
entry to record the collection of storm fund proceeds will be:
DR Account 924 Property insurance-storm contingency
CR Account 182 Deferred charges-storm fund
Incremental costs are defined as the costs which Mass. Electric will incur as a
direct result of a storm which are over and above Mass. Electric's normal costs
of doing business. These costs shall include such things as overtime paid to
employees to restore service to customers, rest time wages incurred as a result
of storm restoration (as stipulated in union contracts), outside vendor costs,
lodging and meal charges, material and supply charges, and other. The storm fund
is not intended to reimburse Mass. Electric for incremental capital costs.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. _____
Exhibit DMW-7
Page 2 of 2
3. Interest shall be accrued on any positive or negative balance in the fund,
calculated in accordance with the Terms and Conditions for interest expense
calculated on customer deposits. If the fund is in a positive position, the
entry on Mass. Electric's books will be:
DR Account 431 Interest expense
CR Account 254 Storm contingency reserve
If the fund is in a negative position, the entry on Mass. Electric's books will
be:
DR Account 182 Deferred charges-storm fund
CR Account 419 Interest income
4. After the occurrence of a major storm, Mass. Electric will account for all
amounts charged to the fund, and provide such accounting to the Department of
Public Utilities and the Attorney General.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit DMW-8
Exhibit DMW-8
Mass. Electric Environmental Response Fund
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ___
Exhibit DMW-8
Page 1 of 6
B. Rate Treatment for Environmental Response Costs.
1. Mass. Electric shall establish on its books a fund for hazardous waste
clean up and liabilities. The fund will pay for Environmental Response
Costs paid after June 30, 1993. Environmental Response Costs are
defined as:
(a) Reasonable and prudently incurred costs or expenses associated
with the investigation, testing, remediation, or other
liabilities attributable to NEES and its current subsidiaries
relating to gas manufacturing facility sites, disposal sites,
sites to which material may have migrated, or any sites at which
manufactured gas waste may have been deposited as a result of the
earlier operation or decommissioning of gas manufacturing
facilities located in Massachusetts;
(b) Reasonable and prudently incurred costs or expenses (excluding
all fines or penalties) associated with the investigation,
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ___
Exhibit DMW-8
Page 2 of 6
testing, remediation, or other liabilities attributable to Mass.
Electric relating to material regulated under the statutes in
subparagraph B.1.(d) unrelated to Massachusetts gas manufacturing
facilities deposited before 1980 on sites or migrating to sites
as a result of the operations of Mass. Electric or its
predecessor companies;
(c) Reasonable and prudently incurred costs or expenses associated
with the purchase of property that is acquired as part of an
overall mitigation and response plan associated with sites
identified in subparagraph B.1.(a) and B.1.(b); and
(d) Reasonable and prudently incurred payments for liabilities,
damages, claims, settlements, or judgments arising from
Subparagraphs B.1.(a) and B.1.(b) under the Comprehensive
Environmental Response, Compensation and Liability Act (CERCLA),
Resource Conservation and Recovery Act (RCRA), Massachusetts G.L.
c. 21C and 21E, and any other laws, regulations or orders by
courts or governmental authorities, or resulting from claims and
contentions arising in tort, breach of contract, or violation of
law.
Except for property acquired under Paragraph B.1.(c), Environmental
Response Costs shall not include costs or expenses associated with the
investigation, testing, remediation, or other liabilities relating to
property acquired after the Approval Date.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ___
Exhibit DMW-8
Page 3 of 6
2. The fund shall be financed by:
(a) A $30 million shareholder contribution will be credited to the
fund effective as of October 1, 1993;
(b) (i) Annual contributions by Mass. Electric of $3.0 million
commencing as of October 1, 1993, adjusted each October
1 for changes to the Gross Domestic Product Implicit
Price Deflator (GDPIPD) occurring after October 1,
1993. One-twelfth of the annual amount shall be
credited to the fund each month.
(ii) Interest free loans to the fund by Mass. Electric to
the extent that the balance in the fund is inadequate
to make the payments from the fund required under
Paragraph B.1.
(c) Proceeds from insurance companies related to Environmental
Response Costs, proceeds from the sale of properties purchased
under subparagraph B.1.(c), repayments of discounts as required
under Paragraph C.1.(c), and recoveries from third parties,
including natural gas companies; and
(d) Interest on the fund credited each October 1 and calculated using
the methodology for calculating interest on customer deposits
specified in Mass. Electric's terms and conditions.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ___
Exhibit DMW-8
Page 4 of 6
3. Rate recovery for Mass. Electric shall be as follows:
(a) Mass. Electric's contributions and loans to the fund under
Paragraph B.2.(b) shall be includable in Mass. Electric's cost of
service and recoverable in Mass. Electric's rates based on the
kilowatthour consumption in each rate class. This recovery shall
occur regardless of the prudence of the operations that have
given rise to the Environmental Response Costs, provided,
however, that nothing in this Offer of Settlement shall: (1)
prevent any party from contending in either a general rate filing
or a quarterly adjustment proceeding that the costs associated
with clean up activities were unreasonable or imprudent or (2)
relieve Mass. Electric of the obligation to demonstrate that its
actions and the costs incurred associated with any cleanup
activities were reasonable and prudent. To the extent that the
Department concludes that any costs incurred after the test year
in Mass. Electric's prior general rate case have not been
demonstrated to be reasonable and prudent, Mass. Electric shall
credit such amounts with interest back to the fund. Mass.
Electric's recovery of these costs shall be implemented in the
following manner:
(i) Mass. Electric's annual contribution as adjusted under
subparagraph B.2.(b)(i) shall be recovered in base rates.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ___
Exhibit DMW-8
Page 5 of 6
(ii) Any loans made by Mass. Electric under subparagraph
B.2.(b)(ii) shall be amortized without interest or carrying
charges over seven years and recovered net of the value of
the rate base deduction associated with any deferred tax
balances on the unamortized amounts through a separate
quarterly adjustment included with the adjustment calculated
under Mass. Electric's Standard Fuel Clause using the
formula included in Attachment 1 to this Offer of
Settlement. This recovery shall occur over the twelve months
commencing on April 1 of the year following the year in
which the loan was made.
This Paragraph B.3.(a) shall be the exclusive method for rate
recovery of the costs defined in Paragraph B.1.
(b) All reasonable and prudently incurred fees and costs associated
with law firms and consultants outside of Mass. Electric and its
affiliates to defend or prosecute claims or liabilities under
Paragraph B.1. shall be paid directly by Mass. Electric and shall
not be paid by the fund. To the extent that these fees and costs
are reasonable, prudent, and related to the Environmental
Response Costs defined in Paragraph B.1., they shall be
recoverable in Mass. Electric's base rates based on an historical
three year rolling average.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. ___
Exhibit DMW-8
Page 6 of 6
4. Every three years, the Parties to this Settlement shall reevaluate the
annual amount contributed to the fund under Paragraph B.2.(b)(i) for
its ability together with the loans under Paragraph B.2.(b)(ii) to
provide sufficient resources to satisfy future Environmental Response
Costs in a prudent and reasonable fashion; provided, however, that
under no circumstances shall the amounts contributed under Paragraph
B.2.(b)(i) be increased. At the completion of payment and rate
recovery for all Environmental Response Costs, any balance remaining
in the fund shall be returned to customers.
5. Mass. Electric shall file with the Department semi-annually the
information set forth in Attachment 2.
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- ----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- ----------------------------------
DIRECT TESTIMONY
OF
THERESA M. BURNS
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- ----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- ----------------------------------
DIRECT TESTIMONY
OF
THERESA M. BURNS
Table of Contents
Page
I. Introduction and Qualifications..................................... 1
II. Purpose of Testimony................................................ 2
III. Summary of Mass. Electric's Current Rates........................... 3
IV. Summary of Eastern Edison's Current Rates........................... 5
V. Proposed Rate Plan.................................................. 7
General.................................................... 7
Distribution............................................... 12
Transmission............................................... 13
Transition................................................. 15
Results of Rate Plan on Retail Delivery Revenue............ 16
VI. Typical Bills....................................................... 18
VII. Tariffs and Terms and Conditions.................................... 25
VIII. Conclusion.......................................................... 27
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 1 of 27
<S> <C>
1 I. Introduction and Qualifications
2 Q. Please state your full name and business address.
3 A. Theresa M. Burns, 25 Research Drive, Westborough, Massachusetts 01582.
4
5 Q. Please state your position.
6 A. I am a Principal Rate Analyst for New England Power Service Company ("NEPSCO"),
7 performing rate related services for companies in the New England Electric System,
8 including Massachusetts Electric Company ("Mass. Electric" or "the Company").
9
10 Q. Please describe your educational background and training.
11 A. I graduated from Babson College in Wellesley, Massachusetts with a Bachelor of Science
12 degree in Accounting in 1986. In 1994, I received a Masters in Business Administration
13 from Babson College. I am a certified public accountant and a member of the
14 Massachusetts Society of Certified Public Accountants.
15
16 Q. Please describe your professional experience.
17 A. From 1986 to 1990, I was an auditor for Ernst & Young in Boston, Massachusetts. In
18 June 1990, I joined NEPSCO as an Accounting Analyst in the Financial Analysis Group
19 of the General Accounting Department. In June 1991, I was given responsibility over
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 2 of 27
1 general ledger accounting for NEPSCO's three retail affiliates. In July 1993, I joined the
2 Internal Audit Department and was responsible for performing both financial and
3 operational audits. In June 1994, I was promoted to Senior Internal Auditor. In July
4 1995, I transferred to the Rate Department as a Senior Rate Analyst. In this position, I
5 have been responsible for the design and implementation of retail access rates. In April
6 1999, I was promoted to Principal Rate Analyst, with responsibility over Mass. Electric's
7 and Granite State Electric Company's retail rate design and implementation.
8
9 Q. Have you previously testified before the Department of Telecommunications and Energy
10 ("the Department")?
11 A. Yes I have. I have submitted pre-filed testimony and testified for Nantucket Electric
12 Company's Cable Facilities Surcharge. I have also testified in Massachusetts Electric
13 Company's Docket Nos. 98-69 and 98-76, Proposals for Alternative Street lighting
14 Service and Purchase Price Methodology for the sale of streetlights pursuant to Section 196 of the
15 Restructuring Act.
16
17 II. Purpose of Testimony
18 Q. What is the purpose of your testimony?
19 A. My testimony presents the Company's proposed rate plan with Eastern Edison Company
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 3 of 27
1 ("Eastern"), upon the Company's merger with Eastern following completion of the
2 acquisition of Eastern Utilities Associates ("EUA") by New England Electric System
3 ("NEES"), as described in the testimony of Mr. Jesanis. I will first provide a brief
4 summary of both Mass. Electric's and Eastern's current rates on a total company basis as
5 approved by the Department. Second, I will describe the proposed rate plan which will
6 serve as a means of consolidating the rates of Mass. Electric and Eastern onto one set of
7 retail delivery service tariffs. Third, I will present the anticipated effects of the proposed
8 rate plan on revenue, both at the component level (i.e., distribution, transmission and
9 transition individually) and at the retail delivery service level (i.e., distribution,
10 transmission and transition collectively). Finally, I will discuss the application of tariffs,
11 provisions, and terms and conditions to the combined company.
12
13 III. Summary of Mass. Electric's Current Rates
14 Q. Please provide a brief summary of Mass. Electric's current rates.
15 A. Exhibit TMB-1 illustrates Mass. Electric's total average rates for various time periods,
16 both historic and projected. The rates consist of several specific components: distribution
17 charges, transmission charges, transition charges, and DSM and renewables charges
18 (together "delivery rates"). In addition, customers have the option to take standard
19 service or to purchase electricity from the competitive market. In accordance with the
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 4 of 27
1 Company's Settlement Agreement in Docket No. 96-25 ("Settlement"), distribution rates
2 were approved by the Department to collect, on average 2.502(cent) per kilowatt-hour. The
3 distribution component of the delivery rate is to be maintained at its current levels
4 through calendar year 2000. The Company is allowed to file a general rate case to adjust
5 distribution rates for dates on or after January 1, 2001. Demand side management and
6 renewables charges are in accordance with the Electric Utility Restructuring Act of 1997
7 ("the Act").
8
9 The Company's current average transmission rate of 0.641(cent) per kilowatt-hour as
10 approved by the Department collects both the current projection of transmission costs for
11 calendar year 1999 of 0.535(cent) per kilowatt-hour plus the recovery of an under collection
12 of transmission costs for the reconciliation period March 1, 1998 through September 30,
13 1998 of 0.106(cent) per kilowatt-hour. Mass. Electric's transmission rate recovers on a fully
14 reconciling basis the costs it incurs to provide transmission service to its customers. The
15 Company currently incurs transmission costs from New England Power Company
16 ("NEP"), as allocated to it by its load ratio share of NEP's total transmission costs, New
17 England Power Pool ("NEPOOL") and the Independent System Operator of New
18 England ("ISO"). The Company's transmission rate to its retail customers is a uniform
19 cents per kilowatt-hour charge unique to each rate class based upon an allocation of
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 5 of 27
1 transmission costs billed to it by NEP, NEPOOL and the ISO to each rate class. This
2 allocation is based on each rate class' demand at the time of NEP's peak, which is
3 analogous to the method with which NEP bills Mass. Electric.
4
5 The Company's current average transition charge of 1.328(cent) per kilowatt-hour as
6 approved by the Department reflects the contract termination charge being billed to it by
7 NEP of 1.339(cent) per kilowatt-hour, reduced by the refund of an over collection of transition
8 charge revenue for the reconciliation period March 1, 1998 through September 30, 1998
9 of 0.011(cent) per kilowatt-hour. Mass. Electric's transition charge recovers on a fully
10 reconciling basis the contract termination charge billed to it by NEP, and is a uniform
11 cents per kilowatt-hour charge for all rate classes other than the Company's Rate R-4,
12 Residential Time-of-Use (Optional), which maintains and on peak and off peak price
13 differential to ensure the rate reductions required under the Act.
14
15 IV. Summary of Eastern's Current Rates
16 Q. Please provide a brief summary of Eastern's current rates.
17 A. Exhibit TMB-2 illustrates Eastern's total average rates for various time periods, both
18 historic and projected. In accordance with Eastern's Settlement Agreement in Docket
19 No. 96-24, the distribution component of the delivery rate was approved by the
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 6 of 27
1 Department to collect, on average 2.743(cent) per kilowatt-hour. Similar to Mass. Electric's
2 Settlement, distribution rates are to be maintained at their current levels through calendar
3 year 2000. Eastern is also entitled to file a general rate case to adjust distribution rates, to
4 take effect on or after January 1, 2001. As with Mass. Electric, demand side management
5 and renewables charges are in accordance with the Act.
6
7 Eastern's current average transmission rate for calendar year 1999 is 0.298(cent) per kilowatt-
8 hour. Eastern's transmission rate is essentially the transmission rate of Montaup Electric
9 Company ("Montaup"), and recovers actual transmission costs that Montaup, NEPOOL,
10 and the ISO incur to provide transmission service to retail customers based on an historic
11 test year. These costs are allocated to Eastern, Blackstone Valley Electric Company, and
12 Newport Electric Company customers on a monthly basis and are divided by the total
13 monthly kilowatt-hours of the affiliate companies to arrive at a retail transmission rate
14 that Eastern will bill its customers on behalf of Montaup. Montaup's transmission rate,
15 as billed by Eastern, is a uniform cents per kilowatt-hour charge to all retail customers of
16 Montaup's affiliated companies.
17
18 Eastern's current average transition rate of 2.100(cent) per kilowatt-hour reflects the contract
19 termination charge being billed to it by Montaup. Eastern's transition charge recovers on
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 7 of 27
1 a fully reconciling basis Montaup's contract termination charge billed to Eastern, and is
2 billed to customers at differing rate structures, depending upon a customer's rate class. A
3 designed transition charge is included in the Rate R-4 Residential Time-of-Use tariff, and
4 the majority of General Service tariffs, while all other rate classes are billed at a uniform
5 cents per kilowatt-hour level.
6
7 V. Proposed Rate Plan
8 General
9 Q. Please provide a general description of the Company's proposed rate plan.
10 A. The Company's proposal for consolidating the rates of Eastern and Mass. Electric is
11 discussed in the testimony of Mr. Jesanis. As he explains, the rate consolidation and
12 distribution rate freeze will produce a reduction of $23.1 million, or 14.2%, in Eastern's
13 delivery rate in calendar year 2001. Mr. Jesanis's savings amount is based on projected
14 kilowatt-hour deliveries in calendar year 2001. In contrast, my exhibits, based on actual
15 billing determinants in calendar year 1998, reflect a savings amount of only $19.6 million
16 (see Exhibit TMB-7). My analysis also does not reflect the benefits of the distribution
17 rate freeze. As Mr. Bonner explains, the use of actual 1998 billing determinants is
18 necessary for the mapping process and its impacts. The Company is proposing to
19 consolidate all rates of Mass. Electric and Eastern effective on the first day of the billing
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 8 of 27
1 month of January 2001 ("Consolidation Date"). As I present below, the proposed rate
2 consolidation slightly increases distribution and transmission charges to Eastern's
3 customers, but these increases are more than offset by a significant reduction in Eastern's
4 transition charge. Mass. Electric's delivery rate increases slightly over the level
5 anticipated without the merger as the result of the blended transition charge, but still
6 declines in calendar year 2001 below the level expected for calendar year 2000, before
7 the proposed rate consolidation.
8
9 The proposed rate consolidation process begins with an analysis of the availability
10 provisions in the tariffs of the two companies. The rate classes of Eastern under which
11 Eastern's customers are served immediately prior to consolidation are proposed to be
12 mapped over to Mass. Electric's rate classes, as illustrated in Exhibit TMB-3. This
13 proposed rate mapping is performed by referencing the availability provisions of
14 Eastern's retail delivery service tariffs and matching each tariff to a corresponding Mass.
15 Electric retail delivery service tariff. As a result of this review, several Eastern general
16 service rates map to more than one Mass. Electric general service rate. This occurs
17 because the availability provisions of Eastern's general service tariffs encompass a wider
18 range of customer usage levels than those of Mass. Electric's general service tariffs.
19 Accordingly, the billing determinants under Eastern's retail delivery service tariffs have
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 9 of 27
1 been accumulated to match the availability provisions of Mass. Electric's retail delivery
2 service tariffs. The testimony of Mr. Bonner supports in more detail the rate mapping
3 process and the billing determinants that the Company is using as part of its proposed rate
4 plan and its effect on revenue. Once all of Eastern's customers are placed on the
5 appropriate Mass. Electric rate, all customers will be charged the same rates for
6 distribution, transmission, and transition as well as standard service, default service,
7 demand side management, and renewables.
8
9 Q. How will Mass. Electric implement the consolidated rates for Eastern's customers?
10 A. Mass. Electric will implement the consolidated rates for Eastern's customers on a bills
11 rendered basis for meter readings on and after the Consolidation Date. Because of the
12 complexity of separate billing systems and rate structures, a shift from Eastern's rates to
13 Mass. Electric's consolidated rates must occur on a bills rendered basis. Proration of
14 usage among two entirely different billing systems and rate structures is extremely
15 difficult and introduces needless complexity for customers, who would receive two
16 separate bills for one billing period under a prorated approach. Thus, the change on a
17 bills rendered basis ensures the proper billing of all usage between the meter reading
18 immediately subsequent to the Consolidation Date and the meter reading immediately
19 prior to the Consolidation Date. Under the Company's proposal, bills issued to Eastern's
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 10 of 27
1 customers for the billing period following the Consolidation Date will be based on Mass.
2 Electric's consolidated rates.
3
4 Q. Is the Company evaluating the adequacy of customer's meters for billing Mass. Electric's
5 rates as part of the rate consolidation?
6 A. Yes. First, Eastern's peak hours period is significantly different than Mass. Electric's
7 peak hours period. This will affect both the quantity of on peak kilowatt-hours in a
8 billing period once Eastern's time-of-use customers are placed on Mass. Electric's time-
9 of-use rates as well as the billing demand for the large general service customers
10 (maximum kilowatt usage during the peak hours period). Meters for these customers will
11 require reprogramming or replacement. Mass. Electric's medium general service
12 customers are charged uniform energy charges and their billing demand is based on the
13 maximum kilowatts used in all hours. Thus, for Eastern's general service customers
14 transferring to Mass. Electric's medium general service rate, meter configurations will be
15 evaluated and reprogrammed or replaced as needed. Additionally, some of Eastern's
16 large general service customers are not currently served on a time-of-use rate, and will be
17 placed on Mass. Electric's large general service rate which includes time-of-use pricing.
18 Meters for these customers will be replaced. Mass. Electric also determines billing
19 demand based on a comparison of kilowatts to kilovolt amperes. Eastern does not have
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 11 of 27
1 this provision in its general service tariffs, therefore kilovolt ampere meters are not
2 installed at customer locations. As part of all of Eastern's general service customers
3 transferring to Mass. Electric's medium and large general service tariffs, kilovolt ampere
4 meters will be installed at these customer locations requiring such meters.
5
6 Q. Who will be evaluating and performing these meter activities?
7 A. Mass. Electric's Meter Operations and Engineering group and its counterpart at Eastern,
8 along with Customer Service, will be identifying customers affected by required meter
9 activity and implementing the necessary changes. Meters will be reprogrammed,
10 replaced, or installed as soon as possible after the merger is approved to ensure the proper
11 billing of Mass. Electric's distribution rates. If kilovolt ampere meters are not installed
12 by the first billing cycle after the Consolidation Date at a customer's location, the
13 customer will have its demand charge based on maximum kilowatts registered until a
14 kilovolt ampere meter can be installed.
15
16 Q. What impact will the meter changes have on the revenues following the proposed
17 consolidation?
18 A. Mass. Electric and Eastern have attempted to redefine the billing units used in this filing
19 for Mass. Electric's peak hours period. This is explained more fully in Mr. Bonner's
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 12 of 27
1 testimony. Therefore, on peak kilowatt-hours and billing demand are estimated under
2 Mass. Electric's rates. Mass. Electric has not attempted to determine the effect on
3 kilovolt ampere usage on billing demand. Therefore, the demand-based revenue
4 calculated in this filing may increase with the installation of kilovolt ampere meters,
5 providing that the maximum kilowatts is less than 90 percent of the maximum kilovolt
6 amperes. Consequently, Eastern's savings projected following the proposed rate
7 consolidation may drop slightly. Moreover, the billing determinants presented in this
8 filing are actual units from calendar year 1998, and amounts and values will change when
9 the rates are applied to actual usage in calendar year 2001.
10
11 Distribution
12 Q. What is the Company's plan for consolidating the distribution rates of both Mass. Electric
13 and Eastern?
14 A. The Company is proposing to transfer Eastern's customers from Eastern's distribution
15 rates to those of Mass. Electric. Mass. Electric's distribution rates have been frozen since
16 March 1, 1998. As part of this proposal, Mass. Electric will extend its current
17 distribution rate freeze that expires on December 31, 2000, for either two or four
18 additional years. Mr. Jesanis describes the conditions behind the term of the freeze.
19
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 13 of 27
1 Q. What is the estimated impact on Mass. Electric's distribution revenue generated from
2 Eastern's customers?
3 A. The movement of Eastern's customers to Mass. Electric's distribution rates is projected to
4 increase distribution revenues from Eastern's customers by approximately $2.6 million
5 over the distribution revenues under Eastern's current distribution rates. The revenue
6 comparison is shown on Exhibit TMB-4. This exhibit determines the annual normalized
7 distribution revenue of Eastern's customers, both on Eastern's current distribution rates
8 and Mass. Electric's current distribution rates. This analysis, along with many other total
9 company and total rate class analyses included in this filing, are based on calendar year
10 1998 billing determinants, and are explained in more detail in the testimony of Mr.
11 Bonner.
12
13 Transmission
14 Q. How will transmission costs be billed after the Consolidation Date?
15 A. After the Consolidation Date, Eastern's customers and Mass. Electric's customers will be
16 charged a consolidated transmission rate. If the NEP and Montaup transmission rates are
17 not fully consolidated, then the retail consolidated transmission rate will be based on the
18 sum of the projected Montaup transmission bill to Mass. Electric's retail delivery service
19 customers in the former Eastern service territory and the projected NEP bill to Mass.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 14 of 27
1 Electric's existing retail delivery service customers for transmission service along with
2 projected bills from NEPOOL and the ISO to arrive at a total transmission expense for
3 the combined company. Once the NEP and Montaup transmission rates are consolidated,
4 NEP will issue one transmission bill to Mass. Electric that will include transmission
5 service to the combined retail delivery service customer base, and Mass. Electric will
6 continue to be allocated transmission costs from NEPOOL and the ISO. The Company
7 will then allocate the total transmission expense of the combined company to Mass.
8 Electric's rate classes based on coincident peak demand, a methodology that has
9 previously been used by Mass. Electric and approved by the Department. This allocation
10 ensures that transmission costs are allocated to each rate class based on how they
11 contribute to those costs. After allocating transmission expenses to the individual rate
12 classes, the Company will calculate a uniform cents per kilowatt-hour transmission rate
13 unique to each rate class to be charged equally to all customers of the particular rate class.
14 This calculation is illustrated in Workpaper TMB-3.
15
16 Q. What is the effect of the consolidation of transmission costs on transmission revenue
17 generated from Eastern's customers?
18 A. Consolidating the transmission rates of Eastern and Mass. Electric into one transmission
19 rate will result in Eastern's customers contributing additional transmission revenue above
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 15 of 27
1 what they otherwise would have contributed absent the consolidation. Exhibit TMB-5
2 illustrates the effect of consolidating transmission rates on the customers of Eastern as
3 compared to the average transmission rate these customers are projected to be charged in
4 calendar year 2001. Eastern's customers are expected to see an increase of approximately
5 $6 million in the transmission component of their delivery rate, as indicated in this
6 exhibit. Mass. Electric's transmission expenses from NEP, NEPOOL, and the ISO are
7 higher per kilowatt-hour than Eastern's transmission expenses from Montaup, NEPOOL,
8 and the ISO. Thus, blending the transmission rates reduces the transmission component
9 of Mass. Electric's delivery rate to Mass. Electric's existing customers and increases the
10 transmission component of the delivery rate to Eastern's existing customers.
11
12 Transition
13 Q. What is the Company's proposal for billing transition charges after the Consolidation
14 Date?
15 A. Mass. Electric is proposing to move Eastern's customers and Mass. Electric's customers
16 onto a consolidated transition charge. This consolidated transition charge will sum the
17 Montaup contract termination charge bill to Eastern and the NEP contract termination
18 charge bill to Mass. Electric to arrive at a total contract termination charge for the
19 combined company. This calculation is illustrated in Workpaper TMB-4. From this
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 16 of 27
1 combined contract termination charge, the Company will calculate a uniform cents per
2 kilowatt-hour transition charge to be charged equally to all customers of the combined
3 company.
4
5 Q. What is the effect of the proposed consolidation of contract termination charges on
6 transition revenue generated from Eastern's customers?
7 A. Eastern's customers are expected to receive a significant reduction in transition charges
8 as a result of consolidating the transition charges of Eastern and Mass. Electric. Exhibit
9 TMB-6 illustrates the effect of consolidating transition charges on the customers of
10 Eastern as compared to the transition charges these customers would otherwise be
11 charged in calendar year 2001, which is calculated in Workpaper TMB-5. Eastern's
12 customers are expected to see a transition rate decrease of approximately $28 million, as
13 indicated in this exhibit. This decrease is due to Mass. Electric's contract termination
14 charge as billed to it by NEP being significantly lower than Eastern's contract termination
15 charge as billed to it by Montaup.
16
17 Results of Rate Plan
18 Q. Has the Company determined what the results of the above proposed rate plan are on the
19 retail delivery service revenue to be generated by Eastern's customers?
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 17 of 27
1 A. Yes it has. The $28 million decrease in transition charges is offset by the increases in
2 transmission and distribution charges discussed above. As illustrated in Exhibit TMB-7,
3 Mass. Electric anticipates that overall, Eastern's customers will see a decrease in the first
4 year of rate consolidation of approximately $19.6 million in retail delivery service
5 billings in accordance with the proposed rate plan. This exhibit compares, for Eastern's
6 customers the estimated retail delivery service revenue generated in calendar year 2001
7 with and without the proposed rate consolidation. The significant reduction is driven by
8 the decrease in the projected consolidated transition charge that Eastern's customers are
9 anticipated to be charged during calendar year 2001 as compared to the Eastern-only
10 projected transition charge for the same year.
11
12 Q. Will the proposed rate plan still provide the rate reductions required under the Act for
13 Mass. Electric's customers?
14 A. Yes it will. Page 1 of Exhibit TMB-8 recasts Mass. Electric's total company rate path
15 provided in Exhibit TMB-1 for the proposed rate plan, reflecting the extension of the
16 current distribution rate freeze by two years. The average distribution rate remains at
17 current levels through calendar year 2002. Demand side management and renewables
18 charges are as mandated in the Act. The projected average transmission rate declines
19 slightly as compared to its original projection for calendar year 2001 due to the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 18 of 27
1 consolidation of transmission expenses of Eastern and Mass. Electric. And the projected
2 average transition charge increases slightly as compared to the originally projected level
3 for calendar year 2001, but continues to decline from its level from calendar year 2000.
4 With these revisions to the total company rate path, the rate reductions required under the
5 Act continue to be met, as illustrated on p. 1, Line (8) of Exhibit TMB-8.
6
7 Q. Will the proposed rate plan provide the statutory rate reductions if the distribution rate
8 freeze is extended for an additional two years through the end of calendar year 2004?
9 A. Yes it will. Page 2 of Exhibit TMB-8 presents the effects of a longer distribution rate
10 freeze on the statutory rate reductions. Again, Line (8) reflects that Mass. Electric will
11 continue to provide the statutory rate reductions required under the Act.
12
13 VI. Typical Bills
14 Q. Has the Company prepared typical bills showing the impacts on the proposed rate plan at
15 typical usage levels for Eastern?
16 A. Yes it has. Exhibit TMB-10 presents typical bills for Eastern. This exhibit compares
17 stand-alone actual and projected rates on January 1, 2001 to consolidated actual and
18 projected rates on January 1, 2001 assuming the merger and rate consolidation occur as
19 proposed. A typical 500 kilowatt-hour residential customer on Eastern's Rate R-1 is
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 19 of 27
1 estimated to be billed $52.90 by Eastern after January 1, 2001, and is estimated to be
2 billed $48.16 by Mass. Electric based on consolidated rates after January 1, 2001,
3 reflecting a decrease of $4.74, or 9.0%. Further savings will be realized in the future as
4 the result of the distribution rate freeze. These savings are not reflected in the typical bill
5 analysis.
6
7 Q. Has the Company prepared similar typical bills showing the impacts on the proposed rate
8 plan at typical usage levels for Mass. Electric?
9 A. Yes it has. Exhibit TMB-11 presents typical bills for Mass. Electric. As in Exhibit
10 TMB-10, Exhibit TMB-11 presents a bill comparison between stand-alone actual and
11 projected rates after January 1, 2001 and consolidated actual and projected rates after
12 January 1, 2001. The bill for a typical 500 kilowatt-hour residential customer on Mass.
13 Electric's Rate R-1 after January 1, 2001 is estimated to increase by $0.56, or 1.2%, from
14 $47.60 to $48.16. However, the $48.16 monthly bill after the proposed rate consolidation
15 will represent a decrease of $0.84, or 1.7% from Mass. Electric's typical bill in calendar
16 year 2000 that is estimated to be $49.00.
17
18 A comparison of Mass. Electric's average delivery rates from calendar years 2000 to
19 2001 is shown in Exhibit TMB-8. The average delivery rate in calendar year 2001 of
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 20 of 27
1 4.619(cent) per kilowatt-hour represents a decrease of 3.3% from the average delivery rate in
2 calendar year 2000 of 4.779(cent) per kilowatt-hour. Therefore, the proposed rate plan
3 continues to provide lower rates to Mass. Electric's existing customers, despite the slight
4 increase caused by the blending of the transition charge.
5
6 Q. Do any bills to Eastern's customers increase after the proposed consolidation?
7 A. Yes. The proposed rate consolidation increases prices to one Eastern rate class as shown
8 in Exhibit TMB-7. In addition, a review of Eastern's typical bills in Exhibit TMB-10
9 shows that, at specific usage levels within rate classes, some customers may see increases
10 after the Consolidation Date as a result of the proposed rate plan. These are identified
11 below.
12
13 Eastern's S-1 Customers to Mass. Electric's S-1 Rate
14 The rate class which experiences an increase is Eastern's streetlight rate class, Rate S-1
15 (see Exhibit TMB-7). Even with the decrease in the transition charge, this rate class will
16 experience an increase in retail delivery service billings. This increase occurs because
17 Mass. Electric's streetlight distribution rates are higher than Eastern's streetlight
18 distribution rates, as shown in Exhibit TMB-4. However, most municipal customers will
19 still experience savings when all of their accounts are aggregated and analyzed in total for
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 21 of 27
1 the impact of the proposed rate consolidation. The results of this analysis by community
2 is presented in Exhibit TMB-12. In addition, Eastern's municipalities will experience a
3 further and ongoing benefit from the proposed distribution rate freeze that would not
4 occur absent the merger. Similar benefits will be realized by private lighting customers
5 who will see rate reductions for general use at their service locations, and will also realize
6 the benefits of the distribution rate freeze.
7
8 Eastern's Small G-2 Customers to Mass. Electric's G-1 Rate
9 Some of Eastern's small commercial and industrial customers now served on demand
10 rates will experience an increase when placed on Mass. Electric's Rate G-1 (Small
11 Commercial and Industrial). The effects are shown on pages 7-10 of Exhibit TMB-10.
12 Eastern's Rate G-2 maps to three of Mass. Electric's general service rates: Rate G-1, Rate
13 G-2 Demand General Service, and Rate G-3 Time-of-Use General Service, as discussed
14 in the testimony of Mr. Bonner. Based upon the differences between the rate structures
15 of Eastern's Rate G-2 tariff and Mass. Electric's Rate G-1 tariff, these small general
16 service customers with high hours use (illustrated on pp. 10-11) are expected to see
17 increases in their bills upon implementation of the rate consolidation in calendar year
18 2001. Eastern's Rate G-2 has a demand component to its rate structure, while Mass.
19 Electric's Rate G-1 does not, and the customer charge under Eastern's Rate G-2 is
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 22 of 27
1 significantly lower than that of Mass. Electric's Rate G-1. The short-term increase for
2 these customers is mitigated by the economic benefits from the proposed distribution rate
3 freeze.
4
5 Eastern's Small T-2 Customers to Mass. Electric's G-1 Rate
6 Small commercial and industrial customers served on Eastern's time-of-use Rate T-2 will
7 also see an increase (see Exhibit TMB-10, pp. 43-47). Eastern Edison's Rate T-2 also
8 maps to the three Mass. Electric general service rates. Again, based upon the differences
9 between the rate structures of Eastern's Rate T-2 tariff and Mass. Electric's Rate G-1
10 tariff, these small general service customers with high hours use (illustrated on pp. 45-47)
11 are expected to see increases in their bills upon implementation of the proposed rate
12 consolidation. Eastern's Rate T-2 has both a demand component and an on peak/off peak
13 kilowatt-hour charge differential to its rate structure, while Mass. Electric's Rate G-1
14 does not. Again, the economic effect of the short-term increase is mitigated by the
15 proposed distribution rate freeze.
16
17 Eastern's Small H-1 Customers to Mass. Electric's G-1 Rate
18 Eastern's smaller customers on Rate H-1, General Space Heating, transferring to Mass.
19 Electric's Rate G-1, Small Commercial and Industrial are also affected by the proposed
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 23 of 27
1 rate consolidation (see Exhibit TMB-10, p. 60, and Exhibit TMB-7). Eastern's Rate H-1
2 also maps to the three Mass. Electric general service rates. Mass. Electric has eliminated
3 its commercial space heating rates, and these small general service customers will see
4 increases in their bills upon transfer to Rate G-1. Both the customer charge and
5 distribution energy charge under Mass. Electric's Rate G-1 are greater than the customer
6 charge and distribution energy charge of Eastern's Rate H-1.
7
8 Eastern's Small H-2 Customers to Mass. Electric's G-1 Rate
9 Eastern's smaller customers on Rate H-2, General Heating, transferring to Mass.
10 Electric's Rate G-1, Small Commercial and Industrial are affected the same way (see
11 Exhibit TMB- 10, p. 73 and Exhibit TMB-7). Eastern's Rate H-2 maps to two of Mass.
12 Electric's general service rates: Rate G-1 and Rate G-2. Mass. Electric has eliminated its
13 commercial heating rate, and these small general service customers are also expected to
14 see increases in their bills upon transfer to Rate G-1. Both the customer charge and
15 distribution energy charge under Mass. Electric's Rate G-1 are greater than the customer
16 charge and distribution energy charge of Eastern's Rate H-2.
17
18 Eastern's Non-Residential W-1 Customers to Mass. Electric's G-1 Rate
19 The other Eastern special end use rate is for water heating and will also be eliminated,
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New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 24 of 27
1 producing increases in this component of the customer's bill. Eastern's non-residential
2 customers on Rate W-1, Controlled Water Heating, transferring to Mass. Electric's Rate
3 G-1, Small Commercial and Industrial. Eastern's Rate W-1 provides service to both
4 residential and non-residential customers, and therefore maps to Mass. Electric Rate R-1,
5 Regular Residential, Rate R-2, Low Income Residential, and Rate G-1. Mass. Electric
6 Rate R-1 and Rate R-2 include a provision for a controlled water heating credit, however
7 Rate G-1 does not. Therefore Eastern's non-residential Rate W-1 customers will see an
8 increase by transferring to Mass. Electric's Rate G-1. The increases under this rate will
9 be mitigated, if not eliminated, by reductions in the bill for the customer's general usage,
10 and by the proposed distribution rate freeze aspect of the proposed rate plan.
11
12 Q. Is the Company proposing any rate design changes to address these effects to specific
13 customer groups?
14 A. No. Eastern's customers as a whole will benefit significantly from the proposed merger
15 and rate consolidation, as illustrated by the approximately $19.6 million reduction in
16 retail delivery service revenue identified in Exhibit TMB-7. The rate increases discussed
17 above largely stem from the movement of Eastern's customers onto Mass. Electric's
18 simpler rate structure. As will occur in any rate design and implementation, the change
19 will produce benefits to one group of customers and detriments to a second group. In this
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 25 of 27
1 case, because the rate designs are similar between the two companies and because
2 Eastern's overall rates are declining, the bill impacts for these customers are relatively
3 small and reasonable. Moreover, many of the bill impacts occur for special end use rates.
4 These effects are mitigated or reversed when evaluated in light of the customer's overall
5 usage of electricity. For example, streetlight increases to municipalities are offset by
6 price reductions at municipal facilities, and as a whole municipal customers benefit from
7 the proposed rate plan, as illustrated in Exhibit TMB-12. Water heating rate increases are
8 substantially reduced or reversed by reductions in the customer's usage from other
9 general purposes. Finally, the short term increases for specific Eastern customers will be
10 offset by the other longer term economic benefits of the merger, such as the long term
11 blending of transition charges and the extension of the distribution rate freeze.
12 Accordingly, the short-term increases in typical bills are reasonable given the longer term
13 benefits conferred upon Eastern's customers as a result of the merger and proposed rate
14 plan.
15
16 VII. Tariffs and Terms and Conditions
17 Q. Will Eastern's customers be subject to Mass. Electric's terms and conditions and
18 adjustment provisions after the Consolidation Date?
19 A. Yes. Eastern's customers will be subject to all of Mass. Electric's tariffs and terms and
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 26 of 27
1 conditions after the Consolidation Date.
2
3 Q. Has the Company determined whether or not it needs to make any revisions to its
4 adjustment provisions as a result of the merger?
5 A. Yes it has. The Company has reviewed its Transmission Service Cost Adjustment
6 Provision (M.D.T.E. No. 977-D), Transition Cost Adjustment Provision (M.D.T.E. No.
7 978-C), Standard Service Cost Adjustment Provision (M.D.T.E. No. 981-A), and Default
8 Service Adjustment Provision (M.D.T.E. No. 987-A) to determine whether the provisions
9 are sufficient to provide for service, reconciliation, and adjustment of rates subsequent to
10 the merger.
11
12 Q. Based upon this review, are there any adjustment provisions requiring revision?
13 A. No, there are not.
14
15 Q. Currently, Eastern has one customer receiving auxiliary service under Rate A-6. What is
16 Mass. Electric's proposal for this customer?
17 A. Mass. Electric is proposing to provide auxiliary service to this customer under its existing
18 Auxiliary Service Provision, M.D.P.U. No. 649-D. To achieve this transfer, the customer
19 will be placed directly onto Mass. Electric's Rate G-3 and be billed for auxiliary service
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of T. M. Burns
Page 27 of 27
1 as needed under this rate. The shift to Mass. Electric's Rate G-3 will produce a rate
2 reduction for the customer and treats this customer consistently with Mass. Electric's
3 other auxiliary service customers.
4
5 VIII. Conclusion
6 Q. Does this conclude your testimony?
7 A. Yes it does.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
EXHIBITS AND WORKPAPERS
OF
THERESA M. BURNS
Exhibit TMB-1 Massachusets Electric Company Total Company Rate Path
Assuming No Consolidation
Exhibit TMB-2 Eastern Edison Company Total Company Rate Path Assuming No
Consolidation
Exhibit TMB-3 Proposed Mapping of Eastern Rate Classes to Mass. Electric
Rate Classes
Exhibit TMB-4 Eastern Edison Company - Impact on Distribution Revenue
Exhibit TMB-5 Eastern Edison Company - Impact on Transmission Revenue
Exhibit TMB-6 Eastern Edison Company - Impact on Transition Revenue
Exhibit TMB-7 Eastern Edison Company - Impact on Retail Delivery Service
Revenue
Exhibit TMB-8 Massachusetts Electric Company Total Company Rate Path
Assuming Rate Consolidation on January 1, 2001
Exhibit TMB-9 Eastern Edison Company Total Company Rate Path Assuming Rate
Consolidation on January 1, 2001
Exhibit TMB-10 Eastern Edison Company Typical Bills - January 1, 2001
Assuming No Merger vs. January 1, 2001 Combined Rates
Exhibit TMB-11 Massachusetts Electric Company Typical Bills - January 1,
2001 Assuming No Merger vs. January 1, 2001 Combined Rates
Exhibit TMB-12 Eastern Edison Company - Total Municipal Revenue Analysis
Workpaper TMB-1 Eastern Edison Company Detail Supporting Revenue Impact
Workpaper TMB-2 Eastern Edison Company Estimated Retail Transmission Rate in
Year 2001
Workpaper TMB-3 Massachusetts Electric Company Consolidated Retail
Transmission Rates Assuming Rate Consolidation on January 1,
2001
Workpaper TMB-4 Massachusetts Electric Company Estimated Combined Transition
Charge in Year 2001
Workpaper TMB-5 Eastern Edison Company Estimated Transition Charges in Year
2001
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-1
Massachusets Electric Company
Total Company Rate Path
Assuming No Consolidation
<PAGE>
<TABLE>
<CAPTION>
C:\eua files on disk\tmb-1.WK4 New England Electric System
MECO-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-1
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
Average (cent)/kWh
Without Consolidation with Eastern Edison
1998 1999
-------------------- -------------------------------
Benchmark
Rates
8/01/97 March 1 September 1 January 1 March 1 September 1 2000 2001 2002 2003 2004
------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(1) Distribution 2.270 2.502 2.502 2.502 2.502 2.502 2.502 2.557 2.613 2.670 2.729
(1a) DSM 0.350 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250
(1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
TOTAL DISTRIBUTION 2.620 2.907 2.907 2.912 2.912 2.912 2.912 2.927 2.938 2.970 3.029
(2) Transmission 0.429 0.404 0.404 0.535 0.535 0.535 0.547 0.559 0.571 0.584 0.597
(2a) Transmission
Adjustment 0.106 0.106 0.106 tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- ----- ----
TOTAL TRANSMISSION 0.429 0.404 0.404 0.641 0.641 0.641 0.547 0.559 0.571 0.584 0.597
(3) Transition 3.400 2.707 1.407 1.246 1.339 1.339 1.320 1.070 1.070 1.000 0.940
(3a) Transition Adjustment (0.011) (0.011) (0.011) tbd tbd tbd tbd tbd
------ ------ ------ ----- ----- ----- ----- -----
TOTAL TRANSITION 3.400 2.707 1.407 1.235 1.328 1.328 1.320 1.070 1.070 1.000 0.940
(4) TOTAL AVERAGE RETAIL
DELIVERY PRICE 6.449 6.018 4.718 4.788 4.881 4.881 4.779 4.556 4.579 4.554 4.566
- -----------------------------------------------------------------------------------------------------------------------------------
(5) Standard Service
Backstop 3.366 2.800 3.200 3.500 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(5a) Standard Service
Adjustment 0.207 0.207 0.207 tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- ----- -----
TOTAL STANDARD SERVICE 3.366 2.800 3.200 3.707 3.707 3.707 3.800 3.800 4.200 4.700 5.100
(6) TOTAL AVERAGE PRICE
(EXCL. DISCOUNTS 9.815 8.818 7.918 8.495 8.588 8.588 8.579 8.356 8.779 9.254 9.666
(7) Statutory Benchmark,
Adjusted for Inflation 9.815 9.815 9.815 9.815 10.174 10.495 10.726 10.962 11.203 11.449
(8) Savings Off Inflation-
Adjusted Price 10.16% 19.33% 13.45% 12.50% 15.59% 18.26% 22.10% 19.91% 17.40% 15.57%
- -----------------------------------------------------------------------------------------------------------------------------------
(1),(2) Assumed Inflation Rate for Distribution and Transmission Components 2.2%
and Statutory Benchmark Beyond 2000
(3) Exhibits of J.K. Zschokke
(7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Page 2 of 2
</TABLE>
<PAGE>
C:\eua files on disk\tmb-1.WK4 New England Electric System
MECO INFLAT Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB- 1
Page 2 of 2
Massachusetts Electric Company
Determination of Statutory Benchmark, Adjusted for Inflation
August 1, 1997 to December 31, 2000
CPI Percentage Benchmark
Index Change Rates
----- ------ -----
ACTUAL
Aug-97 160.5 1/ 9.815
Sep-97 160.8 1/ 0.187% 9.833
Oct-97 161.2 1/ 0.249% 9.857
Nov-97 161.6 1/ 0.248% 9.881
Dec-97 161.5 1/ -0.062% 9.875
Jan-98 161.3 1/ -0.124% 9.863
Feb-98 161.6 1/ 0.186% 9.881
Mar-98 161.9 1/ 0.186% 9.899
Apr-98 162.2 1/ 0.185% 9.917
May-98 162.5 1/ 0.185% 9.935
Jun-98 162.8 1/ 0.185% 9.953
Jul-98 163.0 1/ 0.123% 9.965
Aug-98 163.2 1/ 0.123% 9.977
Sep-98 163.4 1/ 0.123% 9.989
Oct-98 163.6 1/ 0.122% 10.001
Nov-98 164.0 1/ 0.244% 10.025
Dec-98 164.0 1/ 0.000% 10.025
PROJECTED
1st Quarter 1999 165.1 2/ 0.670% 10.092
2nd Quarter 1999 165.9 2/ 0.484% 10.141
3rd Quarter 1999 (through Aug-99) 166.7-2/ 0.321% 10.174
3rd Quarter 1999 (Sep-99) 0.160% 10.190
4th Quarter 1999 167.7 2/ 0.599% 10.251
1st Quarter 2000 168.6 2/ 0.536% 10.306
2nd Quarter 2000 169.6 2/ 0.593% 10.367
3rd Quarter 2000 170.6 2/ 0.589% 10.428
4th Quarter 2000 171.7 2/ 0.644% 10.495
-------------------------------------------------------------------
1/ Historical Consumer Price Index - All Urban Consumers (CPI-U)
obtained from the Bureau of Labor Statistics
2/ Projected CPI growth from the Blue Chip Economic Forecast dated
February 10, 1999
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-2
Eastern Edison Company
Total Company Rate Path
Assuming No Consolidation
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System
EEC-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-2, Revised
Page 1 of 2
EASTERN EDISON COMPANY
Average (cent)/kWh
Without Consolidation with Massachusetts Electric
1998 1999
-------------------- -------------------------------
Benchmark
Rates
8/01/97 March 1 September 1 January 1 April 1 September 1 2000 2001 2002 2003 2004
------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(1) Distribution 2.743 2.743 2.743 2.743 2.743 2.743 2.803 2.865 2.928 2.992
(1a) DSM 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250
(1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
TOTAL DISTRIBUTION 0.000 3.148 3.148 3.153 3.153 3.153 3.153 3.173 3.190 3.228 3.292
(2) Transmission 0.258 0.258 0.215 0.270 0.298 0.285 0.291 0.297 0.304 0.311
(2a) Transmission
Adjustment tbd tbd tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- -----
TOTAL TRANSMISSION 0.000 0.258 0.258 0.215 0.270 0.298 0.285 0.291 0.297 0.304 0.311
(3) Transition 3.040 3.040 3.040 2.100 2.100 2.380 2.300 2.220 1.840 1.690
(3a) Transition Adjustment tbd tbd tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- -----
TOTAL TRANSITION 0.000 3.040 3.040 3.040 2.100 2.100 2.380 2.300 2.220 1.840 1.690
(4) TOTAL AVERAGE RETAIL
DELIVERY PRICE 6.446 6.446 6.408 5.523 5.551 5.818 5.764 5.707 5.372 5.293
- -----------------------------------------------------------------------------------------------------------------------------------
(5) Standard Service
Backstop 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(5a) Standard Service
Adjustment n/a n/a tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- -----
TOTAL STANDARD SERVICE 0.000 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(6) TOTAL AVERAGE PRICE
(EXCL. DISCOUNTS 10.471 9.246 9.246 9.508 9.023 9.051 9.618 9.564 9.907 10.072 10.393
(7) Statutory Benchmark,
Adjusted for Inflation 10.471 10.471 10.471 10.471 10.860 11.203 11.449 11.701 11.958 12.221
(8) Savings Off Inflation-
Adjusted Price 11.70% 11.70% 9.20% 13.83% 16.66% 14.15% 16.46% 15.33% 15.77% 14.96%
- -----------------------------------------------------------------------------------------------------------------------------------
(1),(2) Assumed Inflation Rate for Distribution and Transmission Components 2.2%
and Statutory Benchmark Beyond 2000
(3) February 12, 1999 Divestiture Filing
(7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Page 2 of 2
</TABLE>
<PAGE>
C:\eua files on disk\tmb-2.WK4 New England Electric System
EEC INFLAT Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB- 2, Revised
Page 2 of 2
Eastern Edison Company
Determination of Statutory Benchmark, Adjusted for Inflation
August 1, 1997 to December 31, 2000
CPI Percentage Benchmark
Index Change Rates
----- ------ -----
ACTUAL
Aug-97 160.5 1/ 10.471
Sep-97 160.8 1/ 0.187% 10.491
Oct-97 161.2 1/ 0.249% 10.517
Nov-97 161.6 1/ 0.248% 10.543
Dec-97 161.5 1/ -0.062% 10.536
Jan-98 161.3 1/ -0.124% 10.523
Feb-98 161.6 1/ 0.186% 10.543
Mar-98 161.9 1/ 0.186% 10.563
Apr-98 162.2 1/ 0.185% 10.583
May-98 162.5 1/ 0.185% 10.603
Jun-98 162.8 1/ 0.185% 10.623
Jul-98 163.0 1/ 0.123% 10.636
Aug-98 163.2 1/ 0.123% 10.649
Sep-98 163.4 1/ 0.123% 10.662
Oct-98 163.6 1/ 0.122% 10.675
Nov-98 164.0 1/ 0.244% 10.701
Dec-98 164.0 1/ 0.000% 10.701
PROJECTED
1st Quarter 1999 165.1 2/ 0.670% 10.773
2nd Quarter 1999 165.9 2/ 0.484% 10.825
3rd Quarter 1999 (through Aug-99) 166.7 2/ 0.321% 10.860
3rd Quarter 1999 (Sep-99) 0.160% 10.877
4th Quarter 1999 167.7 2/ 0.599% 10.942
1st Quarter 2000 168.6 2/ 0.536% 11.001
2nd Quarter 2000 169.6 2/ 0.593% 11.066
3rd Quarter 2000 170.6 2/ 0.589% 11.131
4th Quarter 2000 171.7 2/ 0.644% 11.203
------------------------------------------------------------------------
1/ Historical Consumer Price Index - All Urban Consumers (CPI-U)
obtained from the Bureau of Labor Statistics
2/ Projected CPI growth from the Blue Chip Economic Forecast dated
February 10, 1999
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-3
Proposed Mapping of
Eastern Rate Classes to
Mass. Electric Rate Classes
<PAGE>
S:\RADATA1\EASTED\Mapping1.wk4 New England Electric System
SUMMARY Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-3
Page 1 of 1
Massachusetts Electric Company
Eastern Edison Company
Summary of Rate Mapping
- -------------------------------------------------------------------------------
EEC MECO
Rate Description Rate Description
- -------------------------------------------------------------------------------
R-1 Residential Service R-1 Residential Service
- -------------------------------------------------------------------------------
R-2 Residential Low Income Service R-2 Residential Low Income Service
- -------------------------------------------------------------------------------
R-3 Residential Space Heating Service R-1 Residential Service
- -------------------------------------------------------------------------------
R-4 Residential Time of Use Service R-1 Residential Service
(no minimum usage)
- -------------------------------------------------------------------------------
G-1 Small Secondary Voltage Service G-1 Small C&I
(kWh<10,000 per month)
- -------------------------------------------------------------------------------
G-1 Small C&I
G-2 Medium Secondary Voltage Service G-2 General Service Demand
(kw<200 per month,
kWh>10,000 per month)
(10<kw<500, annual kWh>36,000)
G-3 Time of Use
(kw>200 per month)
- -------------------------------------------------------------------------------
G-4 Large Secondary Voltage Service G-3 Time of Use
- -------------------------------------------------------------------------------
G-2 General Service Demand
G-5 Medium Primary Voltage Service
(100<kw<500) G-3 Time of Use
- -------------------------------------------------------------------------------
G-6 Large Primary Voltage Service G-3 Time of Use
- -------------------------------------------------------------------------------
G-1 Small C&I
T-2 Medium TOU Secondary Votlage G-2 General Service Demand
Service (10<kw<500,
annual kWh>36,000) G-3 Time of Use
- -------------------------------------------------------------------------------
G-1 Small C&I
H-1 Space Heating Service G-2 General Service Demand
(non-residential)
G-3 Time of Use
- -------------------------------------------------------------------------------
G-1 Small C&I
H-2 Space Heating Service
(non-industrial) G-2 General Service Demand
- -------------------------------------------------------------------------------
R-1 Residential Service
W-1 Controlled Water Heating Service
(all customer types) G-1 Small C&I
- -------------------------------------------------------------------------------
S-1 Lighting Service S-1 Streetlighting-Company Owned
(company owned)
- -------------------------------------------------------------------------------
A-6 Auxiliary Service G-3 Time of Use
- -------------------------------------------------------------------------------
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-4
Eastern Edison Company
Impact on Distribution Revenue
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
DIST REVENUE Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit TMB-4
Page 1 of 1
Massachusetts Electric Company
Eastern Edison Company
Revenue Comparison Based on
Distribution Rates Effective March 1, 1998
Distribution Revenue
Eastern Eastern $
Edison Edison Revenue %
Eastern Edison Mass. Electric Units on Units on Increase Increase
Rate Class Rate Class EEC 2001 Rate $/kWh Consol. 2001 Rate $/kWh (Decrease) (Decrease)
--------------- -------------- ------------- ----- ----------------- ----- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
R-1: Regular Residential R-1: Regular Residential $34,195,956 $0.03811 $32,359,837 $0.03606 ($1,836,119) -5.37%
R-2: Low Income
Residential R-2: Low Income Residential $535,326 $0.00797 $898,391 $0.01338 $363,065 67.82%
R-3: Residential Space
Heat R-1: Regular Residential $1,836,429 $0.02600 $2,176,005 $0.03081 $339,576 18.49%
R-4: Large Residential R-1: Regular Residential $14,067 $0.02438 $17,600 $0.03050 $3,533 25.12%
W-1: Controlled Water
Heat R-1: Regular Residential $1,308,877 $0.02688 $1,276,239 $0.02621 ($32,638) -2.49%
---------- ---------- --------
Total Residential $37,890,656 $0.03494 $36,728,072 $0.03387 ($1,162,583) -3.07%
- ---------------------------------------------------------------------------------------------------------------------------
G-1: Small Secondary
Voltage G-1: Small C&I $4,933,943 $0.04522 $5,944,826 $0.05449 $1,010,883 20.49%
G-2: Medium Secondary
Voltage G-1: Small C&I $6,763,214 $0.02797 $9,807,323 $0.04055 $3,044,109 45.01%
G-2: Medium C&I $9,725,074 $0.02292 $8,568,240 $0.02020 ($1,156,834) -11.90%
G-3: Large C&I $3,869,559 $0.02230 $3,011,607 $0.01735 ($857,953) -22.17%
G-4: Large Secondary
Voltage G-3: Large C&I $4,518,331 $0.01310 $4,977,073 $0.01443 $458,742 10.15%
G-5: Medium Primary
Voltage G-2: Medium C&I $146,756 $0.02059 $122,553 $0.01720 ($24,203) -16.49%
G-3: Large C&I $376,004 $0.02060 $308,082 $0.01688 ($67,922) -18.06%
G-6: Large Primary Voltage G-3: Large C&I $2,623,010 $0.01349 $2,537,193 $0.01305 ($85,818) -3.27%
T-2: Medium TOU Secondary G-1: Small C&I $19,356 $0.01642 $47,777 $0.04053 $28,422 146.84%
G-2: Medium C&I $174,447 $0.00931 $300,863 $0.01605 $126,416 72.47%
G-3: Large C&I $444,783 $0.00837 $693,296 $0.01304 $248,512 55.87%
H-1: Space Heating (non-
resid) G-1: Small C&I $74,569 $0.02930 $108,058 $0.04245 $33,489 44.91%
G-2: Medium C&I $19,002 $0.02696 $21,794 $0.03092 $2,792 14.69%
G-3: Large C&I $179,140 $0.02673 $185,431 $0.02767 $6,291 3.51%
H-2: Space Heating (non-
indust) G-1: Small C&I $67,696 $0.02944 $104,828 $0.04559 $37,131 54.85%
G-2: Medium C&I $3,844 $0.02840 $3,306 $0.02442 ($538) -14.00%
W-1: Controlled Water Heat G-1: Small C&I $20,705 $0.02657 $52,542 $0.06741 $31,837 153.76%
------- ------- ------
Total Commercial and Industrial $33,959,436 $0.02123 $36,794,790 $0.02300 $2,835,354 8.35%
- ----------------------------------------------------------------------------------------------------------------------------
S-1: Lighting S-1: Company Owned $2,538,661 $0.09083 $3,454,923 $0.12105 $916,262 36.09%
- ----------------------------------------------------------------------------------------------------------------------------
Total Company $74,388,752 $0.02743 $76,977,785 $0.02838 $2,589,033 3.48%
- ----------------------------------------------------------------------------------------------------------------------------
Total kWh 2,711,961,115 2,712,552,392
Source: Workpaper TMB-1
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-5
Eastern Edison Company
Impact on Transmission Revenue
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit TMB-5, Revised
Page 1 of 1
Massachusetts Electric Company
Eastern Edison Company
Revenue Comparison Based on
Transmission Rates
Transmission Revenue
EASTERN $
EDISON EASTERN EDISON REVENUE %
EASTERN EDISON MASS. ELECTRIC UNITS ON UNITS ON CONSOL. INCREASE INCREASE
RATE CLASS RATE CLASS EEC 2001 RATES $/KWH 2001 RATES $/KWH (DECREASE) (DECREASE)
---------- ---------- -------------- ----- ----------- ------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
R-1: Regular R-1: Regular $2,611,387 $0.00291 $5,124,062 $0.00571 $2,512,675 96.22%
Residential Residential
R-2: Low Income R-2: Low Income $195,402 $0.00291 $383,418 $0.00571 $188,016 96.22%
Residential Residential
R-3: Residential R-1: Regular $205,500 $0.00291 $403,232 $0.00571 $197,732 96.22%
Space Heat Residential
R-4: Large R-1: Regular $1,679 $0.00291 $3,295 $0.00571 $1,616 96.22%
Residential Residential
W-1: Controlled R-1: Regular $141,709 $0.00291 $278,062 $0.00571 $136,353 96.22%
Water Heat Residential --------- --------- ---------
Total Residential $3,155,678 $0.00291 $6,192,068 $0.00571 $3,036,391 96.22%
---------------------------------------------------------------------------------------------------------------------------
G-1: Small Secondary G-1: Small C&I $317,475 $0.00291 $619,677 $0.00568 $302,202 95.19%
Voltage
G-2: Medium Secondary G-1: Small C&I $703,722 $0.00291 $1,373,587 $0.00568 $669,866 95.19%
Voltage
G-2: Medium C&I $1,234,553 $0.00291 $2,176,377 $0.00513 $941,824 76.29%
G-3: Large C&I $505,004 $0.00291 $798,288 $0.00460 $293,284 58.08%
G-4: Large Secondary G-3: Large C&I $1,003,391 $0.00291 $1,586,117 $0.00460 $582,726 58.08%
Voltage
G-5: Medium Primary G-2: Medium C&I $20,738 $0.00291 $36,193 $0.00508 $15,455 74.53%
Voltage
G-3: Large C&I $53,107 $0.00291 $83,109 $0.00455 $30,003 56.49%
G-6: Large Primary G-3: Large C&I $565,847 $0.00291 $885,521 $0.00455 $319,674 56.49%
Voltage
T-2: Medium TOU G-1: Small C&I $3,431 $0.00291 $6,696 $0.00568 $3,266 95.19%
Secondary
G-2: Medium C&I $54,544 $0.00291 $96,155 $0.00513 $41,611 76.29%
G-3: Large C&I $154,671 $0.00291 $244,497 $0.00460 $89,826 58.08%
H-1: Space Heating G-1: Small C&I $7,407 $0.00291 $14,457 $0.00568 $7,050 95.19%
(non-resid)
G-2: Medium C&I $2,051 $0.00291 $3,616 $0.00513 $1,565 76.29%
G-3: Large C&I $19,503 $0.00291 $30,830 $0.00460 $11,327 58.08%
H-2: Space Heating G-1: Small C&I $6,691 $0.00291 $13,060 $0.00568 $6,369 95.19%
(non-indust)
G-2: Medium C&I $394 $0.00291 $694 $0.00513 $301 76.29%
W-1: Controlled G-1: Small C&I $2,268 $0.00291 $4,427 $0.00568 $2,159 95.19%
Water Heat ------- ------- -------
Total Commercial $4,654,796 $0.00291 $7,973,302 $0.00498 $3,318,506 71.29%
and Industrial
--------------------------------------------------------------------------------------------------------------------------
S-1: Lighting S-1: Company Owned $81,333 $0.00291 $137,566 $0.00482 $56,233 69.14%
--------------------------------------------------------------------------------------------------------------------------
Total Company $7,891,807 $0.00291 $14,302,937 $0.00527 $6,411,130 81.24%
-------------------------------------------------------------------------------------------------------------------------
Total kWh 2,711,961,115 2,712,552,392
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-6
Eastern Edison Company
Impact on Transition Revenue
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
TRANSI REVENUE Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit TMB-6
Page 1 of 1
Massachusetts Electric Company
Eastern Edison Company
Revenue Comparison Based on
Transition Rates
Transition Revenue
Eastern Eastern
Edison Edison $
Units on Units on Revenue %
Eastern Edison Mass. Electric EEC 2001 Consol. Increase Increase
Rate Class Rate Class Rate $/kWh 2001 Rate $/kWh (Decrease) (Decrease)
---------- ---------- -------- ----- --------- ----- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
R-1: Regular Residential R-1: Regular Residential $20,639,828 $0.02300 $11,217,298 $0.01250 ($9,422,530) -45.65%
R-2: Low Income Residential R-2: Low Income Residential $1,544,415 $0.02300 $839,356 $0.01250 ($705,059) -45.65%
R-3: Residential Space Heat R-1: Regular Residential $1,624,226 $0.02300 $882,732 $0.01250 ($741,495) -45.65%
R-4: Large Residential R-1: Regular Residential $13,350 $0.02313 $7,214 $0.01250 ($6,136) -45.96%
W-1: Controlled Water Heat R-1: Regular Residential $1,120,039 $0.02300 $608,717 $0.01250 ($511,322) -45.65%
Total Residential $24,941,858 $0.02300 $13,555,316 $0.01250 ($11,386,54) -45.65%
- ----------------------------------------------------------------------------------------------------------------------------------
G-1: Small Secondary Voltage G-1: Small C&I $2,509,256 $0.02300 $1,363,726 $0.01250 ($1,145,530) -45.65%
G-2: Medium Secondary Voltage G-1: Small C&I $6,800,623 $0.02812 $3,022,860 $0.01250 ($3,777,763) -55.55%
G-2: Medium C&I $8,735,503 $0.02059 $5,303,063 $0.01250 ($3,432,440) -39.29%
G-3: Large C&I $3,430,400 $0.01977 $2,169,262 $0.01250 ($1,261,139) -36.76%
G-4: Large Secondary Voltage G-3: Large C&I $7,823,168 $0.02269 $4,310,100 $0.01250 ($3,513,068) -44.91%
G-5: Medium Primary Voltage G-2: Medium C&I $160,783 $0.02256 $89,080 $0.01250 ($71,703) -44.60%
G-3: Large C&I $432,655 $0.02371 $228,122 $0.01250 ($204,533) -47.27%
G-6: Large Primary Voltage G-3: Large C&I $4,505,296 $0.02317 $2,430,612 $0.01250 ($2,074,684) -46.05%
T-2: Medium TOU Secondary G-1: Small C&I $39,752 $0.03372 $14,737 $0.01250 ($25,015) -62.93%
G-2: Medium C&I $462,403 $0.02467 $234,295 $0.01250 ($228,108) -49.33%
G-3: Large C&I $1,237,834 $0.02329 $664,393 $0.01250 ($573,441) -46.33%
H-1: Space Heating (non-resid) G-1: Small C&I $58,542 $0.02300 $31,816 $0.01250 ($26,726) -45.65%
G-2: Medium C&I $16,212 $0.02300 $8,811 $0.01250 ($7,401) -45.65%
G-3: Large C&I $154,151 $0.02300 $83,778 $0.01250 ($70,373) -45.65%
H-2: Space Heating (non-indust) G-1: Small C&I $52,884 $0.02300 $28,742 $0.01250 ($24,143) -45.65%
G-2: Medium C&I $3,113 $0.02300 $1,692 $0.01250 ($1,421) -45.65%
W-1: Controlled Water Heat G-1: Small C&I $17,927 $0.02300 $9,743 $0.01250 ($8,184) -45.65%
Total Commercial and Industrial $36,440,502 $0.02278 $19,994,829 $0.01250 ($16,445,672) -45.13%
- ----------------------------------------------------------------------------------------------------------------------------------
S-1: Lighting S-1: Company Owned $642,838 $0.02300 $356,760 $0.01250 ($286,079) -44.50%
- ----------------------------------------------------------------------------------------------------------------------------------
Total Company $62,025,198 $0.02287 $33,906,905 $0.01250 ($28,118,293) -45.33%
- ----------------------------------------------------------------------------------------------------------------------------------
Total kWh 2,711,961,115 2,712,552,392
Source: Workpaper TMB-1
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-7
Eastern Edison Company
Impact on Retail Delivery Service Revenue
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\01vs01a.wk4 New England Electric System
WIRES REVENUE Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Exhibit TMB-7, Revised
Page 1 of 1
Massachusetts Electric Company
Eastern Edison Company
Revenue Comparison Based on
Rates Effective March 1, 1999
Retail Delivery Service Revenue
Eastern Eastern $
Edison Edison Revenue %
Eastern Edison Mass. Electric Units on Units on Increase Increase
Rate Class Rate Class EEC 2001 Rates $/kWh Consol. 2001 Rates $/kWh (Decrease) (Decrease)
-------------- -------------- -------------- ----- ------------------ ----- ---------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
R-1: Regular Residential R-1: Regular Residential $57,447,171 $0.06402 $48,701,196 $0.05427 ($8,745,975) -15.22%
R-2: Low Income
Residential R-2: Low Income Residential $2,275,143 $0.03388 $2,121,165 $0.03159 ($153,978) -6.77%
R-3: Residential Space
Heat R-1: Regular Residential $3,666,155 $0.05191 $3,461,968 $0.04902 ($204,187) -5.57%
R-4: Large Residential R-1: Regular Residential $29,097 $0.05042 $28,110 $0.04871 ($987) -3.39%
W-1: Controlled Water Heat R-1: Regular Residential $2,570,625 $0.05279 $2,163,018 $0.04442 ($407,607) -15.86%
---------- ---------- ---------
Total Residential $65,988,191 $0.06085 $56,475,456 $0.05208 ($9,512,735) -14.42%
- ------------------------------------------------------------------------------------------------------------------------------
G-1: Small Secondary
Voltage G-1: Small C&I $7,760,675 $0.07113 $7,928,229 $0.07267 $167,554 2.16%
G-2: Medium Secondary
Voltage G-1: Small C&I $14,267,559 $0.05900 $14,203,770 $0.05873 ($63,789) -0.45%
G-2: Medium C&I $19,695,130 $0.04642 $16,047,680 $0.03783 ($3,647,451) -18.52%
G-3: Large C&I $7,804,964 $0.04497 $5,979,157 $0.03445 ($1,825,807) -23.39%
G-4: Large Secondary
Voltage G-3: Large C&I $13,344,890 $0.03870 $10,873,290 $0.03153 ($2,471,600) -18.52%
G-5: Medium Primary
Voltage G-2: Medium C&I $328,277 $0.04606 $247,826 $0.03478 ($80,451) -24.51%
G-3: Large C&I $861,766 $0.04722 $619,313 $0.03394 ($242,452) -28.13%
G-6: Large Primary Voltage G-3: Large C&I $7,694,153 $0.03957 $5,853,325 $0.03010 ($1,840,828) -23.93%
T-2: Medium TOU Secondary G-1: Small C&I $62,538 $0.05305 $69,210 $0.05871 $6,672 10.67%
G-2: Medium C&I $691,393 $0.03689 $631,312 $0.03368 ($60,081) -8.69%
G-3: Large C&I $1,837,288 $0.03457 $1,602,185 $0.03014 ($235,103) -12.80%
H-1: Space Heating (non-
resid) G-1: Small C&I $140,518 $0.05521 $154,331 $0.06063 $13,814 9.83%
G-2: Medium C&I $37,265 $0.05287 $34,221 $0.04855 ($3,045) -8.17%
G-3: Large C&I $352,794 $0.05264 $300,039 $0.04477 ($52,756) -14.95%
H-2: Space Heating (non-
indust) G-1: Small C&I $127,272 $0.05535 $146,630 $0.06377 $19,358 15.21%
G-2: Medium C&I $7,351 $0.05431 $5,693 $0.04205 ($1,659) -22.57%
W-1: Controlled Water Heat G-1: Small C&I $40,900 $0.05248 $66,712 $0.08559 $25,812 63.11%
------- ------- -------
Total Commercial and Industrial $75,054,734 $0.04692 $64,762,921 $0.04049 ($10,291,812) -13.71%
- ------------------------------------------------------------------------------------------------------------------------------
S-1: Lighting S-1: Company Owned $3,262,832 $0.11674 $3,949,249 $0.13837 $686,417 21.04%
- ------------------------------------------------------------------------------------------------------------------------------
Total Company $144,305,757 $0.05321 $125,187,627 $0.04615 ($19,118,130) -13.25%
- ------------------------------------------------------------------------------------------------------------------------------
Total kWh 2,711,961,115 2,712,552,392
Source: Workpaper TMB-1
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-8
Massachusetts Electric Company
Total Company Rate Path
Assuming Rate Consolidation on January 1, 2001
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System
MECO-2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-8, Revised
Page 1 of 2
MASSACHUSETTS ELECTRIC COMPANY
Average (cent)/kWh
With Consolidation with Eastern Edison on January 1, 2001
1998 1999
-------------------- -------------------------------
Benchmark
Rates
8/01/97 March 1 September 1 January 1 March 1 September 1 2000 2001 2002 2003 2004
------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(1) Distribution 2.270 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.557 2.613
(1a) DSM 0.350 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250
(1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
TOTAL DISTRIBUTION 2.620 2.907 2.907 2.912 2.912 2.912 2.912 2.872 2.827 2.857 2.913
(2) Transmission 0.429 0.404 0.404 0.535 0.535 0.535 0.547 0.518 0.529 0.541 0.553
(2a) Transmission
Adjustment 0.106 0.106 0.106 tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- ----- -----
TOTAL TRANSMISSION 0.429 0.404 0.404 0.641 0.641 0.641 0.547 0.518 0.529 0.541 0.553
(3) Transition 3.400 2.707 1.407 1.246 1.339 1.339 1.320 1.250 1.230 1.110 1.050
(3a) Transition Adjustment (0.011) (0.011) (0.011) tbd tbd tbd tbd tbd
------ ------ ------ ----- ----- ----- ----- -----
TOTAL TRANSITION 3.400 2.707 1.407 1.235 1.328 1.328 1.320 1.250 1.230 1.110 1.050
(4) TOTAL AVERAGE RETAIL
DELIVERY PRICE 6.449 6.018 4.718 4.788 4.881 4.881 4.779 4.640 4.586 4.508 4.516
- -----------------------------------------------------------------------------------------------------------------------------------
(5) Standard Service
Backstop 3.366 2.800 3.200 3.500 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(5a) Standard Service
Adjustment 0.207 0.207 0.207 tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- ----- -----
TOTAL STANDARD SERVICE 3.366 2.800 3.200 3.707 3.707 3.707 3.800 3.800 4.200 4.700 5.100
(6) TOTAL AVERAGE PRICE
(EXCL. DISCOUNTS 9.815 8.818 7.918 8.495 8.588 8.588 8.579 8.440 8.786 9.208 9.616
(7) Statutory Benchmark,
Adjusted for Inflation 9.815 9.815 9.815 9.815 10.174 10.495 10.726 10.962 11.203 11.449
(8) Savings Off Inflation-
Adjusted Price 10.16% 19.33% 13.45% 12.50% 15.59% 18.26% 21.31% 19.85% 17.81% 16.01%
- -----------------------------------------------------------------------------------------------------------------------------------
(2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated NEPOOL
transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3
2002 & beyond: inflated by 2.2% per year
(3) 2001 & beyond: Workpaper TMB-4
(7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Exhibit TMB-1,
Page 2
<PAGE>
<CAPTION>
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System
MECO-3 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-8, Revised
Page 2 of 2
MASSACHUSETTS ELECTRIC COMPANY
Average (cent)/kWh
With Consolidation with Eastern Edison on January 1, 2001
1998 1999
-------------------------------------------
Benchmark
Rates
8/01/97 March 1 September 1 January 1 March 1 September 1 2000 2001 2002 2003 2004
------- ------- ----------- --------- ------- ----------- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(1) Distribution 2.270 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502 2.502
(1a) DSM 0.350 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250
(1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
TOTAL DISTRIBUTION 2.620 2.907 2.907 2.912 2.912 2.912 2.912 2.872 2.827 2.802 2.802
(2) Transmission 0.429 0.404 0.404 0.535 0.535 0.535 0.547 0.518 0.529 0.541 0.553
(2a) Transmission
Adjustment 0.106 0.106 0.106 tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- ----- -----
TOTAL TRANSMISSION 0.429 0.404 0.404 0.641 0.641 0.641 0.547 0.518 0.529 0.541 0.553
(3) Transition 3.400 2.707 1.407 1.246 1.339 1.339 1.320 1.250 1.230 1.110 1.050
(3a) Transition Adjustment (0.011) (0.011) (0.011) tbd tbd tbd tbd tbd
------ ------ ------ ----- ----- ----- ----- -----
TOTAL TRANSITION 3.400 2.707 1.407 1.235 1.328 1.328 1.320 1.250 1.230 1.110 1.050
(4) TOTAL AVERAGE RETAIL
DELIVERY PRICE 6.449 6.018 4.718 4.788 4.881 4.881 4.779 4.640 4.586 4.453 4.405
- -----------------------------------------------------------------------------------------------------------------------------------
(5) Standard Service
Backstop 3.366 2.800 3.200 3.500 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(5a) Standard Service
Adjustment 0.207 0.207 0.207 tbd tbd tbd tbd tbd
----- ----- ----- ----- ----- ----- ----- -----
TOTAL STANDARD SERVICE 3.366 2.800 3.200 3.707 3.707 3.707 3.800 3.800 4.200 4.700 5.100
(6) TOTAL AVERAGE PRICE
(EXCL. DISCOUNTS 9.815 8.818 7.918 8.495 8.588 8.588 8.579 8.440 8.786 9.153 9.505
(7) Statutory Benchmark,
Adjusted for Inflation 9.815 9.815 9.815 9.815 10.174 10.495 10.726 10.962 11.203 11.449
(8) Savings Off Inflation-
Adjusted Price 10.16% 19.33% 13.45% 12.50% 15.59% 18.26% 21.31% 19.85% 18.30% 16.98%
- -----------------------------------------------------------------------------------------------------------------------------------
(2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated NEPOOL
transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3
2002 & beyond: inflated by 2.2% per year
(3) 2001 & beyond: Workpaper TMB-4
(7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference Exhibit TMB-1,
Page 2
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-9
Eastern Edison Company
Total Company Rate Path
Assuming Rate Consolidation on January 1, 2001
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System
EEC-2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-9, Revised
Page 1 of 2
EASTERN EDISON COMPANY
Average (cent)/kWh
With Consolidation with Massachusetts Electric on January 1, 2001
1998 1999
----------------- -----------------------
Benchmark
Rates Sept- Jan- Sept-
8/01/97 March 1 ember 1 uary 1 April 1 ember 2000 2001 2002 2003 2004
------- ------- ------- ------ ------ ------ ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
(1) Distribution 2.743 2.743 2.743 2.743 2.743 2.743 2.838 2.838 2.900 2.964
(1a) DSM 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250
(1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050
------ ------ ------ ------ ------ ------ ------ ------ ------ -----
TOTAL DISTRIBUTION 0.000 3.148 3.148 3.153 3.153 3.153 3.153 3.208 3.163 3.200 3.264
(2) Transmission 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553
(2a) Transmission Adjustment tbd tbd tbd tbd tbd tbd tbd
---- ---- ---- ---- ---- ---- ---
TOTAL TRANSMISSION 0.000 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553
(3) Transition 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050
(3a) Transition Adjustment tbd tbd tbd tbd tbd tbd tbd
---- ---- ---- ---- ---- ---- ---
TOTAL TRANSITION 0.000 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050
(4) TOTAL AVERAGE RETAIL
DELIVERY PRICE 6.446 6.446 6.408 5.523 5.551 5.738 4.976 4.922 4.851 4.867
- ---------------------------------------------------------------------------------------------------------------------------------
(5) Standard Service Backstop 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(5a) Standard Service Adjustment n/a n/a tbd tbd tbd tbd tbd
---- ---- ---- ---- ---- ---- ---
TOTAL STANDARD SERVICE 0.000 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(6) TOTAL AVERAGE PRICE (EXCL.
DISCOUNTS) 10.471 9.246 9.246 9.508 9.023 9.051 9.538 8.776 9.122 9.551 9.967
(7) Statutory Benchmark,
Adjusted for Inflation 10.471 10.471 10.471 10.471 10.860 11.203 11.449 11.701 11.958 12.221
(8) Savings Off Inflation-
Adjusted Price 11.70% 11.70% 9.20% 13.83% 16.66% 14.86% 23.35% 22.04% 20.13% 18.44%
- ---------------------------------------------------------------------------------------------------------------------------------
(2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated
NEPOOL transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3
2002 & beyond: inflated by 2.2% per year
(3) 2001 & beyond: Workpaper TMB-4
(7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference
Exhibit TMB-2, Page 2
<PAGE>
S:\RADATA1\EASTED\2001\Path-01a.wk4 New England Electric System
EEC-3 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Exhibit TMB-9, Revised
Page 2 of 2
EASTERN EDISON COMPANY
Average (cent)/kWh
With Consolidation with Massachusetts Electric on January 1, 2001
1998 1999
----------------- -----------------------
Benchmark
Rates Sept- Jan- Sept-
8/01/97 March 1 ember 1 uary 1 April 1 ember 2000 2001 2002 2003 2004
------- ------- ------- ------ ------ ------ ---- ---- ---- ---- ----
(1) Distribution 2.743 2.743 2.743 2.743 2.743 2.743 2.838 2.838 2.838 2.838
(1a) DSM 0.330 0.330 0.310 0.310 0.310 0.285 0.270 0.250 0.250 0.250
(1b) Renewables 0.075 0.075 0.100 0.100 0.100 0.125 0.100 0.075 0.050 0.050
------ ------ ------ ------ ------ ------ ------ ------ ------ -----
TOTAL DISTRIBUTION 0.000 3.148 3.148 3.153 3.153 3.153 3.153 3.208 3.163 3.138 3.138
(2) Transmission 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553
(2a) Transmission Adjustment tbd tbd tbd tbd tbd tbd tbd
---- ---- ---- ---- ---- ---- ---
TOTAL TRANSMISSION 0.000 0.258 0.258 0.215 0.270 0.298 0.285 0.518 0.529 0.541 0.553
(3) Transition 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050
(3a) Transition Adjustment tbd tbd tbd tbd tbd tbd tbd
---- ---- ---- ---- ---- ---- ---
TOTAL TRANSITION 0.000 3.040 3.040 3.040 2.100 2.100 2.300 1.250 1.230 1.110 1.050
(4) TOTAL AVERAGE RETAIL
DELIVERY PRICE 6.446 6.446 6.408 5.523 5.551 5.738 4.976 4.922 4.789 4.741
- ---------------------------------------------------------------------------------------------------------------------------------
(5) Standard Service Backstop 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(5a) Standard Service Adjustment n/a n/a tbd tbd tbd tbd tbd
---- ---- ---- ---- ---- ---- ---
TOTAL STANDARD SERVICE 0.000 2.800 2.800 3.100 3.500 3.500 3.800 3.800 4.200 4.700 5.100
(6) TOTAL AVERAGE PRICE (EXCL.
DISCOUNTS) 10.471 9.246 9.246 9.508 9.023 9.051 9.538 8.776 9.122 9.489 9.841
(7) Statutory Benchmark,
Adjusted for Inflation 10.471 10.471 10.471 10.471 10.860 11.203 11.449 11.701 11.958 12.221
(8) Savings Off Inflation-
Adjusted Price 11.70% 11.70% 9.20% 13.83% 16.66% 14.86% 23.35% 22.04% 20.65% 19.47%
- ---------------------------------------------------------------------------------------------------------------------------------
(2) 2001: 1999 Combined Company transmission costs per FERC 205 Filing, Exhibit__(PAV-4), Statement BG plus estimated
NEPOOL transmission costs / combined kWh sales inflated at 2.2% for 2 years; see Workpaper TMB-3
2002 & beyond: inflated by 2.2% per year
(3) 2001 & beyond: Workpaper TMB-4
(7) Assumed Inflation Rate for Statutory Benchmark Through 2000: All Urban Consumer Price Index (CPI-U); reference
Exhibit TMB-2, Page 2
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-10
Eastern Edison Company
Typical Bills
January 1, 2001 Assuming No Merger
vs.
January 1, 2001 Combined Rates
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: R-1 TO R-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 1 of 82
Impact on R-1 to R-1 Rate Customers
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 $2.38 $0.38 $2.00 $6.66 $0.38 $6.28 $4.28 179.8%
50 $6.51 $1.90 $4.61 $10.06 $1.90 $8.16 $3.55 54.5%
100 $11.66 $3.80 $7.86 $14.30 $3.80 $10.50 $2.64 22.6%
250 $27.14 $9.50 $17.64 $27.04 $9.50 $17.54 ($0.10) -0.4%
500 $52.93 $19.00 $33.93 $48.28 $19.00 $29.28 ($4.65) -8.8%
750 $78.72 $28.50 $50.22 $69.51 $28.50 $41.01 ($9.21) -11.7%
1,000 $104.51 $38.00 $66.51 $90.74 $38.00 $52.74 ($13.77) -13.2%
1,500 $156.10 $57.00 $99.10 $133.21 $57.00 $76.21 ($22.89) -14.7%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates R-1 to R-1 Year 2001 Consolidated Rates R-1 to R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $1.34 Customer Charge $5.81
Distribution Charge KWh x $0.03556 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: R-2 TO R-2 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 2 of 82
Impact on R-2 to R-2 Rate Customers
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 $1.61 $0.38 $1.23 $4.42 $0.38 $4.04 $2.81 174.5%
50 $4.55 $1.90 $2.65 $7.00 $1.90 $5.10 $2.45 53.8%
100 $8.21 $3.80 $4.41 $10.22 $3.80 $6.42 $2.01 24.5%
250 $19.23 $9.50 $9.73 $19.91 $9.50 $10.41 $0.68 3.5%
500 $37.58 $19.00 $18.58 $36.04 $19.00 $17.04 ($1.54) -4.1%
600 $44.91 $22.80 $22.11 $42.49 $22.80 $19.69 ($2.42) -5.4%
750 $55.92 $28.50 $27.42 $52.18 $28.50 $23.68 ($3.74) -6.7%
1,000 $74.27 $38.00 $36.27 $68.31 $38.00 $30.31 ($5.96) -8.0%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates R-2 to R-2 Year 2001 Consolidated Rates R-2 to R-2
<S> <C> <C> <C> <C> <C>
Customer Charge $0.87 Customer Charge $3.77
Distribution Charge KWh x $0.00579 Distribution Charge KWh x $0.00463
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: R-3 TO R-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 3 of 82
Impact on R-3 to R-1 Rate Customers
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 $6.39 $1.90 $4.49 $10.06 $1.90 $8.16 $3.67 57.4%
100 $10.97 $3.80 $7.17 $14.30 $3.80 $10.50 $3.33 30.4%
250 $24.76 $9.50 $15.26 $27.04 $9.50 $17.54 $2.28 9.2%
500 $47.71 $19.00 $28.71 $48.28 $19.00 $29.28 $0.57 1.2%
750 $70.67 $28.50 $42.17 $69.51 $28.50 $41.01 ($1.16) -1.6%
1,000 $93.62 $38.00 $55.62 $90.74 $38.00 $52.74 ($2.88) -3.1%
1,500 $139.54 $57.00 $82.54 $133.21 $57.00 $76.21 ($6.33) -4.5%
2,000 $185.45 $76.00 $109.45 $175.67 $76.00 $99.67 ($9.78) -5.3%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates R-3 to R-1 Year 2001 Consolidated Rates R-3 to R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $1.79 Customer Charge $5.81
Distribution Charge KWh x $0.02422 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: R-4 TO R-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 4 of 82
Impact on R-4 to R-1 Rate Customers
KWh Split: - On-Peak 20%
- Off-Peak 80%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
500 $53.08 $19.00 $34.08 $48.28 $19.00 $29.28 ($4.80) -9.0%
750 $75.65 $28.50 $47.15 $69.52 $28.50 $41.02 ($6.13) -8.1%
1,000 $98.22 $38.00 $60.22 $90.74 $38.00 $52.74 ($7.48) -7.6%
1,250 $120.80 $47.50 $73.30 $111.99 $47.50 $64.49 ($8.81) -7.3%
1,500 $143.36 $57.00 $86.36 $133.21 $57.00 $76.21 ($10.15) -7.1%
2,000 $188.50 $76.00 $112.50 $175.67 $76.00 $99.67 ($12.83) -6.8%
2,500 $233.65 $95.00 $138.65 $218.14 $95.00 $123.14 ($15.51) -6.6%
3,000 $278.78 $114.00 $164.78 $260.60 $114.00 $146.60 ($18.18) -6.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates R-4 to R-1 Year 2001 Consolidated Rates R-4 to R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.93 Customer Charge $5.81
Distribution Charge KWh x $0.01690 Distribution Charge KWh x $0.02502
Access Charge: On Peak KWh x $0.10899 Transition Charge KWh x $0.01250
Access Charge: Off Peak KWh x $0.00872 Transmission Charge KWh x $0.00571
Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-1 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:37 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 5 of 82
Impact on G-1 to G-1 Rate Customers
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 $6.86 $1.90 $4.96 $13.24 $1.90 $11.34 $6.38 93.0%
100 $12.36 $3.80 $8.56 $18.15 $3.80 $14.35 $5.79 46.8%
250 $28.90 $9.50 $19.40 $32.90 $9.50 $23.40 $4.00 13.8%
500 $56.45 $19.00 $37.45 $57.48 $19.00 $38.48 $1.03 1.8%
1,000 $111.55 $38.00 $73.55 $106.63 $38.00 $68.63 ($4.92) -4.4%
2,500 $276.87 $95.00 $181.87 $254.10 $95.00 $159.10 ($22.77) -8.2%
5,000 $552.39 $190.00 $362.39 $499.87 $190.00 $309.87 ($52.52) -9.5%
7,500 $827.92 $285.00 $542.92 $745.65 $285.00 $460.65 ($82.27) -9.9%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-1 to G-1 Year 2001 Consolidated Rates G-1 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $1.34 Customer Charge $8.32
Distribution Charge KWh x $0.04260 Distribution Charge KWh x $0.03843
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 6 of 82
Impact on G-2 to G-1 Rate Customers
Hours Use: 100
- ----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 1,000 $156.70 $38.00 $118.70 $106.39 $38.00 $68.39 ($50.31) -32.1%
12 1,200 $186.60 $45.60 $141.00 $126.00 $45.60 $80.40 ($60.60) -32.5%
15 1,500 $231.44 $57.00 $174.44 $155.43 $57.00 $98.43 ($76.01) -32.8%
17 1,700 $261.33 $64.60 $196.73 $175.04 $64.60 $110.44 ($86.29) -33.0%
20 2,000 $306.16 $76.00 $230.16 $204.46 $76.00 $128.46 ($101.70) -33.2%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $8.32
Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544
Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 7 of 82
Impact on G-2 to G-1 Rate Customers
Hours Use: 150
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 1,500 $186.94 $57.00 $129.94 $155.43 $57.00 $98.43 ($31.51) -16.9%
12 1,800 $222.86 $68.40 $154.46 $184.85 $68.40 $116.45 ($38.01) -17.1%
15 2,250 $276.78 $85.50 $191.28 $228.98 $85.50 $143.48 ($47.80) -17.3%
17 2,550 $312.72 $96.90 $215.82 $258.40 $96.90 $161.50 ($54.32) -17.4%
20 3,000 $366.62 $114.00 $252.62 $302.53 $114.00 $188.53 ($64.09) -17.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $8.32
Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544
Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 8 of 82
Impact on G-2 to G-1 Rate Customers
Hours Use: 200
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 2,000 $217.16 $76.00 $141.16 $204.46 $76.00 $128.46 ($12.70) -5.8%
12 2,400 $259.14 $91.20 $167.94 $243.69 $91.20 $152.49 ($15.45) -6.0%
15 3,000 $322.12 $114.00 $208.12 $302.53 $114.00 $188.53 ($19.59) -6.1%
17 3,400 $364.10 $129.20 $234.90 $341.76 $129.20 $212.56 ($22.34) -6.1%
20 4,000 $427.08 $152.00 $275.08 $400.60 $152.00 $248.60 ($26.48) -6.2%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $8.32
Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544
Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 9 of 82
Impact on G-2 to G-1 Rate Customers
Hours Use: 250
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 2,500 $247.40 $95.00 $152.40 $253.50 $95.00 $158.50 $6.10 2.5%
12 3,000 $295.42 $114.00 $181.42 $302.53 $114.00 $188.53 $7.11 2.4%
15 3,750 $367.48 $142.50 $224.98 $376.08 $142.50 $233.58 $8.60 2.3%
17 4,250 $415.50 $161.50 $254.00 $425.12 $161.50 $263.62 $9.62 2.3%
20 5,000 $487.54 $190.00 $297.54 $498.67 $190.00 $308.67 $11.13 2.3%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $8.32
Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544
Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 10 of 82
Impact on G-2 to G-1 Rate Customers
Hours Use: 300
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 3,000 $277.62 $114.00 $163.62 $302.53 $114.00 $188.53 $24.91 9.0%
12 3,600 $331.70 $136.80 $194.90 $361.37 $136.80 $224.57 $29.67 8.9%
15 4,500 $412.82 $171.00 $241.82 $449.64 $171.00 $278.64 $36.82 8.9%
17 5,100 $466.89 $193.80 $273.09 $508.48 $193.80 $314.68 $41.59 8.9%
20 6,000 $548.00 $228.00 $320.00 $596.74 $228.00 $368.74 $48.74 8.9%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $8.32
Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00544
Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 11 of 82
Impact on G-2 to G-1 Rate Customers
Hours Use: 350
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 3,500 $308.07 $133.00 $175.07 $352.41 $133.00 $219.41 $44.34 14.4%
12 4,200 $368.23 $159.60 $208.63 $421.22 $159.60 $261.62 $52.99 14.4%
15 5,250 $458.48 $199.50 $258.98 $524.45 $199.50 $324.95 $65.97 14.4%
17 5,950 $518.63 $226.10 $292.53 $593.26 $226.10 $367.16 $74.63 14.4%
20 7,000 $608.88 $266.00 $342.88 $696.49 $266.00 $430.49 $87.61 14.4%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-1 Year 2001 Consolidated Rates G-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $8.32
Distribution Demand Charge KW x $2.83 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.07 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.01393 Transmission Charge KWh x $0.00568
Transition Charge KWh x $0.00198 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00291 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 12 of 82
Impact on G-2 to G-2 Rate Customers
Hours Use: 200
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 10,000 $1,056.84 $380.00 $676.84 $916.13 $380.00 $536.13 ($140.71) -13.3%
100 20,000 $2,106.44 $760.00 $1,346.44 $1,817.03 $760.00 $1,057.03 ($289.41) -13.7%
125 25,000 $2,631.24 $950.00 $1,681.24 $2,267.48 $950.00 $1,317.48 ($363.76) -13.8%
150 30,000 $3,156.04 $1,140.00 $2,016.04 $2,717.93 $1,140.00 $1,577.93 ($438.11) -13.9%
175 35,000 $3,680.84 $1,330.00 $2,350.84 $3,168.38 $1,330.00 $1,838.38 ($512.46) -13.9%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $15.23
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KWh x $5.92
Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250
Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 13 of 82
Impact on G-2 to G-2 Rate Customers
Hours Use: 250
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 12,500 $1,208.00 $475.00 $733.00 $1,067.36 $475.00 $592.36 ($140.64) -11.6%
100 25,000 $2,408.74 $950.00 $1,458.74 $2,119.48 $950.00 $1,169.48 ($289.26) -12.0%
125 31,250 $3,009.12 $1,187.50 $1,821.62 $2,645.54 $1,187.50 $1,458.04 ($363.58) -12.1%
150 37,500 $3,609.50 $1,425.00 $2,184.50 $3,171.61 $1,425.00 $1,746.61 ($437.89) -12.1%
175 43,750 $4,209.88 $1,662.50 $2,547.38 $3,697.67 $1,662.50 $2,035.17 ($512.21) -12.2%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $15.23
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250
Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 14 of 82
Impact on G-2 to G-2 Rate Customers
Hours Use: 300
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 15,000 $1,359.14 $570.00 $789.14 $1,218.58 $570.00 $648.58 ($140.56) -10.3%
100 30,000 $2,711.04 $1,140.00 $1,571.04 $2,421.93 $1,140.00 $1,281.93 ($289.11) -10.7%
125 37,500 $3,387.00 $1,425.00 $1,962.00 $3,023.61 $1,425.00 $1,598.61 ($363.39) -10.7%
150 45,000 $4,062.94 $1,710.00 $2,352.94 $3,625.28 $1,710.00 $1,915.28 ($437.66) -10.8%
175 52,500 $4,738.90 $1,995.00 $2,743.90 $4,226.96 $1,995.00 $2,231.96 ($511.94) -10.8%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $15.23
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250
Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 15 of 82
Impact on G-2 to G-2 Rate Customers
Hours Use: 350
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 17,500 $1,510.30 $665.00 $845.30 $1,369.81 $665.00 $704.81 ($140.49) -9.3%
100 35,000 $3,013.34 $1,330.00 $1,683.34 $2,724.38 $1,330.00 $1,394.38 ($288.96) -9.6%
125 43,750 $3,764.88 $1,662.50 $2,102.38 $3,401.67 $1,662.50 $1,739.17 ($363.21) -9.6%
150 52,500 $4,516.40 $1,995.00 $2,521.40 $4,078.96 $1,995.00 $2,083.96 ($437.44) -9.7%
175 61,250 $5,267.92 $2,327.50 $2,940.42 $4,756.24 $2,327.50 $2,428.74 ($511.68) -9.7%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $15.23
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250
Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 16 of 82
Impact on G-2 to G-2 Rate Customers
Hours Use: 400
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 20,000 $1,661.44 $760.00 $901.44 $1,521.03 $760.00 $761.03 ($140.41) -8.5%
100 40,000 $3,315.64 $1,520.00 $1,795.64 $3,026.83 $1,520.00 $1,506.83 ($288.81) -8.7%
125 50,000 $4,142.74 $1,900.00 $2,242.74 $3,779.73 $1,900.00 $1,879.73 ($363.01) -8.8%
150 60,000 $4,969.84 $2,280.00 $2,689.84 $4,532.63 $2,280.00 $2,252.63 ($437.21) -8.8%
175 70,000 $5,796.94 $2,660.00 $3,136.94 $5,285.53 $2,660.00 $2,625.53 ($511.41) -8.8%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $15.23
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250
Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00491
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-2 TO G-2 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 17 of 82
Impact on G-2 to G-2 Rate Customers
Hours Use: 450
- ---------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $1,813.95 $855.00 $958.95 $1,677.21 $855.00 $822.21 ($136.74) -7.5%
100 45,000 $3,620.64 $1,710.00 $1,910.64 $3,339.18 $1,710.00 $1,629.18 ($281.46) -7.8%
125 56,250 $4,524.00 $2,137.50 $2,386.50 $4,170.17 $2,137.50 $2,032.67 ($353.83) -7.8%
150 67,500 $5,427.35 $2,565.00 $2,862.35 $5,001.16 $2,565.00 $2,436.16 ($426.19) -7.9%
175 78,750 $6,330.70 $2,992.50 $3,338.20 $5,832.14 $2,992.50 $2,839.64 ($498.56) -7.9%
- ---------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-2 Year 2001 Consolidated Rates G-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $15.23
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.07 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.01393 Transition Charge KWh x $0.01250
Transition Charge KWh x $0.00198 Transmission Charge KWh x $0.00513
Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 18 of 82
Impact on G-2 to G-3 Rate Customers
Hours Use: 250
kWh Split: On Peak: 55%
Off Peak: 45%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 62,500 $6,011.00 $2,375.00 $3,636.00 $5,043.93 $2,375.00 $2,668.93 ($967.07) -16.1%
300 75,000 $7,211.74 $2,850.00 $4,361.74 $6,039.26 $2,850.00 $3,189.26 ($1,172.48) -16.3%
350 87,500 $8,412.50 $3,325.00 $5,087.50 $7,034.59 $3,325.00 $3,709.59 ($1,377.91) -16.4%
400 100,000 $9,613.24 $3,800.00 $5,813.24 $8,029.92 $3,800.00 $4,229.92 ($1,583.32) -16.5%
450 112,500 $10,814.00 $4,275.00 $6,539.00 $9,025.25 $4,275.00 $4,750.25 ($1,788.75) -16.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $67.27
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 19 of 82
Impact on G-2 to G-3 Rate Customers
Hours Use: 300
kWh Split: On Peak: 50%
Off Peak: 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 75,000 $6,766.74 $2,850.00 $3,916.74 $5,813.40 $2,850.00 $2,963.40 ($953.34) -14.1%
300 90,000 $8,118.64 $3,420.00 $4,698.64 $6,962.62 $3,420.00 $3,542.62 ($1,156.02) -14.2%
350 105,000 $9,470.54 $3,990.00 $5,480.54 $8,111.85 $3,990.00 $4,121.85 ($1,358.69) -14.3%
400 120,000 $10,822.44 $4,560.00 $6,262.44 $9,261.07 $4,560.00 $4,701.07 ($1,561.37) -14.4%
450 135,000 $12,174.34 $5,130.00 $7,044.34 $10,410.30 $5,130.00 $5,280.30 ($1,764.04) -14.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $67.27
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 20 of 82
Impact on G-2 to G-3 Rate Customers
Hours Use: 350
kWh Split: On Peak: 50%
Off Peak: 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 87,500 $7,522.50 $3,325.00 $4,197.50 $6,619.83 $3,325.00 $3,294.83 ($902.67) -12.0%
300 105,000 $9,025.54 $3,990.00 $5,035.54 $7,930.35 $3,990.00 $3,940.35 ($1,095.19) -12.1%
350 122,500 $10,528.60 $4,655.00 $5,873.60 $9,240.86 $4,655.00 $4,585.86 ($1,287.74) -12.2%
400 140,000 $12,031.64 $5,320.00 $6,711.64 $10,551.37 $5,320.00 $5,231.37 ($1,480.27) -12.3%
450 157,500 $13,534.70 $5,985.00 $7,549.70 $11,861.88 $5,985.00 $5,876.88 ($1,672.82) -12.4%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $67.27
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 21 of 82
Impact on G-2 to G-3 Rate Customers
Hours Use: 400
kWh Split: On Peak: 45%
Off Peak: 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 100,000 $8,278.24 $3,800.00 $4,478.24 $7,367.12 $3,800.00 $3,567.12 ($911.12) -11.0%
300 120,000 $9,932.44 $4,560.00 $5,372.44 $8,827.09 $4,560.00 $4,267.09 ($1,105.35) -11.1%
350 140,000 $11,586.64 $5,320.00 $6,266.64 $10,287.06 $5,320.00 $4,967.06 ($1,299.58) -11.2%
400 160,000 $13,240.84 $6,080.00 $7,160.84 $11,747.03 $6,080.00 $5,667.03 ($1,493.81) -11.3%
450 180,000 $14,895.04 $6,840.00 $8,055.04 $13,207.00 $6,840.00 $6,367.00 ($1,688.04) -11.3%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $67.27
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 22 of 82
Impact on G-2 to G-3 Rate Customers
Hours Use: 450
kWh Split: On Peak: 45%
Off Peak: 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 112,500 $9,034.00 $4,275.00 $4,759.00 $8,166.16 $4,275.00 $3,891.16 ($867.84) -9.6%
300 135,000 $10,839.34 $5,130.00 $5,709.34 $9,785.94 $5,130.00 $4,655.94 ($1,053.40) -9.7%
350 157,500 $12,644.70 $5,985.00 $6,659.70 $11,405.72 $5,985.00 $5,420.72 ($1,238.98) -9.8%
400 180,000 $14,450.04 $6,840.00 $7,610.04 $13,025.50 $6,840.00 $6,185.50 ($1,424.54) -9.9%
450 202,500 $16,255.40 $7,695.00 $8,560.40 $14,645.28 $7,695.00 $6,950.28 ($1,610.12) -9.9%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $67.27
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00285 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-2 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 23 of 82
Impact on G-2 to G-3 Rate Customers
Hours Use: 500
kWh Split: On Peak: 45%
Off Peak: 55%
- ----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 3,500 $308.07 $133.00 $175.07 $352.41 $133.00 $219.41 $44.34 14.4%
250 125,000 $9,797.24 $4,750.00 $5,047.24 $8,990.21 $4,750.00 $4,240.21 ($807.03) -8.2%
300 150,000 $11,755.24 $5,700.00 $6,055.24 $10,774.80 $5,700.00 $5,074.80 ($980.44) -8.3%
350 175,000 $13,713.24 $6,650.00 $7,063.24 $12,559.38 $6,650.00 $5,909.38 ($1,153.86) -8.4%
400 200,000 $15,671.24 $7,600.00 $8,071.24 $14,343.97 $7,600.00 $6,743.97 ($1,327.27) -8.5%
450 225,000 $17,629.24 $8,550.00 $9,079.24 $16,128.56 $8,550.00 $7,578.56 ($1,500.68) -8.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-2 to G-3 Year 2001 Consolidated Rates G-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $7.24 Customer Charge $67.27
Distribution Demand Charge KW x $2.83 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.07 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01393 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge KWh x $0.00198 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00460
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 24 of 82
Impact on G-4 to G-3 Rate Customers
Hours Use: 250
kWh Split: On Peak: 35% 55%
Off Peak: 65% 45%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 150,000 $14,427.12 $5,700.00 $8,727.12 $12,011.25 $5,700.00 $6,311.25 ($2,415.87) -16.7%
800 200,000 $19,230.22 $7,600.00 $11,630.22 $15,992.57 $7,600.00 $8,392.57 ($3,237.65) -16.8%
1000 250,000 $24,033.32 $9,500.00 $14,533.32 $19,973.90 $9,500.00 $10,473.90 ($4,059.42) -16.9%
1500 375,000 $36,041.07 $14,250.00 $21,791.07 $29,927.21 $14,250.00 $15,677.21 ($6,113.86) -17.0%
3000 750,000 $72,064.32 $28,500.00 $43,564.32 $59,787.15 $28,500.00 $31,287.15 ($12,277.17) -17.0%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $17.82 Customer Charge $67.27
Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 25 of 82
Impact on G-4 to G-3 Rate Customers
Hours Use: 300
kWh Split: On Peak: 30% 50%
Off Peak: 70% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 180,000 $16,191.90 $6,840.00 $9,351.90 $13,857.97 $6,840.00 $7,017.97 ($2,333.93) -14.4%
800 240,000 $21,583.26 $9,120.00 $12,463.26 $18,454.87 $9,120.00 $9,334.87 ($3,128.39) -14.5%
1000 300,000 $26,974.62 $11,400.00 $15,574.62 $23,051.77 $11,400.00 $11,651.77 ($3,922.85) -14.5%
1500 450,000 $40,453.02 $17,100.00 $23,353.02 $34,544.02 $17,100.00 $17,444.02 ($5,909.00) -14.6%
3000 900,000 $80,888.22 $34,200.00 $46,688.22 $69,020.77 $34,200.00 $34,820.77 ($11,867.45) -14.7%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $17.82 Customer Charge $67.27
Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 26 of 82
Impact on G-4 to G-3 Rate Customers
Hours Use: 150 350
kWh Split: On Peak: 30% 50%
Off Peak: 70% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 210,000 $18,002.58 $7,980.00 $10,022.58 $15,793.42 $7,980.00 $7,813.42 ($2,209.16) -12.3%
800 280,000 $23,997.50 $10,640.00 $13,357.50 $21,035.47 $10,640.00 $10,395.47 ($2,962.03) -12.3%
1000 350,000 $29,992.42 $13,300.00 $16,692.42 $26,277.52 $13,300.00 $12,977.52 ($3,714.90) -12.4%
1500 525,000 $44,979.72 $19,950.00 $25,029.72 $39,382.65 $19,950.00 $19,432.65 ($5,597.07) -12.4%
3000 1,050,000 $89,941.62 $39,900.00 $50,041.62 $78,698.02 $39,900.00 $38,798.02 ($11,243.60) -12.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $17.82 Customer Charge $67.27
Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 27 of 82
Impact on G-4 to G-3 Rate Customers
Hours Use: 400
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 240,000 $19,739.82 $9,120.00 $10,619.82 $17,586.91 $9,120.00 $8,466.91 ($2,152.91) -10.9%
800 320,000 $26,313.82 $12,160.00 $14,153.82 $23,426.79 $12,160.00 $11,266.79 ($2,887.03) -11.0%
1000 400,000 $32,887.82 $15,200.00 $17,687.82 $29,266.67 $15,200.00 $14,066.67 ($3,621.15) -11.0%
1500 600,000 $49,322.82 $22,800.00 $26,522.82 $43,866.37 $22,800.00 $21,066.37 ($5,456.45) -11.1%
3000 1,200,000 $98,627.82 $45,600.00 $53,027.82 $87,665.47 $45,600.00 $42,065.47 ($10,962.35) -11.1%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $17.82 Customer Charge $67.27
Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 28 of 82
Impact on G-4 to G-3 Rate Customers
Hours Use: 450
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 270,000 $21,541.32 $10,260.00 $11,281.32 $19,504.62 $10,260.00 $9,244.62 ($2,036.70) -9.5%
800 360,000 $28,715.82 $13,680.00 $15,035.82 $25,983.73 $13,680.00 $12,303.73 ($2,732.09) -9.5%
1000 450,000 $35,890.32 $17,100.00 $18,790.32 $32,462.85 $17,100.00 $15,362.85 ($3,427.47) -9.5%
1500 675,000 $53,826.57 $25,650.00 $28,176.57 $48,660.63 $25,650.00 $23,010.63 ($5,165.94) -9.6%
3000 1,350,000 $107,635.32 $51,300.00 $56,335.32 $97,254.00 $51,300.00 $45,954.00 ($10,381.32) -9.6%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $17.82 Customer Charge $67.27
Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-4 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 29 of 82
Impact on G-4 to G-3 Rate Customers
Hours Use: 500
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 300,000 $23,360.82 $11,400.00 $11,960.82 $21,482.32 $11,400.00 $10,082.32 ($1,878.50) -8.0%
800 400,000 $31,141.82 $15,200.00 $15,941.82 $28,620.67 $15,200.00 $13,420.67 ($2,521.15) -8.1%
1,000 500,000 $38,922.82 $19,000.00 $19,922.82 $35,759.02 $19,000.00 $16,759.02 ($3,163.80) -8.1%
1,500 750,000 $58,375.32 $28,500.00 $29,875.32 $53,604.90 $28,500.00 $25,104.90 ($4,770.42) -8.2%
3,000 1,500,000 $116,732.82 $57,000.00 $59,732.82 $107,142.52 $57,000.00 $50,142.52 ($9,590.30) -8.2%
- --------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-4 to G-3 Year 2001 Consolidated Rates G-4 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $17.82 Customer Charge $67.27
Distribution Demand Charge KW x $2.81 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.04 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00657 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01352 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00740 Transmission Charge KWh x $0.00460
Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 30 of 82
Impact on G-5 to G-3 Rate Customers
Hours Use: 250
kWh Split: On Peak: 35% 55%
Off Peak: 65% 45%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 37,500 $3,620.70 $1,425.00 $2,195.70 $2,955.23 $1,425.00 $1,530.23 ($665.47) -18.4%
200 50,000 $4,812.97 $1,900.00 $2,912.97 $3,918.11 $1,900.00 $2,018.11 ($894.86) -18.6%
300 75,000 $7,197.53 $2,850.00 $4,347.53 $5,843.86 $2,850.00 $2,993.86 ($1,353.67) -18.8%
400 100,000 $9,582.07 $3,800.00 $5,782.07 $7,769.62 $3,800.00 $3,969.62 ($1,812.45) -18.9%
450 112,500 $10,774.35 $4,275.00 $6,499.35 $8,732.50 $4,275.00 $4,457.50 ($2,041.85) -19.0%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 31 of 82
Impact on G-5 to G-3 Rate Customers
Hours Use: 300
kWh Split: On Peak: 30% 50%
Off Peak: 70% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 45,000 $4,113.64 $1,710.00 $2,403.64 $3,412.30 $1,710.00 $1,702.30 ($701.34) -17.0%
200 60,000 $5,470.23 $2,280.00 $3,190.23 $4,527.53 $2,280.00 $2,247.53 ($942.70) -17.2%
300 90,000 $8,183.41 $3,420.00 $4,763.41 $6,757.99 $3,420.00 $3,337.99 ($1,425.42) -17.4%
400 120,000 $10,896.59 $4,560.00 $6,336.59 $8,988.46 $4,560.00 $4,428.46 ($1,908.13) -17.5%
450 135,000 $12,253.18 $5,130.00 $7,123.18 $10,103.69 $5,130.00 $4,973.69 ($2,149.49) -17.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 32 of 82
Impact on G-5 to G-3 Rate Customers
Hours Use: 350
kWh Split: On Peak: 30% 50%
Off Peak: 70% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 52,500 $4,616.95 $1,995.00 $2,621.95 $3,891.32 $1,995.00 $1,896.32 ($725.63) -15.7%
200 70,000 $6,141.29 $2,660.00 $3,481.29 $5,166.23 $2,660.00 $2,506.23 ($975.06) -15.9%
300 105,000 $9,190.00 $3,990.00 $5,200.00 $7,716.04 $3,990.00 $3,726.04 ($1,473.96) -16.0%
400 140,000 $12,238.71 $5,320.00 $6,918.71 $10,265.86 $5,320.00 $4,945.86 ($1,972.85) -16.1%
450 157,500 $13,763.08 $5,985.00 $7,778.08 $11,540.76 $5,985.00 $5,555.76 ($2,222.32) -16.1%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 33 of 82
Impact on G-5 to G-3 Rate Customers
Hours Use: 400
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 60,000 $5,103.67 $2,280.00 $2,823.67 $4,335.21 $2,280.00 $2,055.21 ($768.46) -15.1%
200 80,000 $6,790.27 $3,040.00 $3,750.27 $5,758.08 $3,040.00 $2,718.08 ($1,032.19) -15.2%
300 120,000 $10,163.47 $4,560.00 $5,603.47 $8,603.82 $4,560.00 $4,043.82 ($1,559.65) -15.3%
400 160,000 $13,536.67 $6,080.00 $7,456.67 $11,449.56 $6,080.00 $5,369.56 ($2,087.11) -15.4%
450 180,000 $15,223.27 $6,840.00 $8,383.27 $12,872.43 $6,840.00 $6,032.43 ($2,350.84) -15.4%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 34 of 82
Impact on G-5 to G-3 Rate Customers
Hours Use: 450
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 67,500 $5,604.90 $2,565.00 $3,039.90 $4,809.84 $2,565.00 $2,244.84 ($795.06) -14.2%
200 90,000 $7,458.57 $3,420.00 $4,038.57 $6,390.92 $3,420.00 $2,970.92 ($1,067.65) -14.3%
300 135,000 $11,165.93 $5,130.00 $6,035.93 $9,553.08 $5,130.00 $4,423.08 ($1,612.85) -14.4%
400 180,000 $14,873.27 $6,840.00 $8,033.27 $12,715.25 $6,840.00 $5,875.25 ($2,158.02) -14.5%
450 202,500 $16,726.95 $7,695.00 $9,031.95 $14,296.33 $7,695.00 $6,601.33 ($2,430.62) -14.5%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-5 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 35 of 82
Impact on G-5 to G-3 Rate Customers
Hours Use: 500
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 300,000 $23,360.82 $11,400.00 $11,960.82 $21,482.32 $11,400.00 $10,082.32 ($1,878.50) -8.0%
150 75,000 $6,110.63 $2,850.00 $3,260.63 $5,299.32 $2,850.00 $2,449.32 ($811.31) -13.3%
200 100,000 $8,132.87 $3,800.00 $4,332.87 $7,043.56 $3,800.00 $3,243.56 ($1,089.31) -13.4%
300 150,000 $12,177.37 $5,700.00 $6,477.37 $10,532.05 $5,700.00 $4,832.05 ($1,645.32) -13.5%
400 200,000 $16,221.87 $7,600.00 $8,621.87 $14,020.53 $7,600.00 $6,420.53 ($2,201.34) -13.6%
450 225,000 $18,244.13 $8,550.00 $9,694.13 $15,764.77 $8,550.00 $7,214.77 ($2,479.36) -13.6%
- --------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-5 to G-3 Year 2001 Consolidated Rates G-5 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.01324 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01318 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00766 Transmission Charge KWh x $0.00460
Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 36 of 82
Impact on G-6 to G-3 Rate Customers
Hours Use: 250
kWh Split: On Peak: 35% 55%
Off Peak: 65% 45%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 150,000 $14,165.18 $5,700.00 $8,465.18 $11,621.13 $5,700.00 $5,921.13 ($2,544.05) -18.0%
800 200,000 $18,872.27 $7,600.00 $11,272.27 $15,472.64 $7,600.00 $7,872.64 ($3,399.63) -18.0%
1000 250,000 $23,579.39 $9,500.00 $14,079.39 $19,324.16 $9,500.00 $9,824.16 ($4,255.23) -18.0%
1500 375,000 $35,347.12 $14,250.00 $21,097.12 $28,952.94 $14,250.00 $14,702.94 ($6,394.18) -18.1%
3000 750,000 $70,650.38 $28,500.00 $42,150.38 $57,839.27 $28,500.00 $29,339.27 ($12,811.11) -18.1%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 37 of 82
Impact on G-6 to G-3 Rate Customers
Hours Use: 300
kWh Split: On Peak: 30% 50%
Off Peak: 70% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 180,000 $16,099.75 $6,840.00 $9,259.75 $13,449.39 $6,840.00 $6,609.39 ($2,650.36) -16.5%
800 240,000 $21,451.71 $9,120.00 $12,331.71 $17,910.32 $9,120.00 $8,790.32 ($3,541.39) -16.5%
1000 300,000 $26,803.67 $11,400.00 $15,403.67 $22,371.25 $11,400.00 $10,971.25 ($4,432.42) -16.5%
1500 450,000 $40,183.57 $17,100.00 $23,083.57 $33,523.58 $17,100.00 $16,423.58 ($6,659.99) -16.6%
3000 900,000 $80,323.27 $34,200.00 $46,123.27 $66,980.56 $34,200.00 $32,780.56 ($13,342.71) -16.6%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 38 of 82
Impact on G-6 to G-3 Rate Customers
Hours Use: 350
kWh Split: On Peak: 30% 50%
Off Peak: 70% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 210,000 $18,075.73 $7,980.00 $10,095.73 $15,365.49 $7,980.00 $7,385.49 ($2,710.24) -15.0%
800 280,000 $24,086.35 $10,640.00 $13,446.35 $20,465.12 $10,640.00 $9,825.12 ($3,621.23) -15.0%
1000 350,000 $30,096.97 $13,300.00 $16,796.97 $25,564.74 $13,300.00 $12,264.74 ($4,532.23) -15.1%
1500 525,000 $45,123.53 $19,950.00 $25,173.53 $38,313.82 $19,950.00 $18,363.82 ($6,809.71) -15.1%
3000 1,050,000 $90,203.17 $39,900.00 $50,303.17 $76,561.04 $39,900.00 $36,661.04 ($13,642.13) -15.1%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 39 of 82
Impact on G-6 to G-3 Rate Customers
Hours Use: 400
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 240,000 $19,985.47 $9,120.00 $10,865.47 $17,141.04 $9,120.00 $8,021.04 ($2,844.43) -14.2%
800 320,000 $26,632.67 $12,160.00 $14,472.67 $22,832.52 $12,160.00 $10,672.52 ($3,800.15) -14.3%
1000 400,000 $33,279.87 $15,200.00 $18,079.87 $28,524.00 $15,200.00 $13,324.00 ($4,755.87) -14.3%
1500 600,000 $49,897.87 $22,800.00 $27,097.87 $42,752.71 $22,800.00 $19,952.71 ($7,145.16) -14.3%
3000 1,200,000 $99,751.87 $45,600.00 $54,151.87 $85,438.82 $45,600.00 $39,838.82 ($14,313.05) -14.3%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 40 of 82
Impact on G-6 to G-3 Rate Customers
Hours Use: 450
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- ----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 270,000 $21,953.18 $10,260.00 $11,693.18 $19,039.57 $10,260.00 $8,779.57 ($2,913.61) -13.3%
800 360,000 $29,256.27 $13,680.00 $15,576.27 $25,363.89 $13,680.00 $11,683.89 ($3,892.38) -13.3%
1000 450,000 $36,559.38 $17,100.00 $19,459.38 $31,688.22 $17,100.00 $14,588.22 ($4,871.16) -13.3%
1500 675,000 $54,817.12 $25,650.00 $29,167.12 $47,499.03 $25,650.00 $21,849.03 ($7,318.09) -13.4%
3000 1,350,000 $109,590.38 $51,300.00 $58,290.38 $94,931.46 $51,300.00 $43,631.46 ($14,658.92) -13.4%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 41 of 82
Impact on G-6 to G-3 Rate Customers
Hours Use: 500
kWh Split: On Peak: 25% 45%
Off Peak: 75% 55%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 300,000 $23,938.87 $11,400.00 $12,538.87 $20,997.50 $11,400.00 $9,597.50 ($2,941.37) -12.3%
800 400,000 $31,903.87 $15,200.00 $16,703.87 $27,974.46 $15,200.00 $12,774.46 ($3,929.41) -12.3%
1,000 500,000 $39,868.87 $19,000.00 $20,868.87 $34,951.43 $19,000.00 $15,951.43 ($4,917.44) -12.3%
1,500 750,000 $59,781.38 $28,500.00 $31,281.38 $52,393.85 $28,500.00 $23,893.85 ($7,387.53) -12.4%
3,000 1,500,000 $119,518.87 $57,000.00 $62,518.87 $104,721.09 $57,000.00 $47,721.09 ($14,797.78) -12.4%
- -------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: G-6 to G-3 Year 2001 Consolidated Rates G-6 to G-3
Customer Charge $43.87 Customer Charge $67.27
Distribution Demand Charge KW x $2.22 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $4.78 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00839 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01679 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.01127 Transmission Charge KWh x $0.00460
Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100 High Voltage Metering Discount KW x ($0.45)
High Voltage Delivery Discount -1%
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 42 of 82
Impact on T-2 to G-1 Rate Customers
Hours Use: 175
kWh Split: On Peak: 25%
Off Peak: 75%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 1,750 $205.78 $66.50 $139.28 $179.94 $66.50 $113.44 ($25.84) -12.6%
12 2,100 $244.37 $79.80 $164.57 $214.27 $79.80 $134.47 ($30.10) -12.3%
15 2,625 $302.25 $99.75 $202.50 $265.75 $99.75 $166.00 ($36.50) -12.1%
17 2,975 $340.83 $113.05 $227.78 $300.08 $113.05 $187.03 ($40.75) -12.0%
20 3,500 $398.73 $133.00 $265.73 $351.57 $133.00 $218.57 ($47.16) -11.8%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $8.32
Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843
Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544
Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270
Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100
Transmission Charge KWh x $0.00285
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 43 of 82
Impact on T-2 to G-1 Rate Customers
Hours Use: 200
kWh Split: On Peak: 20%
Off Peak: 80%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 2,000 $219.57 $76.00 $143.57 $204.46 $76.00 $128.46 ($15.11) -6.9%
12 2,400 $260.91 $91.20 $169.71 $243.69 $91.20 $152.49 ($17.22) -6.6%
15 3,000 $322.94 $114.00 $208.94 $302.53 $114.00 $188.53 ($20.41) -6.3%
17 3,400 $364.28 $129.20 $235.08 $341.76 $129.20 $212.56 ($22.52) -6.2%
20 4,000 $426.31 $152.00 $274.31 $400.60 $152.00 $248.60 ($25.71) -6.0%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $8.32
Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843
Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544
Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270
Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100
Transmission Charge KWh x $0.00285
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 44 of 82
Impact on T-2 to G-1 Rate Customers
Hours Use: 225
kWh Split: On Peak: 20%
Off Peak: 80%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 2,250 $233.90 $85.50 $148.40 $228.98 $85.50 $143.48 ($4.92) -2.1%
12 2,700 $278.12 $102.60 $175.52 $273.11 $102.60 $170.51 ($5.01) -1.8%
15 3,375 $344.44 $128.25 $216.19 $339.31 $128.25 $211.06 ($5.13) -1.5%
17 3,825 $388.65 $145.35 $243.30 $383.44 $145.35 $238.09 ($5.21) -1.3%
20 4,500 $454.97 $171.00 $283.97 $449.64 $171.00 $278.64 ($5.33) -1.2%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $8.32
Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843
Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544
Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270
Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100
Transmission Charge KWh x $0.00285
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 45 of 82
Impact on T-2 to G-1 Rate Customers
Hours Use: 250
kWh Split: On Peak: 15%
Off Peak: 85%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 2,500 $247.47 $95.00 $152.47 $253.50 $95.00 $158.50 $6.03 2.4%
12 3,000 $294.39 $114.00 $180.39 $302.53 $114.00 $188.53 $8.14 2.8%
15 3,750 $364.78 $142.50 $222.28 $376.08 $142.50 $233.58 $11.30 3.1%
17 4,250 $411.70 $161.50 $250.20 $425.12 $161.50 $263.62 $13.42 3.3%
20 5,000 $482.09 $190.00 $292.09 $498.67 $190.00 $308.67 $16.58 3.4%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $8.32
Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843
Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544
Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270
Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100
Transmission Charge KWh x $0.00285
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: G-6 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 46 of 82
Impact on T-2 to G-1 Rate Customers
Hours Use: 275
kWh Split: On Peak: 15%
Off Peak: 85%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 2,750 $261.73 $104.50 $157.23 $278.01 $104.50 $173.51 $16.28 6.2%
12 3,300 $311.49 $125.40 $186.09 $331.95 $125.40 $206.55 $20.46 6.6%
15 4,125 $386.16 $156.75 $229.41 $412.86 $156.75 $256.11 $26.70 6.9%
17 4,675 $435.93 $177.65 $258.28 $466.80 $177.65 $289.15 $30.87 7.1%
20 5,500 $510.60 $209.00 $301.60 $547.71 $209.00 $338.71 $37.11 7.3%
- ----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates T-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $8.32
Distribution Demand Charge KW x $2.92 Distribution KWh x $0.03843
Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00544
Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270
Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100
Transmission Charge KWh x $0.00285
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 47 of 82
Impact on T-2 to G-1 Rate Customers
Hours Use: 300
kWh Split: On Peak: 15%
Off Peak: 85%
- ---------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 3,000 $276.15 $114.00 $162.15 $303.25 $114.00 $189.25 $27.10 9.8%
12 3,600 $328.81 $136.80 $192.01 $362.24 $136.80 $225.44 $33.43 10.2%
15 4,500 $407.81 $171.00 $236.81 $450.72 $171.00 $279.72 $42.91 10.5%
17 5,100 $460.46 $193.80 $266.66 $509.70 $193.80 $315.90 $49.24 10.7%
20 6,000 $539.45 $228.00 $311.45 $598.18 $228.00 $370.18 $58.73 10.9%
- ---------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-1 Year 2001 Consolidated Rates: T-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $8.32
Distribution Demand Charge KW x $2.92 Distribution Charge KWh x $0.03843
Transition Demand Charge KW x $6.29 Transition Charge KWh x $0.01250
Distribution Charge KWh x $0.00231 Transmission Charge KWh x $0.00568
Transition Charge: On Peak KWh x $0.01536 Energy Conservation Charge KWh x $0.00270
Transition Charge: Off Peak KWh x $0.00923 Renewables Charge KWh x $0.00100
Transmission Charge KWh x $0.00291
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 48 of 82
Impact on T-2 to G-2 Rate Customers
Hours Use: 200
kWh Split: On Peak: 25%
Off Peak: 75%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 10,000 $1,049.57 $380.00 $669.57 $916.13 $380.00 $536.13 ($133.44) -12.7%
100 20,000 $2,086.29 $760.00 $1,326.29 $1,817.03 $760.00 $1,057.03 ($269.26) -12.9%
125 25,000 $2,604.65 $950.00 $1,654.65 $2,267.48 $950.00 $1,317.48 ($337.17) -12.9%
150 30,000 $3,123.02 $1,140.00 $1,938.02 $2,717.93 $1,140.00 $1,577.93 ($405.09) -13.0%
175 35,000 $3,641.38 $1,330.00 $2,311.38 $3,168.38 $1,330.00 $1,838.38 ($473.00) -13.0%
Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $15.23
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250
Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491
Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 49 of 82
Impact on T-2 to G-2 Rate Customers
Hours Use: 250
kWh Split: On Peak: 20%
Off Peak: 80%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 12,500 $1,189.80 $475.00 $714.80 $1,067.36 $475.00 $592.36 ($122.44) -10.3%
100 25,000 $2,366.74 $950.00 $1,416.74 $2,119.48 $950.00 $1,169.48 ($247.26) -10.4%
125 31,250 $2,955.22 $1,187.50 $1,767.72 $2,645.54 $1,187.50 $1,458.04 ($309.68) -10.5%
150 37,500 $3,543.70 $1,425.00 $2,118.70 $3,171.61 $1,425.00 $1,746.61 ($372.09) -10.5%
175 43,750 $4,132.17 $1,662.50 $2,469.67 $3,697.67 $1,662.50 $2,035.17 ($434.50) -10.5%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $15.23
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250
Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491
Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 50 of 82
Impact on T-2 to G-2 Rate Customers
Hours Use: 300
kWh Split: On Peak: 20%
Off Peak: 80%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 15,000 $1,333.08 $570.00 $763.08 $1,218.58 $570.00 $648.58 ($114.50) -8.6%
100 30,000 $2,653.32 $1,140.00 $1,513.32 $2,421.93 $1,140.00 $1,281.93 ($231.39) -8.7%
125 37,500 $3,313.45 $1,425.00 $1,888.45 $3,023.61 $1,425.00 $1,598.61 ($289.84) -8.7%
150 45,000 $3,973.56 $1,710.00 $2,263.56 $3,625.28 $1,710.00 $1,915.28 ($348.28) -8.8%
175 52,500 $4,633.69 $1,995.00 $2,638.69 $4,226.96 $1,995.00 $2,231.96 ($406.73) -8.8%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $15.23
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250
Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491
Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 51 of 82
Impact on T-2 to G-2 Rate Customers
Hours Use: 350
kWh Split: On Peak: 15%
Off Peak: 85%
- --------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 17,500 $1,471.02 $665.00 $806.02 $1,369.81 $665.00 $704.81 ($101.21) -6.9%
100 35,000 $2,929.17 $1,330.00 $1,599.17 $2,724.38 $1,330.00 $1,394.38 ($204.79) -7.0%
125 43,750 $3,658.26 $1,662.50 $1,995.76 $3,401.67 $1,662.50 $1,739.17 ($256.59) -7.0%
150 52,500 $4,387.35 $1,995.00 $2,392.35 $4,078.96 $1,995.00 $2,083.96 ($308.39) -7.0%
175 61,250 $5,116.43 $2,327.50 $2,788.93 $4,756.24 $2,327.50 $2,428.74 ($360.19) -7.0%
- --------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $15.23
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250
Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491
Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 52 of 82
Impact on T-2 to G-2 Rate Customers
Hours Use: 400
kWh Split: On Peak: 15%
Off Peak: 85%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 20,000 $1,613.53 $760.00 $853.53 $1,521.03 $760.00 $761.03 ($92.50) -5.7%
100 40,000 $3,214.22 $1,520.00 $1,694.22 $3,026.83 $1,520.00 $1,506.83 ($187.39) -5.8%
125 50,000 $4,014.57 $1,900.00 $2,114.57 $3,779.73 $1,900.00 $1,879.73 ($234.84) -5.8%
150 60,000 $4,814.91 $2,280.00 $2,534.91 $4,532.63 $2,280.00 $2,252.63 ($282.28) -5.9%
175 70,000 $5,615.26 $2,660.00 $2,955.26 $5,285.53 $2,660.00 $2,625.53 ($329.73) -5.9%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates T-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $15.23
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250
Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00491
Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00285 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-2 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 53 of 82
Impact on T-2 to G-2 Rate Customers
Hours Use: 450
kWh Split: On Peak: 15%
Off Peak: 85%
- ---------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $1,757.41 $855.00 $902.41 $1,677.21 $855.00 $822.21 ($80.20) -4.6%
100 45,000 $3,501.97 $1,710.00 $1,791.97 $3,339.18 $1,710.00 $1,629.18 ($162.79) -4.6%
125 56,250 $4,374.26 $2,137.50 $2,236.76 $4,170.17 $2,137.50 $2,032.67 ($204.09) -4.7%
150 67,500 $5,246.54 $2,565.00 $2,681.54 $5,001.16 $2,565.00 $2,436.16 ($245.38) -4.7%
175 78,750 $6,118.81 $2,992.50 $3,126.31 $5,832.14 $2,992.50 $2,839.64 ($286.67) -4.7%
- ---------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-2 Year 2001 Consolidated Rates: T-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $15.23
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $5.92
Transition Demand Charge KW x $6.29 Distribution Charge KWh x $0.00138
Distribution Charge KWh x $0.00231 Transition Charge KWh x $0.01250
Transition Charge: On Peak KWh x $0.01536 Transmission Charge KWh x $0.00513
Transition Charge: Off Peak KWh x $0.00923 Energy Conservation Charge KWh x $0.00270
Transmission Charge KWh x $0.00291 Renewables Charge KWh x $0.00100
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 54 of 82
Impact on T-2 to G-3 Rate Customers
Hours Use: 250
kWh Split: On Peak: 25% 55%
Off Peak: 75% 45%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 62,500 $5,916.76 $2,375.00 $3,541.76 $5,043.93 $2,375.00 $2,668.93 ($872.83) -14.8%
300 75,000 $7,097.53 $2,850.00 $4,247.53 $6,039.26 $2,850.00 $3,189.26 ($1,058.27) -14.9%
350 87,500 $8,278.32 $3,325.00 $4,953.32 $7,034.59 $3,325.00 $3,709.59 ($1,243.73) -15.0%
400 100,000 $9,459.09 $3,800.00 $5,659.09 $8,029.92 $3,800.00 $4,229.92 ($1,429.17) -15.1%
450 112,500 $10,639.88 $4,275.00 $6,364.88 $9,025.25 $4,275.00 $4,750.25 ($1,614.63) -15.2%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $67.27
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 55 of 82
Impact on T-2 to G-3 Rate Customers
Hours Use: 300
kWh Split: On Peak: 20% 50%
Off Peak: 80% 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 75,000 $6,614.04 $2,850.00 $3,764.04 $5,813.40 $2,850.00 $2,963.40 ($800.64) -12.1%
300 90,000 $7,934.28 $3,420.00 $4,514.28 $6,962.62 $3,420.00 $3,542.62 ($971.66) -12.2%
350 105,000 $9,254.52 $3,990.00 $5,264.52 $8,111.85 $3,990.00 $4,121.85 ($1,142.67) -12.3%
400 120,000 $10,574.76 $4,560.00 $6,014.76 $9,261.07 $4,560.00 $4,701.07 ($1,313.69) -12.4%
450 135,000 $11,895.00 $5,130.00 $6,765.00 $10,410.30 $5,130.00 $5,280.30 ($1,484.70) -12.5%
Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $67.27
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services
Standard Service Charge KWh x $0.03800 KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 56 of 82
Impact on T-2 to G-3 Rate Customers
Hours Use: 350
kWh Split: On Peak: 20% 50%
Off Peak: 80% 50%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 87,500 $7,330.50 $3,325.00 $4,005.50 $6,619.83 $3,325.00 $3,294.83 ($710.67) -9.7%
300 105,000 $8,794.02 $3,990.00 $4,804.02 $7,930.35 $3,990.00 $3,940.35 ($863.67) -9.8%
350 122,500 $10,257.56 $4,655.00 $5,602.56 $9,240.86 $4,655.00 $4,585.86 ($1,016.70) -9.9%
400 140,000 $11,721.08 $5,320.00 $6,401.08 $10,551.37 $5,320.00 $5,231.37 ($1,169.71) -10.0%
450 157,500 $13,184.62 $5,985.00 $7,199.62 $11,861.88 $5,985.00 $5,876.88 ($1,322.74) -10.0%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $67.27
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 57 of 82
Impact on T-2 to G-3 Rate Customers
Hours Use: 400
kWh Split: On Peak: 15% 45%
Off Peak: 85% 55%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 100,000 $8,016.29 $3,800.00 $4,216.29 $7,367.12 $3,800.00 $3,567.12 ($649.17) -8.1%
300 120,000 $9,616.98 $4,560.00 $5,056.98 $8,827.09 $4,560.00 $4,267.09 ($789.89) -8.2%
350 140,000 $11,217.67 $5,320.00 $5,897.67 $10,287.06 $5,320.00 $4,967.06 ($930.61) -8.3%
400 160,000 $12,818.36 $6,080.00 $6,738.36 $11,747.03 $6,080.00 $5,667.03 ($1,071.33) -8.4%
450 180,000 $14,419.05 $6,840.00 $7,579.05 $13,207.00 $6,840.00 $6,367.00 ($1,212.05) -8.4%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $67.27
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 58 of 82
Impact on T-2 to G-3 Rate Customers
Hours Use: 450
kWh Split: On Peak: 15% 45%
Off Peak: 85% 55%
- ------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 112,500 $8,728.92 $4,275.00 $4,453.92 $8,166.16 $4,275.00 $3,891.16 ($562.76) -6.4%
300 135,000 $10,472.12 $5,130.00 $5,342.12 $9,785.94 $5,130.00 $4,655.94 ($686.18) -6.6%
350 157,500 $12,215.35 $5,985.00 $6,230.35 $11,405.72 $5,985.00 $5,420.72 ($809.63) -6.6%
400 180,000 $13,958.55 $6,840.00 $7,118.55 $13,025.50 $6,840.00 $6,185.50 ($933.05) -6.7%
450 202,500 $15,701.77 $7,695.00 $8,006.77 $14,645.28 $7,695.00 $6,950.28 ($1,056.49) -6.7%
- ------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates T-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $67.27
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00440
Transmission Charge KWh x $0.00285 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 59 of 82
Impact on T-2 to G-3 Rate Customers
Hours Use: 500
kWh Split: On Peak: 15% 45%
Off Peak: 85% 55%
- ---------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 125,000 $9,449.03 $4,750.00 $4,699.03 $8,990.21 $4,750.00 $4,240.21 ($458.82) -4.9%
300 150,000 $11,336.27 $5,700.00 $5,636.27 $10,774.80 $5,700.00 $5,074.80 ($561.47) -5.0%
350 175,000 $13,223.50 $6,650.00 $6,573.50 $12,559.38 $6,650.00 $5,909.38 ($664.12) -5.0%
400 200,000 $15,110.74 $7,600.00 $7,510.74 $14,343.97 $7,600.00 $6,743.97 ($766.77) -5.1%
450 225,000 $16,997.98 $8,550.00 $8,447.98 $16,128.56 $8,550.00 $7,578.56 ($869.42) -5.1%
- ---------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: T-2 to G-3 Year 2001 Consolidated Rates: T-2 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $12.84 Customer Charge $67.27
Distribution Demand Charge KW x $2.92 Distribution Demand Charge KW x $3.63
Transition Demand Charge KW x $6.29 Distribution Charge: On Peak KWh x $0.01183
Distribution Charge KWh x $0.00231 Distribution Charge: Off Peak KWh x $0.00000
Transition Charge: On Peak KWh x $0.01536 Transition Charge KWh x $0.01250
Transition Charge: Off Peak KWh x $0.00923 Transmission Charge KWh x $0.00460
Transmission Charge KWh x $0.00291 Energy Conservation Charge KWh x $0.00270
Energy Conservation Charge KWh x $0.00270 Renewables Charge KWh x $0.00100
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: H-1 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 60 of 82
Impact on H-1 to G-1 Rate Customers
- ----------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 $10.11 $1.90 $8.21 $13.24 $1.90 $11.34 $3.13 31.0%
100 $14.82 $3.80 $11.02 $18.15 $3.80 $14.35 $3.33 22.5%
250 $28.97 $9.50 $19.47 $32.90 $9.50 $23.40 $3.93 13.6%
500 $52.55 $19.00 $33.55 $57.48 $19.00 $38.48 $4.93 9.4%
1,000 $99.69 $38.00 $61.69 $106.63 $38.00 $68.63 $6.94 7.0%
2,500 $241.15 $95.00 $146.15 $254.10 $95.00 $159.10 $12.95 5.4%
5,000 $476.89 $190.00 $286.89 $499.87 $190.00 $309.87 $22.98 4.8%
7,500 $712.65 $285.00 $427.65 $745.65 $285.00 $460.65 $33.00 4.6%
- ----------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-1 Year 2001 Consolidated Rates H-1 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $8.32
Distribution Charge KWh x $0.02669 Distribution Charge KWh x $0.03843
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 61 of 82
Impact on H-1 to G-2 Rate Customers
Hours Use: 200
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 10,000 $947.79 $380.00 $567.79 $916.13 $380.00 $536.13 ($31.66) -3.3%
100 20,000 $1,890.19 $760.00 $1,130.19 $1,817.03 $760.00 $1,057.03 ($73.16) -3.9%
125 25,000 $2,361.39 $950.00 $1,411.39 $2,267.48 $950.00 $1,317.48 ($93.91) -4.0%
150 30,000 $2,832.59 $1,140.00 $1,692.59 $2,717.93 $1,140.00 $1,577.93 ($114.66) -4.0%
175 35,000 $3,303.79 $1,330.00 $1,973.79 $3,168.38 $1,330.00 $1,838.38 ($135.41) -4.1%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $15.23
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 62 of 82
Impact on H-1 to G-2 Rate Customers
Hours Use: 250
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 12,500 $1,183.40 $475.00 $708.40 $1,067.36 $475.00 $592.36 ($116.04) -9.8%
100 25,000 $2,361.39 $950.00 $1,411.39 $2,119.48 $950.00 $1,169.48 ($241.91) -10.2%
125 31,250 $2,950.39 $1,187.50 $1,762.89 $2,645.54 $1,187.50 $1,458.04 ($304.85) -10.3%
150 37,500 $3,539.40 $1,425.00 $2,114.40 $3,171.61 $1,425.00 $1,746.61 ($367.79) -10.4%
175 43,750 $4,128.40 $1,662.50 $2,465.90 $3,697.67 $1,662.50 $2,035.17 ($430.73) -10.4%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $15.23
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 63 of 82
Impact on H-1 to G-2 Rate Customers
Hours Use: 300
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 15,000 $1,418.99 $570.00 $848.99 $1,218.58 $570.00 $648.58 ($200.41) -14.1%
100 30,000 $2,832.59 $1,140.00 $1,692.59 $2,421.93 $1,140.00 $1,281.93 ($410.66) -14.5%
125 37,500 $3,539.40 $1,425.00 $2,114.40 $3,023.61 $1,425.00 $1,598.61 ($515.79) -14.6%
150 45,000 $4,246.19 $1,710.00 $2,536.19 $3,625.28 $1,710.00 $1,915.28 ($620.91) -14.6%
175 52,500 $4,953.00 $1,995.00 $2,958.00 $4,226.96 $1,995.00 $2,231.96 ($726.04) -14.7%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $15.23
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 64 of 82
Impact on H-1 to G-2 Rate Customers
Hours Use: 350
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 17,500 $1,654.60 $665.00 $989.60 $1,369.81 $665.00 $704.81 ($284.79) -17.2%
100 35,000 $3,303.79 $1,330.00 $1,973.79 $2,724.38 $1,330.00 $1,394.38 ($579.41) -17.5%
125 43,750 $4,128.40 $1,662.50 $2,465.90 $3,401.67 $1,662.50 $1,739.17 ($726.73) -17.6%
150 52,500 $4,953.00 $1,995.00 $2,958.00 $4,078.96 $1,995.00 $2,083.96 ($874.04) -17.6%
175 61,250 $5,777.59 $2,327.50 $3,450.09 $4,756.24 $2,327.50 $2,428.74 ($1,021.35) -17.7%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $15.23
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 65 of 82
Impact on H-1 to G-2 Rate Customers
Hours Use: 400
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 20,000 $1,890.19 $760.00 $1,130.19 $1,521.03 $760.00 $761.03 ($369.16) -19.5%
100 40,000 $3,774.99 $1,520.00 $2,254.99 $3,026.83 $1,520.00 $1,506.83 ($748.16) -19.8%
125 50,000 $4,717.39 $1,900.00 $2,817.39 $3,779.73 $1,900.00 $1,879.73 ($937.66) -19.9%
150 60,000 $5,659.79 $2,280.00 $3,379.79 $4,532.63 $2,280.00 $2,252.63 ($1,127.16) -19.9%
175 70,000 $6,602.19 $2,660.00 $3,942.19 $5,285.53 $2,660.00 $2,625.53 ($1,316.66) -19.9%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $15.23
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01250
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: H-1 TO G-2 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 66 of 82
Impact on H-1 to G-2 Rate Customers
Hours Use: 450
- -------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,127.15 $855.00 $1,272.15 $1,677.21 $855.00 $822.21 ($449.94) -21.2%
100 45,000 $4,248.89 $1,710.00 $2,538.89 $3,339.18 $1,710.00 $1,629.18 ($909.71) -21.4%
125 56,250 $5,309.77 $2,137.50 $3,172.27 $4,170.17 $2,137.50 $2,032.67 ($1,139.60) -21.5%
150 67,500 $6,370.65 $2,565.00 $3,805.65 $5,001.16 $2,565.00 $2,436.16 ($1,369.49) -21.5%
175 78,750 $7,431.52 $2,992.50 $4,439.02 $5,832.14 $2,992.50 $2,839.64 ($1,599.38) -21.5%
- -------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-2 Year 2001 Consolidated Rates H-1 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $15.23
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00291 Transition Charge KWh x $0.01250
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00513
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 67 of 82
Impact on H-1 to G-3 Rate Customers
Hours Use: 250
kWh Split: On Peak: 55%
Off Peak: 45%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 62,500 $5,895.40 $2,375.00 $3,520.40 $5,043.93 $2,375.00 $2,668.93 ($851.47) -14.4%
300 75,000 $7,073.39 $2,850.00 $4,223.39 $6,039.26 $2,850.00 $3,189.26 ($1,034.13) -14.6%
350 87,500 $8,251.40 $3,325.00 $4,926.40 $7,034.59 $3,325.00 $3,709.59 ($1,216.81) -14.7%
400 100,000 $9,429.39 $3,800.00 $5,629.39 $8,029.92 $3,800.00 $4,229.92 ($1,399.47) -14.8%
450 112,500 $10,607.40 $4,275.00 $6,332.40 $9,025.25 $4,275.00 $4,750.25 ($1,582.15) -14.9%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $67.27
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63
Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183
Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000
Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250
Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 68 of 82
Impact on H-1 to G-3 Rate Customers
Hours Use: 300
kWh Split: On Peak: 50%
Off Peak: 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 75,000 $7,073.39 $2,850.00 $4,223.39 $5,813.40 $2,850.00 $2,963.40 ($1,259.99) -17.8%
300 90,000 $8,486.99 $3,420.00 $5,066.99 $6,962.62 $3,420.00 $3,542.62 ($1,524.37) -18.0%
350 105,000 $9,900.59 $3,990.00 $5,910.59 $8,111.85 $3,990.00 $4,121.85 ($1,788.74) -18.1%
400 120,000 $11,314.19 $4,560.00 $6,754.19 $9,261.07 $4,560.00 $4,701.07 ($2,053.12) -18.1%
450 135,000 $12,727.79 $5,130.00 $7,597.79 $10,410.30 $5,130.00 $5,280.30 ($2,317.49) -18.2%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $67.27
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63
Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183
Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000
Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250
Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 69 of 82
Impact on H-1 to G-3 Rate Customers
Hours Use: 350
kWh Split: On Peak: 50%
Off Peak: 50%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 87,500 $8,251.40 $3,325.00 $4,926.40 $6,619.83 $3,325.00 $3,294.83 ($1,631.57) -19.8%
300 105,000 $9,900.59 $3,990.00 $5,910.59 $7,930.35 $3,990.00 $3,940.35 ($1,970.24) -19.9%
350 122,500 $11,549.80 $4,655.00 $6,894.80 $9,240.86 $4,655.00 $4,585.86 ($2,308.94) -20.0%
400 140,000 $13,198.99 $5,320.00 $7,878.99 $10,551.37 $5,320.00 $5,231.37 ($2,647.62) -20.1%
450 157,500 $14,848.20 $5,985.00 $8,863.20 $11,861.88 $5,985.00 $5,876.88 ($2,986.32) -20.1%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $67.27
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63
Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183
Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000
Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250
Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 70 of 82
Impact on H-1 to G-3 Rate Customers
Hours Use: 400
kWh Split: On Peak: 45%
Off Peak: 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 100,000 $9,429.39 $3,800.00 $5,629.39 $7,367.12 $3,800.00 $3,567.12 ($2,062.27) -21.9%
300 120,000 $11,314.19 $4,560.00 $6,754.19 $8,827.09 $4,560.00 $4,267.09 ($2,487.10) -22.0%
350 140,000 $13,198.99 $5,320.00 $7,878.99 $10,287.06 $5,320.00 $4,967.06 ($2,911.93) -22.1%
400 160,000 $15,083.79 $6,080.00 $9,003.79 $11,747.03 $6,080.00 $5,667.03 ($3,336.76) -22.1%
450 180,000 $16,968.59 $6,840.00 $10,128.59 $13,207.00 $6,840.00 $6,367.00 ($3,761.59) -22.2%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $67.27
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63
Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183
Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000
Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250
Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 71 of 82
Impact on H-1 to G-3 Rate Customers
Hours Use: 450
kWh Split: On Peak: 45%
Off Peak: 55%
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 112,500 $10,607.40 $4,275.00 $6,332.40 $8,166.16 $4,275.00 $3,891.16 ($2,441.24) -23.0%
300 135,000 $12,727.79 $5,130.00 $7,597.79 $9,785.94 $5,130.00 $4,655.94 ($2,941.85) -23.1%
350 157,500 $14,848.20 $5,985.00 $8,863.20 $11,405.72 $5,985.00 $5,420.72 ($3,442.48) -23.2%
400 180,000 $16,968.59 $6,840.00 $10,128.59 $13,025.50 $6,840.00 $6,185.50 ($3,943.09) -23.2%
450 202,500 $19,089.00 $7,695.00 $11,394.00 $14,645.28 $7,695.00 $6,950.28 ($4,443.72) -23.3%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $67.27
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63
Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183
Transmission Charge KWh x $0.00285 Distribution Charge: Off Peak KWh x $0.00000
Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250
Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00440
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: H-1 TO G-3 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 72 of 82
Impact on H-1 to G-3 Rate Customers
Hours Use: 500
kWh Split: On Peak: 45%
Off Peak: 55%
- -------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 125,000 $11,792.89 $4,750.00 $7,042.89 $8,990.21 $4,750.00 $4,240.21 ($2,802.68) -23.8%
300 150,000 $14,150.39 $5,700.00 $8,450.39 $10,774.80 $5,700.00 $5,074.80 ($3,375.59) -23.9%
350 175,000 $16,507.89 $6,650.00 $9,857.89 $12,559.38 $6,650.00 $5,909.38 ($3,948.51) -23.9%
400 200,000 $18,865.39 $7,600.00 $11,265.39 $14,343.97 $7,600.00 $6,743.97 ($4,521.42) -24.0%
450 225,000 $21,222.89 $8,550.00 $12,672.89 $16,128.56 $8,550.00 $7,578.56 ($5,094.33) -24.0%
- -------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-1 to G-3 Year 2001 Consolidated Rates H-1 to G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $5.39 Customer Charge $67.27
Distribution Charge KWh x $0.02669 Distribution Demand Charge KW x $3.63
Transition Charge KWh x $0.02300 Distribution Charge: On Peak KWh x $0.01183
Transmission Charge KWh x $0.00291 Distribution Charge: Off Peak KWh x $0.00000
Energy Conservation Charge KWh x $0.00270 Transition Charge KWh x $0.01250
Renewables Charge KWh x $0.00100 Transmission Charge KWh x $0.00460
Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: H-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 73 of 82
Impact on H-2 to G-1 Rate Customers
- -------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 $6.15 $1.90 $4.25 $13.24 $1.90 $11.34 $7.09 115.3%
100 $10.94 $3.80 $7.14 $18.15 $3.80 $14.35 $7.21 65.9%
250 $25.33 $9.50 $15.83 $32.90 $9.50 $23.40 $7.57 29.9%
500 $49.30 $19.00 $30.30 $57.48 $19.00 $38.48 $8.18 16.6%
1,000 $97.24 $38.00 $59.24 $106.63 $38.00 $68.63 $9.39 9.7%
2,500 $241.08 $95.00 $146.08 $254.10 $95.00 $159.10 $13.02 5.4%
5,000 $480.80 $190.00 $290.80 $499.87 $190.00 $309.87 $19.07 4.0%
7,500 $720.53 $285.00 $435.53 $745.65 $285.00 $460.65 $25.12 3.5%
- -------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-1 Year 2001 Consolidated Rates H-2 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $8.32
Distribution Charge KWh x $0.02828 Distribution Charge KWh x $0.03843
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 74 of 82
Impact on H-2 to G-2 Rate Customers
Hours Use: 50
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5%
100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9%
125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9%
150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0%
175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $15.23
Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 75 of 82
Impact on H-2 to G-2 Rate Customers
Hours Use: 100
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5%
100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9%
125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9%
150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0%
175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $15.23
Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KW x $0.01393
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.01393
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00198
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00285
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 76 of 82
Impact on H-2 to G-2 Rate Customers
Hours Use: 200
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5%
100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9%
125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9%
150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0%
175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $15.23
Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 77 of 82
Impact on H-2 to G-2 Rate Customers
Hours Use: 250
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5%
100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9%
125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9%
150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0%
175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $15.23
Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: T-2 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 78 of 82
Impact on H-2 to G-2 Rate Customers
Hours Use: 300
- -----------------------------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,157.53 $855.00 $1,302.53 $1,671.58 $855.00 $816.58 ($485.95) -22.5%
100 45,000 $4,313.70 $1,710.00 $2,603.70 $3,327.93 $1,710.00 $1,617.93 ($985.77) -22.9%
125 56,250 $5,391.79 $2,137.50 $3,254.29 $4,156.11 $2,137.50 $2,018.61 ($1,235.68) -22.9%
150 67,500 $6,469.88 $2,565.00 $3,904.88 $4,984.28 $2,565.00 $2,419.28 ($1,485.60) -23.0%
175 78,750 $7,547.97 $2,992.50 $4,555.47 $5,812.46 $2,992.50 $2,819.96 ($1,735.51) -23.0%
- -----------------------------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $15.23
Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KW x $0.01393
Transmission Charge KWh x $0.00285 Transition Charge KWh x $0.00198
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00285
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: H-2 TO G-2 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 79 of 82
Impact on H-2 to G-2 Rate Customers
Hours Use: 350
- -------------------------------------------------------------------------------------------------------------
Monthly Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Power Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 22,500 $2,158.88 $855.00 $1,303.88 $1,672.93 $855.00 $817.93 ($485.95) -22.5%
100 45,000 $4,316.40 $1,710.00 $2,606.40 $3,330.63 $1,710.00 $1,620.63 ($985.77) -22.8%
125 56,250 $5,395.17 $2,137.50 $3,257.67 $4,159.48 $2,137.50 $2,021.98 ($1,235.69) -22.9%
150 67,500 $6,473.93 $2,565.00 $3,908.93 $4,988.33 $2,565.00 $2,423.33 ($1,485.60) -22.9%
175 78,750 $7,552.69 $2,992.50 $4,560.19 $5,817.18 $2,992.50 $2,824.68 ($1,735.51) -23.0%
- -------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates: H-2 to G-2 Year 2001 Consolidated Rates H-2 to G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $1.35 Customer Charge $15.23
Distribution Charge KWh x $0.02828 Distribution Demand Charge KW x $5.92
Transition Charge KWh x $0.02300 Distribution Charge KWh x $0.01393
Transmission Charge KWh x $0.00291 Transition Charge KWh x $0.00198
Energy Conservation Charge KWh x $0.00270 Transmission Charge KWh x $0.00291
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: W-1 TO G-1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 80 of 82
Impact on W-1 to G-1
- -------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 $23.67 $9.50 $14.17 $32.90 $9.50 $23.40 $9.23 39.0%
500 $46.43 $19.00 $27.43 $57.48 $19.00 $38.48 $11.05 23.8%
750 $69.18 $28.50 $40.68 $82.05 $28.50 $53.55 $12.87 18.6%
1,000 $91.94 $38.00 $53.94 $106.63 $38.00 $68.63 $14.69 16.0%
1,250 $114.71 $47.50 $67.21 $131.21 $47.50 $83.71 $16.50 14.4%
1,500 $137.47 $57.00 $80.47 $155.79 $57.00 $98.79 $18.32 13.3%
2,000 $182.98 $76.00 $106.98 $204.94 $76.00 $128.94 $21.96 12.0%
2,500 $228.51 $95.00 $133.51 $254.10 $95.00 $159.10 $25.59 11.2%
- -------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates W-1 to G-1 Year 2001 Consolidated Rates W-1 to G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $0.90 Customer Charge $8.32
Distribution Charge KWh x $0.02343 Distribution Charge KWh x $0.03843
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00568
Energy Conservation Charge KWh x $0.00270 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: W-1 TO R-1 1 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 81 of 82
Impact on W-1 to R-1 Rate Customers with Interruptible Credit #1
- -----------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 $1.81 $0.38 $1.43 $1.16 $0.38 $0.78 ($0.65) -35.9%
50 $5.46 $1.90 $3.56 $4.56 $1.90 $2.66 ($0.90) -16.5%
100 $10.00 $3.80 $6.20 $8.80 $3.80 $5.00 ($1.20) -12.0%
250 $23.67 $9.50 $14.17 $21.54 $9.50 $12.04 ($2.13) -9.0%
500 $46.43 $19.00 $27.43 $42.78 $19.00 $23.78 ($3.65) -7.9%
750 $69.18 $28.50 $40.68 $64.01 $28.50 $35.51 ($5.17) -7.5%
1,000 $91.94 $38.00 $53.94 $85.24 $38.00 $47.24 ($6.70) -7.3%
1,500 $137.47 $57.00 $80.47 $127.71 $57.00 $70.71 ($9.76) -7.1%
- -----------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates W-1 to R-1 Year 2001 Consolidated Rates W-1 to R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $0.90 Customer Charge $5.81
Distribution Charge KWh x $0.02343 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571
Energy Conservation Charge KWh x $0.00270 Interruptible Credit #1 ($5.50)
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\EDGAR\[eectb1a.wk4]Input Section New England Electric System
Range: W-1 TO R-1 2 Massachusetts Electric Company Eastern Utilities Associates
Date: 04-Aug-99 Eastern Edison Company M.D.T.E. Docket No. 99-__
Time: 12:52 PM Calculation of Monthly Typical Bill for January 1, 2001 Exhibit TMB-10, Revised
Page 82 of 82
Impact on W-1 to R-1 Rate Customers with Interruptible Credit #2
- -----------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates Year 2001 Consolidated Rates Increase/(Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
10 $1.81 $0.38 $1.43 ($0.84) $0.38 ($1.22) ($2.65) -146.4%
50 $5.46 $1.90 $3.56 $2.56 $1.90 $0.66 ($2.90) -53.1%
100 $10.00 $3.80 $6.20 $6.80 $3.80 $3.00 ($3.20) -32.0%
250 $23.67 $9.50 $14.17 $19.54 $9.50 $10.04 ($4.13) -17.4%
500 $46.43 $19.00 $27.43 $40.78 $19.00 $21.78 ($5.65) -12.2%
750 $69.18 $28.50 $40.68 $62.01 $28.50 $33.51 ($7.17) -10.4%
1,000 $91.94 $38.00 $53.94 $83.24 $38.00 $45.24 ($8.70) -9.5%
1,500 $137.47 $57.00 $80.47 $125.71 $57.00 $68.71 ($11.76) -8.6%
- -----------------------------------------------------------------------------------------------------------------
Estimated Year 2001 EEC Rates W-1 to R-1 Year 2001 Consolidated Rates W-1 to R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $0.90 Customer Charge $5.81
Distribution Charge KWh x $0.02343 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.02300 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00291 Transmission Charge KWh x $0.00571
Energy Conservation Charge KWh x $0.00270 Interruptible Credit #2 ($7.50)
Renewables Charge KWh x $0.00100 Energy Conservation Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge $0.03800
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-11
Massachusetts Electric Company
Typical Bills
January 1, 2001 Assuming No Merger
vs.
January 1, 2001 Combined Rates
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 1 of 22
Impact on R-1 Rate Customers
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
125 $16.26 $4.75 $11.51 $16.40 $4.75 $11.65 $0.14 0.9%
250 $26.71 $9.50 $17.21 $26.98 $9.50 $17.48 $0.27 1.0%
500 $47.60 $19.00 $28.60 $48.16 $19.00 $29.16 $0.56 1.2%
750 $68.50 $28.50 $40.00 $69.33 $28.50 $40.83 $0.83 1.2%
1,000 $89.39 $38.00 $51.39 $90.50 $38.00 $52.50 $1.11 1.2%
1,250 $110.29 $47.50 $62.79 $111.67 $47.50 $64.17 $1.38 1.3%
1,500 $131.18 $57.00 $74.18 $132.85 $57.00 $75.85 $1.67 1.3%
2,000 $172.97 $76.00 $96.97 $175.19 $76.00 $99.19 $2.22 1.3%
Projected January 1, 2001 Rates: R-1 Proposed Combined 2001 Rates R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $5.81 Customer Charge $5.81
Distribution Charge KWh x $0.02502 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 2 of 22
Impact on R-1 Rate Customers (with Interruptible Credit #1)
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
250 $21.21 $9.50 $11.71 $21.48 $9.50 $11.98 $0.27 1.3%
500 $42.10 $19.00 $23.10 $42.66 $19.00 $23.66 $0.56 1.3%
750 $63.00 $28.50 $34.50 $63.83 $28.50 $35.33 $0.83 1.3%
1,000 $83.89 $38.00 $45.89 $85.00 $38.00 $47.00 $1.11 1.3%
1,250 $104.79 $47.50 $57.29 $106.17 $47.50 $58.67 $1.38 1.3%
1,500 $125.68 $57.00 $68.68 $127.35 $57.00 $70.35 $1.67 1.3%
2,000 $167.47 $76.00 $91.47 $169.69 $76.00 $93.69 $2.22 1.3%
2,500 $209.26 $95.00 $114.26 $212.04 $95.00 $117.04 $2.78 1.3%
Projected January 1, 2001 Rates: R-1 Proposed Combined 2001 Rates R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $5.81 Customer Charge $5.81
Distribution Charge KWh x $0.02502 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547
Interruptible Credit #1 KWh x ($5.50) Interruptible Credit #1 KWh x ($5.50)
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 3 of 22
Impact on R-1 Rate Customers (with Interruptible Credit #2)
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
250 $19.21 $9.50 $9.71 $19.48 $9.50 $9.98 $0.27 1.4%
500 $40.10 $19.00 $21.10 $40.66 $19.00 $21.66 $0.56 1.4%
750 $61.00 $28.50 $32.50 $61.83 $28.50 $33.33 $0.83 1.4%
1,000 $81.89 $38.00 $43.89 $83.00 $38.00 $45.00 $1.11 1.4%
1,250 $102.79 $47.50 $55.29 $104.17 $47.50 $56.67 $1.38 1.3%
1,500 $123.68 $57.00 $66.68 $125.35 $57.00 $68.35 $1.67 1.4%
2,000 $165.47 $76.00 $89.47 $167.69 $76.00 $91.69 $2.22 1.3%
2,500 $207.26 $95.00 $112.26 $210.04 $95.00 $115.04 $2.78 1.3%
Projected January 1, 2001 Rates: R-1 Proposed Combined 2001 Rates R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $5.81 Customer Charge $5.81
Distribution Charge KWh x $0.02502 Distribution Charge KWh x $0.02502
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547
Interruptible Credit #2 KWh x ($7.50) Interruptible Credit #2 KWh x ($7.50)
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 4 of 22
Impact on R-2 Rate Customers
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
50 $6.93 $1.90 $5.03 $6.99 $1.90 $5.09 $0.06 0.9%
100 $10.09 $3.80 $6.29 $10.20 $3.80 $6.40 $0.11 1.1%
150 $13.25 $5.70 $7.55 $13.42 $5.70 $7.72 $0.17 1.3%
250 $19.57 $9.50 $10.07 $19.85 $9.50 $10.35 $0.28 1.4%
300 $22.73 $11.40 $11.33 $23.06 $11.40 $11.66 $0.33 1.5%
500 $35.37 $19.00 $16.37 $35.92 $19.00 $16.92 $0.55 1.6%
600 $41.68 $22.80 $18.88 $42.35 $22.80 $19.55 $0.67 1.6%
750 $51.16 $28.50 $22.66 $52.00 $28.50 $23.50 $0.84 1.6%
Projected January 1, 2001 Rates: R-2 Proposed Combined 2001 Rates R-2
<S> <C> <C> <C> <C> <C>
Customer Charge $3.77 Customer Charge $3.77
Distribution Charge KWh x $0.00463 Distribution Charge KWh x $0.00463
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 5 of 22
Impact on R-2 Rate Customers
With Interruptible Credit #1
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
300 $17.23 $11.40 $5.83 $17.56 $11.40 $6.16 $0.33 1.9%
500 $29.87 $19.00 $10.87 $30.42 $19.00 $11.42 $0.55 1.8%
600 $36.18 $22.80 $13.38 $36.85 $22.80 $14.05 $0.67 1.9%
750 $45.66 $28.50 $17.16 $46.50 $28.50 $18.00 $0.84 1.8%
900 $55.14 $34.20 $20.94 $56.14 $34.20 $21.94 $1.00 1.8%
1,000 $61.46 $38.00 $23.46 $62.57 $38.00 $24.57 $1.11 1.8%
1,500 $93.06 $57.00 $36.06 $94.72 $57.00 $37.72 $1.66 1.8%
1,750 $108.85 $66.50 $42.35 $110.80 $66.50 $44.30 $1.95 1.8%
Projected January 1, 2001 Rates: R-2 Proposed Combined 2001 Rates R-2
<S> <C> <C> <C> <C> <C>
Customer Charge $3.77 Customer Charge $3.77
Distribution Charge KWh x $0.00463 Distribution Charge KWh x $0.00463
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547
Interruptible Credit #1 KWh x ($5.50) Interruptible Credit #1 KWh x ($5.50)
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 6 of 22
Impact on R-2 Rate Customers
With Interruptible Credit #2
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
300 $15.23 $11.40 $3.83 $15.56 $11.40 $4.16 $0.33 2.2%
500 $27.87 $19.00 $8.87 $28.42 $19.00 $9.42 $0.55 2.0%
600 $34.18 $22.80 $11.38 $34.85 $22.80 $12.05 $0.67 2.0%
750 $43.66 $28.50 $15.16 $44.50 $28.50 $16.00 $0.84 1.9%
900 $53.14 $34.20 $18.94 $54.14 $34.20 $19.94 $1.00 1.9%
1,000 $59.46 $38.00 $21.46 $60.57 $38.00 $22.57 $1.11 1.9%
1,500 $91.06 $57.00 $34.06 $92.72 $57.00 $35.72 $1.66 1.8%
1,750 $106.85 $66.50 $40.35 $108.80 $66.50 $42.30 $1.95 1.8%
Projected January 1, 2001 Rates: R-2 Proposed Combined 2001 Rates R-2
<S> <C> <C> <C> <C> <C>
Customer Charge $3.77 Customer Charge KWh x $3.77
Distribution Charge KWh x $0.00463 Distribution Charge KWh x $0.00463
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00616 Transmission Charge KWh x $0.00547
Interruptible Credit #2 KWh x ($7.50) Interruptible Credit #2 KWh x ($7.50)
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 7 of 22
Impact on R-4 Rate Customers
KWh Split: - On Peak 25%
- Off Peak 75%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1,000 $93.86 $38.00 $55.86 $94.31 $38.00 $56.31 $0.45 0.5%
1,500 $131.29 $57.00 $74.29 $131.97 $57.00 $74.97 $0.68 0.5%
2,000 $168.72 $76.00 $92.72 $169.63 $76.00 $93.63 $0.91 0.5%
3,000 $243.57 $114.00 $129.57 $244.94 $114.00 $130.94 $1.37 0.6%
4,000 $318.43 $152.00 $166.43 $320.25 $152.00 $168.25 $1.82 0.6%
5,000 $393.29 $190.00 $203.29 $395.56 $190.00 $205.56 $2.27 0.6%
8,000 $617.86 $304.00 $313.86 $621.50 $304.00 $317.50 $3.64 0.6%
10,000 $767.58 $380.00 $387.58 $772.13 $380.00 $392.13 $4.55 0.6%
Projected January 1, 2001 Rates: R-4 Proposed Combined 2001 Rates R-4
<S> <C> <C> <C> <C> <C>
Customer Charge $19.00 Customer Charge $19.00
Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: On Peak KWh x $0.05527
Distribution Charge: Off Peak KWh x $0.00730 Distribution Charge: Off Peak KWh x $0.00730
Transition Charge: On Peak KWh x $0.02659 Transition Charge: On Peak KWh x $0.03017
Transition Charge: Off Peak KWh x $0.00217 Transition Charge: Off Peak KWh x $0.00253
Transmission Charge: On Peak KWh x $0.00559 Transmission Charge: On Peak KWh x $0.00488
Transmission Charge: Off Peak KWh x $0.00559 Transmission Charge: Off Peak KWh x $0.00488
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 8 of 22
Impact on R-4 Rate Customers
KWh Split: - On Peak 30%
- Off Peak 70%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1,000 $97.48 $38.00 $59.48 $98.09 $38.00 $60.09 $0.61 0.6%
1,500 $136.72 $57.00 $79.72 $137.64 $57.00 $80.64 $0.92 0.7%
2,000 $175.95 $76.00 $99.95 $177.19 $76.00 $101.19 $1.24 0.7%
3,000 $254.43 $114.00 $140.43 $256.28 $114.00 $142.28 $1.85 0.7%
4,000 $332.91 $152.00 $180.91 $335.37 $152.00 $183.37 $2.46 0.7%
5,000 $411.39 $190.00 $221.39 $414.47 $190.00 $224.47 $3.08 0.7%
8,000 $646.82 $304.00 $342.82 $651.74 $304.00 $347.74 $4.92 0.8%
10,000 $803.77 $380.00 $423.77 $809.93 $380.00 $429.93 $6.16 0.8%
Projected January 1, 2001 Rates: R-4 Proposed Combined 2001 Rates R-4
<S> <C> <C> <C> <C> <C>
Customer Charge $19.00 Customer Charge $19.00
Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: On Peak KWh x $0.05527
Distribution Charge: Off Peak KWh x $0.00730 Distribution Charge: Off Peak KWh x $0.00730
Transition Charge: On Peak KWh x $0.02659 Transition Charge: On Peak KWh x $0.03017
Transition Charge: Off Peak KWh x $0.00217 Transition Charge: Off Peak KWh x $0.00253
Transmission Charge: On Peak KWh x $0.00559 Transmission Charge: On Peak KWh x $0.00488
Transmission Charge: Off Peak KWh x $0.00559 Transmission Charge: Off Peak KWh x $0.00488
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 9 of 22
Impact on R-4 Rate Customers
KWh Split: - On Peak 40%
- Off Peak 60%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1,000 $104.72 $38.00 $66.72 $105.65 $38.00 $67.65 $0.93 0.9%
1,500 $147.57 $57.00 $90.57 $148.98 $57.00 $91.98 $1.41 1.0%
2,000 $190.43 $76.00 $114.43 $192.31 $76.00 $116.31 $1.88 1.0%
3,000 $276.15 $114.00 $162.15 $278.96 $114.00 $164.96 $2.81 1.0%
4,000 $361.86 $152.00 $209.86 $365.62 $152.00 $213.62 $3.76 1.0%
5,000 $447.58 $190.00 $257.58 $452.27 $190.00 $262.27 $4.69 1.0%
8,000 $704.73 $304.00 $400.73 $712.23 $304.00 $408.23 $7.50 1.1%
10,000 $876.16 $380.00 $496.16 $885.54 $380.00 $505.54 $9.38 1.1%
Projected January 1, 2001 Rates: R-4 Proposed Combined 2001 Rates R-4
<S> <C> <C> <C> <C> <C>
Customer Charge $19.00 Customer Charge $19.00
Distribution Charge: On Peak KWh x $0.05527 Distribution Charge: On Peak KWh x $0.05527
Distribution Charge: Off Peak KWh x $0.00730 Distribution Charge: Off Peak KWh x $0.00730
Transition Charge: On Peak KWh x $0.02659 Transition Charge: On Peak KWh x $0.03017
Transition Charge: Off Peak KWh x $0.00217 Transition Charge: Off Peak KWh x $0.00253
Transmission Charge: On Peak KWh x $0.00559 Transmission Charge: On Peak KWh x $0.00488
Transmission Charge: Off Peak KWh x $0.00559 Transmission Charge: Off Peak KWh x $0.00488
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 10 of 22
Impact on G-1 Rate Customers
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
50 $13.16 $1.90 $11.26 $13.22 $1.90 $11.32 $0.06 0.5%
100 $17.99 $3.80 $14.19 $18.13 $3.80 $14.33 $0.14 0.8%
250 $32.50 $9.50 $23.00 $32.84 $9.50 $23.34 $0.34 1.0%
500 $56.68 $19.00 $37.68 $57.36 $19.00 $38.36 $0.68 1.2%
1,000 $105.04 $38.00 $67.04 $106.39 $38.00 $68.39 $1.35 1.3%
2,500 $250.12 $95.00 $155.12 $253.50 $95.00 $158.50 $3.38 1.4%
5,000 $491.92 $190.00 $301.92 $498.67 $190.00 $308.67 $6.75 1.4%
7,500 $733.72 $285.00 $448.72 $743.85 $285.00 $458.85 $10.13 1.4%
Projected January 1, 2001 Rates: G-1 Proposed Combined 2001 Rates G-1
<S> <C> <C> <C> <C> <C>
Customer Charge $8.32 Customer Charge $8.32
Distribution Charge KWh x $0.03843 Distribution Charge KWh x $0.03843
Transition Charge KWh x $0.01070 Transition Charge KWh x $0.01250
Transmission Charge KWh x $0.00589 Transmission Charge KWh x $0.00544
DSM Charge KWh x $0.00270 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100 Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 11 of 22
Impact on G-2 Rate Customers
Hours Use: 200
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 3,000 $282.17 $114.00 $168.17 $285.50 $114.00 $171.50 $3.33 1.2%
20 4,000 $371.15 $152.00 $219.15 $375.59 $152.00 $223.59 $4.44 1.2%
40 8,000 $727.07 $304.00 $423.07 $735.95 $304.00 $431.95 $8.88 1.2%
75 15,000 $1,349.93 $570.00 $779.93 $1,366.58 $570.00 $796.58 $16.65 1.2%
150 30,000 $2,684.63 $1,140.00 $1,544.63 $2,717.93 $1,140.00 $1,577.93 $33.30 1.2%
Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $15.23 Customer Charge $15.23
Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92
Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00
Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 12 of 22
Impact on G-2 Rate Customers
Hours Use: 250
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 3,750 $326.71 $142.50 $184.21 $330.87 $142.50 $188.37 $4.16 1.3%
20 5,000 $430.53 $190.00 $240.53 $436.08 $190.00 $246.08 $5.55 1.3%
40 10,000 $845.83 $380.00 $465.83 $856.93 $380.00 $476.93 $11.10 1.3%
75 18,750 $1,572.61 $712.50 $860.11 $1,593.42 $712.50 $880.92 $20.81 1.3%
150 37,500 $3,129.98 $1,425.00 $1,704.98 $3,171.61 $1,425.00 $1,746.61 $41.63 1.3%
Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $15.23 Customer Charge $15.23
Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92
Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00
Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 13 of 22
Impact on G-2 Rate Customers
Hours Use: 300
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 4,500 $371.24 $171.00 $200.24 $376.24 $171.00 $205.24 $5.00 1.3%
20 6,000 $489.91 $228.00 $261.91 $496.57 $228.00 $268.57 $6.66 1.4%
40 12,000 $964.59 $456.00 $508.59 $977.91 $456.00 $521.91 $13.32 1.4%
75 22,500 $1,795.28 $855.00 $940.28 $1,820.26 $855.00 $965.26 $24.98 1.4%
150 45,000 $3,575.33 $1,710.00 $1,865.33 $3,625.28 $1,710.00 $1,915.28 $49.95 1.4%
Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $15.23 Customer Charge $15.23
Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92
Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00
Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 14 of 22
Impact on G-2 Rate Customers
Hours Use: 350
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 5,250 $415.78 $199.50 $216.28 $421.60 $199.50 $222.10 $5.82 1.4%
20 7,000 $549.29 $266.00 $283.29 $557.06 $266.00 $291.06 $7.77 1.4%
40 14,000 $1,083.35 $532.00 $551.35 $1,098.89 $532.00 $566.89 $15.54 1.4%
75 26,250 $2,017.96 $997.50 $1,020.46 $2,047.09 $997.50 $1,049.59 $29.13 1.4%
150 52,500 $4,020.68 $1,995.00 $2,025.68 $4,078.96 $1,995.00 $2,083.96 $58.28 1.4%
Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $15.23 Customer Charge $15.23
Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92
Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00
Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 15 of 22
Impact on G-2 Rate Customers
Hours Use: 400
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 6,000 $460.31 $228.00 $232.31 $466.97 $228.00 $238.97 $6.66 1.4%
20 8,000 $608.67 $304.00 $304.67 $617.55 $304.00 $313.55 $8.88 1.5%
40 16,000 $1,202.11 $608.00 $594.11 $1,219.87 $608.00 $611.87 $17.76 1.5%
75 30,000 $2,240.63 $1,140.00 $1,100.63 $2,273.93 $1,140.00 $1,133.93 $33.30 1.5%
150 60,000 $4,466.03 $2,280.00 $2,186.03 $4,532.63 $2,280.00 $2,252.63 $66.60 1.5%
Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $15.23 Customer Charge $15.23
Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92
Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00
Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 16 of 22
Impact on G-2 Rate Customers
Hours Use: 450
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 6,750 $504.85 $256.50 $248.35 $512.34 $256.50 $255.84 $7.49 1.5%
20 9,000 $668.05 $342.00 $326.05 $678.04 $342.00 $336.04 $9.99 1.5%
40 18,000 $1,320.87 $684.00 $636.87 $1,340.85 $684.00 $656.85 $19.98 1.5%
75 33,750 $2,463.31 $1,282.50 $1,180.81 $2,500.77 $1,282.50 $1,218.27 $37.46 1.5%
150 67,500 $4,911.38 $2,565.00 $2,346.38 $4,986.31 $2,565.00 $2,421.31 $74.93 1.5%
Projected January 1, 2001 Rates: G-2 Proposed Combined 2001 Rates G-2
<S> <C> <C> <C> <C> <C>
Customer Charge $15.23 Customer Charge $15.23
Distribution Demand Charge KWh x $5.92 Distribution Demand Charge KWh x $5.92
Distribution Charge KWh x $0.00138 Transition Demand Charge KWh x $0.00
Transition Charge KWh x $0.01070 Distribution Charge KWh x $0.00138
Transmission Charge KWh x $0.00560 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00491
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 17 of 22
Impact on G-3 Rate Customers
Hours Use: 250
KWh Split: - On Peak 55%
- Off Peak 45%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 150,000 $11,832.75 $5,700.00 $6,132.75 $12,011.25 $5,700.00 $6,311.25 $178.50 1.5%
800 200,000 $15,754.57 $7,600.00 $8,154.57 $15,992.57 $7,600.00 $8,392.57 $238.00 1.5%
1000 250,000 $19,676.40 $9,500.00 $10,176.40 $19,973.90 $9,500.00 $10,473.90 $297.50 1.5%
1500 375,000 $29,480.96 $14,250.00 $15,230.96 $29,927.21 $14,250.00 $15,677.21 $446.25 1.5%
3000 750,000 $58,894.65 $28,500.00 $30,394.65 $59,787.15 $28,500.00 $31,287.15 $892.50 1.5%
Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $67.27 Customer Charge $67.27
Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63
Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00
Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183
Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000
Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 18 of 22
Impact on G-3 Rate Customers
Hours Use: 300
KWh Split: - On Peak 50%
- Off Peak 50%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 180,000 $13,643.77 $6,840.00 $6,803.77 $13,857.97 $6,840.00 $7,017.97 $214.20 1.6%
800 240,000 $18,169.27 $9,120.00 $9,049.27 $18,454.87 $9,120.00 $9,334.87 $285.60 1.6%
1000 300,000 $22,694.77 $11,400.00 $11,294.77 $23,051.77 $11,400.00 $11,651.77 $357.00 1.6%
1500 450,000 $34,008.52 $17,100.00 $16,908.52 $34,544.02 $17,100.00 $17,444.02 $535.50 1.6%
3000 900,000 $67,949.77 $34,200.00 $33,749.77 $69,020.77 $34,200.00 $34,820.77 $1,071.00 1.6%
Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $67.27 Customer Charge $67.27
Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63
Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00
Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183
Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000
Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 19 of 22
Impact on G-3 Rate Customers
Hours Use: 350
KWh Split: - On Peak 50%
- Off Peak 50%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 210,000 $15,543.52 $7,980.00 $7,563.52 $15,793.42 $7,980.00 $7,813.42 $249.90 1.6%
800 280,000 $20,702.27 $10,640.00 $10,062.27 $21,035.47 $10,640.00 $10,395.47 $333.20 1.6%
1000 350,000 $25,861.02 $13,300.00 $12,561.02 $26,277.52 $13,300.00 $12,977.52 $416.50 1.6%
1500 525,000 $38,757.90 $19,950.00 $18,807.90 $39,382.65 $19,950.00 $19,432.65 $624.75 1.6%
3000 1,050,000 $77,448.52 $39,900.00 $37,548.52 $78,698.02 $39,900.00 $38,798.02 $1,249.50 1.6%
Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $67.27 Customer Charge $67.27
Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63
Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00
Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183
Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000
Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 20 of 22
Impact on G-3 Rate Customers
Hours Use: 400
KWh Split: - On Peak 45%
- Off Peak 55%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 240,000 $17,301.31 $9,120.00 $8,181.31 $17,586.91 $9,120.00 $8,466.91 $285.60 1.7%
800 320,000 $23,045.99 $12,160.00 $10,885.99 $23,426.79 $12,160.00 $11,266.79 $380.80 1.7%
1000 400,000 $28,790.67 $15,200.00 $13,590.67 $29,266.67 $15,200.00 $14,066.67 $476.00 1.7%
1500 600,000 $43,152.37 $22,800.00 $20,352.37 $43,866.37 $22,800.00 $21,066.37 $714.00 1.7%
3000 1,200,000 $86,237.47 $45,600.00 $40,637.47 $87,665.47 $45,600.00 $42,065.47 $1,428.00 1.7%
Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $67.27 Customer Charge $67.27
Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63
Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00
Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183
Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000
Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 21 of 22
Impact on G-3 Rate Customers
Hours Use: 450
KWh Split: - On Peak 45%
- Off Peak 55%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 270,000 $19,183.32 $10,260.00 $8,923.32 $19,504.62 $10,260.00 $9,244.62 $321.30 1.7%
800 360,000 $25,555.33 $13,680.00 $11,875.33 $25,983.73 $13,680.00 $12,303.73 $428.40 1.7%
1000 450,000 $31,927.35 $17,100.00 $14,827.35 $32,462.85 $17,100.00 $15,362.85 $535.50 1.7%
1500 675,000 $47,857.38 $25,650.00 $22,207.38 $48,660.63 $25,650.00 $23,010.63 $803.25 1.7%
3000 1,350,000 $95,647.50 $51,300.00 $44,347.50 $97,254.00 $51,300.00 $45,954.00 $1,606.50 1.7%
Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $67.27 Customer Charge $67.27
Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63
Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00
Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183
Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000
Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
New England Electric System Eastern Utilities Associates
Eastern Edison Company M.D.T.E Docket No. 99-______
Calculation of Monthly Typical Bill Exhibit TMB-11
Page 22 of 22
Impact on G-3 Rate Customers
Hours Use: 500
KWh Split: - On Peak 45%
- Off Peak 55%
Projected January 1, 2001 Rates Proposed Combined 2001 Rates Increase (Decrease)
Monthly Standard Retail Standard Retail
KW KWh Total Service Delivery Total Service Delivery Amount %
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 300,000 $21,065.32 $11,400.00 $9,665.32 $21,422.32 $11,400.00 $10,022.32 $357.00 1.7%
800 400,000 $28,064.67 $15,200.00 $12,864.67 $28,540.67 $15,200.00 $13,340.67 $476.00 1.7%
1000 500,000 $35,064.02 $19,000.00 $16,064.02 $35,659.02 $19,000.00 $16,659.02 $595.00 1.7%
1500 750,000 $52,562.40 $28,500.00 $24,062.40 $53,454.90 $28,500.00 $24,954.90 $892.50 1.7%
3000 1,500,000 $105,057.52 $57,000.00 $48,057.52 $106,842.52 $57,000.00 $49,842.52 $1,785.00 1.7%
Projected January 1, 2001 Rates: G-3 Proposed Combined 2001 Rates G-3
<S> <C> <C> <C> <C> <C>
Customer Charge $67.27 Customer Charge $67.27
Distribution Demand Charge KWh x $3.63 Distribution Demand Charge KWh x $3.63
Distribution Charge: On Peak KWh x $0.01183 Transition Demand Charge KWh x $0.00
Distribution Charge: Off Peak KWh x $0.00000 Distribution Charge: On Peak KWh x $0.01183
Transition Charge KWh x $0.01070 Distribution Charge: Off Peak KWh x $0.00000
Transmission Charge KWh x $0.00501 Transition Charge KWh x $0.01250
DSM Charge KWh x $0.00270 Transmission Charge KWh x $0.00440
Renewables Charge KWh x $0.00100 DSM Charge KWh x $0.00270
Renewables Charge KWh x $0.00100
Supplier Services Supplier Services
Standard Service Charge KWh x $0.03800 Standard Service Charge KWh x $0.03800
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit TMB-12
Eastern Edison Company
Total Municipal Revenue Analysis
<PAGE>
S:\RADATA1\EASTED\2001\Munireva.wk4 New England Electric System
MUNI SUMMARY Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No 99-___
Exhibit TMB-12, Revised
Page 1 of 1
Eastern Edison Company
Impact on Municipal Retail Delivery Service Billings
For All Municipal Accounts, Including Lighting
Retail Delivery Service Revenue on
----------------------------------
Eastern's Mass. Electric's
Year 2001 Year 2001 Increase/
Town Rates Rates (Decrease) %
---- ----- ----- ---------- -
(1) (2) (3) (4)
Abington $195,919 $187,756 ($8,163) -4.2%
Avon $126,864 $142,726 $15,862 12.5%
Bridgewater $355,989 $321,141 ($34,848) -9.8%
Brockton $1,959,706 $1,775,505 ($184,201) -9.4%
Cohasset $170,822 $162,741 ($8,081) -4.7%
Dighton $159,073 $145,216 ($13,857) -8.7%
East Bridgewater $246,924 $223,014 ($23,910) -9.7%
Easton $426,248 $370,346 ($55,902) -13.1%
Fall River $2,179,500 $1,945,967 ($233,533) -10.7%
Halifax $66,499 $61,249 ($5,250) -7.9%
Hanover $267,408 $219,716 ($47,692) -17.8%
Hanson $146,252 $135,841 ($10,411) -7.1%
(a) Hingham $392 $516 $124 31.6%
Norwell $193,825 $179,413 ($14,412) -7.4%
Pembroke $542,509 $439,262 ($103,247) -19.0%
Rockland $334,890 $299,326 ($35,564) -10.6%
Scituate $342,826 $338,278 ($4,548) -1.3%
Somerset $456,831 $428,068 ($28,763) -6.3%
Stoughton $419,560 $392,212 ($27,348) -6.5%
Swansea $246,760 $254,262 $7,502 3.0%
West Bridgewater $119,102 $114,854 ($4,248) -3.6%
(a) Westport $5,370 $6,305 $935 17.4%
Whitman $150,698 $151,558 $860 0.6%
---------- ---------- ---------
$9,113,967 $8,295,272 ($818,695) -9.0%
========== ========== =========
(1) Billing determinants of municipal accounts priced at Eastern's rates
in 2001 as projected
(2) Billing determinants of municipal accounts priced at Mass. Electric's
proposed rates in 2001 as proposed
(3) Column (2) - Column(1)
(4) Column (3) / Column (1)
(a) Municipality only has lighting service through Eastern.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Workpaper TMB-1
Eastern Edison Company Detail
Supporting Revenue Impact
<PAGE>
<TABLE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: R1 TO R1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 1 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
R-1 to R-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
R-1 to R-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 1,705,214 $1.34 $2,284,987 $5.81 $9,907,293
2 Interruptible Credit #1 ($5.50) $0
3 Interruptible Credit #2 ($7.50) $0
4 Total kWh 897,383,838
Distribution Charge 897,383,838 $0.03556 $31,910,969 $0.02502 $22,452,544
Transmission Charge 897,383,838 $0.00291 $2,611,387 $0.00571 $5,124,062
Transition Charge 897,383,838 $0.02300 $20,639,828 $0.01250 $11,217,298
Standard Service Charge 897,383,838 $0.03800 $34,100,586 $0.03800 $34,100,586
DSM/Renewables Charge 897,383,838 $0.00370 $3,320,320 $0.00370 $3,320,320
----------- -----------
5 Total Revenue $94,868,077 $86,122,102
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 1,705,214
Interruptible Credit #1 0
Interruptible Credit #2 0
KWh 897,383,838
2 Total Design EEC Rates $94,868,077
Revenue: MECO 3/1/99 Rates $86,122,102
3 Increase (Decrease) in Total Revenue ($8,745,975)
-9.22%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($1,836,119) $34,195,956 $32,359,837
Transmission $2,512,675 $2,611,387 $5,124,062
Transition ($9,422,530) $20,639,828 $11,217,298
Standard Service $0 $34,100,586 $34,100,586
DSM/Renewables $0 $3,320,320 $3,320,320
---
($8,745,975)
==================================================================================================================================
Sources:
Distribution Charges:Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: R2 TO R2 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 2 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
R-2 to R-2
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
R-2 to R-2 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 168,433 $0.87 $146,537 $3.77 $634,992
2 Interruptible Credit #1 8,636 ($5.50) ($47,498)
3 Interruptible Credit #2 ($7.50) $0
4 Total kWh 67,148,463
Distribution Charge 67,148,463 $0.00579 $388,790 $0.00463 $310,897
Transmission Charge 67,148,463 $0.00291 $195,402 $0.00571 $383,418
Transition Charge 67,148,463 $0.02300 $1,544,415 $0.01250 $839,356
Standard Service Charge 67,148,463 $0.03800 $2,551,642 $0.03800 $2,551,642
DSM/Renewables Charge 67,148,463 $0.00370 $248,449 $0.00370 $248,449
--------- --------
5 Total Revenue $5,075,234 $4,921,256
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 168,433
Interruptible Credit #1 8,636
Interruptible Credit #2 0
KWh 67,148,463
2 Total Design RevenEEC Rates $5,075,234
MECO 3/1/99 Rates $4,921,256
3 Increase (Decrease) in Total Revenue ($153,978)
-3.03%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $363,065 $535,326 $898,391
Transmission $188,016 $195,402 $383,418
Transition ($705,059) $1,544,415 $839,356
Standard Service $0 $2,551,642 $2,551,642
DSM/Renewables $0 $248,449 $248,449
---
($153,978)
==================================================================================================================================
Sources:
Distribution Eastern Edison: Currently Effective Tariffs
Charges: Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: R3 TO R1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 3 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
R-3 to R-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
R-3 to R-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 70,418 $1.79 $126,048 $5.81 $409,129
2 Total kWh 70,618,533
Distribution Charge 70,618,533 $0.02422 $1,710,381 $0.02502 $1,766,876
Transmission Charge 70,618,533 $0.00291 $205,500 $0.00571 $403,232
Transition Charge 70,618,533 $0.02300 $1,624,226 $0.01250 $882,732
Standard Service Charge 70,618,533 $0.03800 $2,683,504 $0.03800 $2,683,504
DSM/Renewables Charge 70,618,533 $0.00370 $261,289 $0.00370 $261,289
--------- ---------
3 Total Revenue $6,610,948 $6,406,761
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 70,418
KWh 70,618,533
2 Total Design RevenEEC Rates $6,610,948
MECO 3/1/99 Rates $6,406,761
3 Increase (Decrease) in Total Revenue ($204,187)
-3.09%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $339,576 $1,836,429 $2,176,005
Transmission $197,732 $205,500 $403,232
Transition ($741,495) $1,624,226 $882,732
Standard Service $0 $2,683,504 $2,683,504
DSM/Renewables $0 $261,289 $261,289
---
($204,187)
==================================================================================================================================
Sources:
Distribution Eastern Edison: Currently Effective Tariffs
Charges: Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: R4 TO R1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 4 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
R-4 to R-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
R-4 to R-1 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 544 $7.93 $4,314 544 $5.81 $3,161
2 Total kWh 577,111 577,111
Distribution Charge 577,111 $0.01690 $9,753 577,111 $0.02502 $14,439
Transmission Charge 577,111 $0.00291 $1,679 577,111 $0.00571 $3,295
Transition Charge-On Peak 82,953 $0.10899 $9,041 577,111 $0.01250 $7,214
Transition Charge-Off Peak 494,158 $0.00872 $4,309 $0
Standard Service Charge 577,111 $0.03800 $21,930 577,111 $0.03800 $21,930
DSM/Renewables Charge 577,111 $0.00370 $2,135 577,111 $0.00370 $2,135
------- ------
3 Total Revenue $53,162 $52,175
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 544 544
On Peak kWh 82,953 577,111
Off Peak kWh 494,158 0
-------- -------
Total kWh 577,111 577,111
2 Total Design EEC Rates $53,162
Revenue MECO 3/1/99 Rates $52,175
3 Increase (Decrease) in Total Revenue ($987)
-1.86%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $3,533 $14,067 $17,600
Transmission $1,616 $1,679 $3,295
Transition ($6,136) $13,350 $7,214
Standard Service $0 $21,930 $21,930
DSM/Renewables $0 $2,135 $2,135
---
($987)
==================================================================================================================================
Sources:
Distribution Charges:Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: W1 TO R1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 5 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
W-1 to R-1
============================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
W-1 to R-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
============================================================================================================
Section 1: Revenue Calculation
<S> <C> <C> <C> <C> <C>
1 Customer Charge 186,554 $0.90 $167,899 $5.81 $1,083,879
2 Interruptible Credit #1 186,554 ($5.50) ($1,026,047)
3 Interruptible Credit #2 ($7.50) $0
4 Total kWh 48,697,330
Distribution Charge 48,697,330 $0.02343 $1,140,978 $0.02502 $1,218,407
Transmission Charge 48,697,330 $0.00291 $141,709 $0.00571 $278,062
Transition Charge 48,697,330 $0.02300 $1,120,039 $0.01250 $608,717
Standard Service Charge 48,697,330 $0.03800 $1,850,499 $0.03800 $1,850,499
DSM/Renewables Charge 48,697,330 $0.00370 $180,180 $0.00370 $180,180
--------- ----------
5 Total Revenue $4,601,304 $4,193,696
==========================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 186,554
Interruptible Credit #1 186,554
Interruptible Credit #2 0
KWh 48,697,330
2 Total Design EEC Rates $4,601,304
Revenue: MECO 3/1/99 Rates $4,193,696
3 Increase (Decrease) in Total Revenue ($407,607)
-8.86%
Component
Inc/(Dec)
----------
4 Revenue by Component
Distribution ($32,638) $1,308,877 $1,276,239
Transmission $136,353 $141,709 $278,062
Transition ($511,322) $1,120,039 $608,717
Standard Service $0 $1,850,499 $1,850,499
DSM/Renewables $0 $180,180 $180,180
($407,607)
==========================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge: Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G1 TO G1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 6 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-1 to G-1
===================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
G-1 to G-1 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
===================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 213,705 $1.34 $286,365 199,662 $8.32 $1,661,188
2 Location Charge 14,043 $6.48 $90,999
3 Total kWh 109,098,086 109,098,086
Distribution Charge 109,098,086 $0.04260 $4,647,578 109,098,086 $0.03843 $4,192,639
Transmission Charge 109,098,086 $0.00291 $317,475 109,098,086 $0.00568 $619,677
Transition Charge 109,098,086 $0.02300 $2,509,256 109,098,086 $0.01250 $1,363,726
Standard Service Charge 109,098,086 $0.03800 $4,145,727 109,098,086 $0.03800 $4,145,727
DSM/Renewables Charge 109,098,086 $0.00370 $403,663 109,098,086 $0.00370 $403,663
--------- ---------
4 Total Revenue $12,310,065 $12,477,619
===================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 213,705
Location Charge 0
KWh 109,098,086
2 Total Design RevenEEC Rates $12,310,065
MECO 3/1/99 Rates $12,477,619
3 Increase (Decrease) in Total Revenue $167,554
1.36%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $1,010,883 $4,933,943 $5,944,826
Transmission $302,202 $317,475 $619,677
Transition ($1,145,530) $2,509,256 $1,363,726
Standard Service ($0) $4,145,727 $4,145,727
DSM/Renewables $0 $403,663 $403,663
---
$167,554
===================================================================================================================================
Sources:
Distribution Charges:Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G2 TO G1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 7 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-2 to G-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
G-2 to G-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 61,760 $7.24 $447,142 $8.32 $513,843
2 Demand Charge
Distribution Charge 1,041,483 $2.83 $2,947,397 $0.00 $0
Transition Charge 1,041,483 $6.07 $6,321,802 $0.00 $0
------ ----------- ------ --
Total $8.90 $9,269,199 $0.00 $0
----------- --
3 Total Customer & Demand Revenues $9,716,341 $513,843
4 Total kWh 241,828,775
Distribution Charge 241,828,775 $0.01393 $3,368,675 $0.03843 $9,293,480
Transmission Charge 241,828,775 $0.00291 $703,722 $0.00568 $1,373,587
Transition Charge 241,828,775 $0.00198 $478,821 $0.01250 $3,022,860
Standard Service Charge 241,828,775 $0.03800 $9,189,493 $0.03800 $9,189,493
DSM/Renewables Charge 241,828,775 $0.00370 $894,766 $0.00370 $894,766
--------- --------
5 Total Revenue $24,351,819 $24,288,030
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 61,760
KW: 1,041,483
KWh 241,828,775
2 Total Design RevenEEC Rates $24,351,819
MECO 3/1/99 Rates $24,288,030
3 Increase (Decrease) in Total Revenue ($63,789)
-0.26%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $3,044,109 $6,763,214 $9,807,323
Transmission $669,866 $703,722 $1,373,587
Transition ($3,777,763) $6,800,623 $3,022,860
Standard Service $0 $9,189,493 $9,189,493
DSM/Renewables $0 $894,766 $894,766
---
($63,789)
==================================================================================================================================
Sources:
Distribution Charges:Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G2 TO G2 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 8 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-2 to G-2
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
G-2 to G-2 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 18,542 $7.24 $134,244 $15.23 $282,395
2 Demand Charge
Distribution Charge 1,300,741 $2.83 $3,681,097 $5.92 $7,700,387
Transition Charge 1,300,741 $6.07 $7,895,498 $0.00 $0
------ ----------- ------ ----------
Total $8.90 $11,576,595 $5.92 $7,700,387
------------ ----------
3 Total Customer & Demand Revenues $11,710,839 $7,982,782
4 Total kWh 424,245,027
Distribution Charge 424,245,027 $0.01393 $5,909,733 $0.00138 $585,458
Transmission Charge 424,245,027 $0.00291 $1,234,553 $0.00513 $2,176,377
Transition Charge 424,245,027 $0.00198 $840,005 $0.01250 $5,303,063
Standard Service Charge 424,245,027 $0.03800 $16,121,311 $0.03800 $16,121,311
DSM/Renewables Charge 424,245,027 $0.00370 $1,569,707 $0.00370 $1,569,707
----------- -----------
5 Total Revenue $37,386,148 $33,738,697
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 18,542
KW: 1,300,741
KWh 424,245,027
2 Total Design RevenEEC Rates $37,386,148
MECO 3/1/99 Rates $33,738,697
3 Increase (Decrease) in Total Revenue ($3,647,451)
-9.76%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($1,156,834) $9,725,074 $8,568,240
Transmission $941,824 $1,234,553 $2,176,377
Transition ($3,432,440) $8,735,503 $5,303,063
Standard Service $0 $16,121,311 $16,121,311
DSM/Renewables $0 $1,569,707 $1,569,707
------------
($3,647,451)
==================================================================================================================================
Sources:
Distribution Charges:Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G2 TO G3 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 9 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-2 to G-3
===================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
G-2 to G-3 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
===================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 1,794 $7.24 $12,989 1,794 $67.27 $120,682
2 Demand Charge
Distribution Charge 508,532 $2.83 $1,439,146 513,617 $3.63 $1,864,430
Transition Charge 508,532 $6.07 $3,086,789 513,617 $0.00 $0
------ ----------- ------ -----------
Total $8.90 $4,525,935 $3.63 $1,864,430
----------- -----------
3 Total Customer & Demand Revenues $4,538,923 $1,985,112
4 Total kWh 173,540,944 173,540,944
Distribution Charge: On Peak 173,540,944 $0.01393 $2,417,425 86,770,472 $0.01183 $1,026,495
Distribution Charge: Off Peak $0 86,770,472 $0.00000 $0
Transmission Charge 173,540,944 $0.00291 $505,004 173,540,944 $0.00460 $798,288
Transition Charge 173,540,944 $0.00198 $343,611 173,540,944 $0.01250 $2,169,262
Standard Service Charge 173,540,944 $0.03800 $6,594,556 173,540,944 $0.03800 $6,594,556
DSM/Renewables Charge 173,540,944 $0.00370 $642,101 173,540,944 $0.00370 $642,101
----------- ---------
5 Total Revenue $15,041,621 $13,215,814
===================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 1,794 1,794
KW 508,532 513,617
On Peak kWh 86,770,472
Off Peak kWh 86,770,472
Total kWh 173,540,944 173,540,944
2 Total Design RevenEEC Rates $15,041,621
MECO 3/1/99 Rates $13,215,814
3 Increase (Decrease) in Total Revenue ($1,825,807)
-12.14%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($857,953) $3,869,559 $3,011,607
Transmission $293,284 $505,004 $798,288
Transition ($1,261,139) $3,430,400 $2,169,262
Standard Service $0 $6,594,556 $6,594,556
DSM/Renewables $0 $642,101 $642,101
---
($1,825,807)
===================================================================================================================================
Sources:
Distribution Charges:Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Eastern Edison: Settlement Agreement
Charges: Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G4 TO G3 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 10 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-4 to G-3
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
G-4 to G-3 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 1,097 $17.82 $19,549 1,097 $67.27 $73,795
2 Demand Charge Distribution Charge 794,802 $2.81 $2,233,394 822,620 $3.63 $2,986,111
Transition Charge 794,802 $6.04 $4,800,604 822,620 $0.00 $0
------ ----------- ------ ----------
Total $8.85 $7,033,998 $3.63 $2,986,111
----------- ----------
3 Total Customer & Demand Revenues $7,053,546 $3,059,906
4 Total kWh 344,807,994 344,807,994
Distribution Charge: On Peak 344,807,994 $0.00657 $2,265,389 162,059,757 $0.01183 $1,917,167
Distribution Charge: Off Peak $0.00657 $0 182,748,237 $0.00000 $0
Transmission Charge 344,807,994 $0.00291 $1,003,391 344,807,994 $0.00460 $1,586,117
Transition Charge: On Peak 76,958,311 $0.01352 $1,040,476 162,059,757 $0.01250 $2,025,747
Transition Charge: Off Peak 267,849,683 $0.00740 $1,982,088 182,748,237 $0.01250 $2,284,353
Standard Service Charge 344,807,994 $0.03800 $13,102,704 344,807,994 $0.03800 $13,102,704
DSM/Renewables Charge 344,807,994 $0.00370 $1,275,790 344,807,994 $0.00370 $1,275,790
----------- ----------
5 Total Revenue $27,723,383 $25,251,783
===================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 1,097 1,097
KW 794,802 822,620
On Peak kWh 76,958,311 162,059,757
Off Peak kWh 267,849,683 182,748,237
------------ -----------
Total kWh 344,807,994 344,807,994
2 Total Design Revenue:EEC Rates $27,723,383
MECO 3/1/99 Rates $25,251,783
3 Increase (Decrease) in Total Revenue ($2,471,600)
-8.92%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $458,742 $4,518,331 $4,977,073
Transmission $582,726 $1,003,391 $1,586,117
Transition ($3,513,068) $7,823,168 $4,310,100
Standard Service $0 $13,102,704 $13,102,704
DSM/Renewables $0 $1,275,790 $1,275,790
---
($2,471,600)
===================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G5 TO G2 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 11 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-5 to G-2
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
G-5 to G-2 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 168 $43.87 $7,370 168 $15.23 $2,559
2 Demand Charge Distribution Charge 20,285 $2.22 $45,033 21,096 $5.92 $124,888
Transition Charge 20,285 $4.78 $96,962 21,096 $0.00 $0
------ -------- ------ --------
Total $7.00 $141,995 $5.92 $124,888
--------- --------
3 Total Customer & Demand Revenues $149,365 $127,447
4 Total kWh 7,126,400 7,126,400
Distribution Charge 7,126,400 $0.01324 $94,354 7,126,400 $0.00138 $9,834
Transmission Charge 7,126,400 $0.00291 $20,738 7,126,400 $0.00513 $36,558
Transition Charge: On Peak 1,672,460 $0.01318 $22,043 7,126,400 $0.01250 $89,080
Transition Charge: Off Peak 5,453,940 $0.00766 $41,777
Standard Service Charge 7,126,400 $0.03800 $270,803 7,126,400 $0.03800 $270,803
DSM/Renewables Charge 7,126,400 $0.00370 $26,368 7,126,400 $0.00370 $26,368
-------- -------
5 Total Bill $625,448 $560,091
6 High Voltage Metering @ -1%
Distribution -1.00% ($5,235)
Transmission -1.00% ($366)
--------
Total ($5,601)
7 High Voltage Delivery @ -$.45 20,285 21,096 ($0.45) ($9,493)
--------
8 Total Revenue $625,448 $544,997
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 168 168
KW 20,285 21,096
On Peak kWh 1,672,460
Off Peak kWh 5,453,940
Total kWh 7,126,400 7,126,400
2 Total Design Revenue:EEC Rates $625,448
MECO 3/1/99 Rates $544,997
3 Increase (Decrease) in Total Revenue ($80,451)
-12.86%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($24,203) $146,756 $122,553
Transmission $15,455 $20,738 $36,193
Transition ($71,703) $160,783 $89,080
Standard Service $0 $270,803 $270,803
DSM/Renewables $0 $26,368 $26,368
---
($80,451)
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G5 TO G3 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 12 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-5 to G-3
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
G-5 to G-3 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 234 $43.87 $10,266 234 $67.27 $15,741
2 Demand Charge Distribution Charge 55,906 $2.22 $124,111 60,155 $3.63 $218,363
Transition Charge 55,906 $4.78 $267,231 60,155 $0.00 $0
------ --------- ------ --------
Total $7.00 $391,342 $3.63 $218,363
--------- --------
3 Total Customer & Demand Revenues $401,608 $234,104
4 Total kWh 18,249,760 18,249,760
Distribution Charge: On Peak 18,249,760 $0.01324 $241,627 9,672,373 $0.01183 $114,424
Distribution Charge: Off Peak 8,577,387 $0.00000 $0
Transmission Charge 18,249,760 $0.00291 $53,107 18,249,760 $0.00460 $83,949
Transition Charge: On Peak 4,643,330 $0.01318 $61,199 9,672,373 $0.01250 $120,905
Transition Charge: Off Peak 13,606,430 $0.00766 $104,225 8,577,387 $0.01250 $107,217
Standard Service Charge 18,249,760 $0.03800 $693,491 18,249,760 $0.03800 $693,491
DSM/Renewables Charge 18,249,760 $0.00370 $67,524 18,249,760 $0.00370 $67,524
-------- -------
5 Total Bill $1,622,781 $1,421,614
6 High Voltage Metering @ -1%
Distribution -1.00% ($13,377)
Transmission -1.00% ($839)
------
Total ($14,216)
7 High Voltage Delivery @ -$.45 55,906 60,155 ($0.45) ($27,070)
---------
8 Total Revenue $1,622,781 $1,380,328
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 234 234
KW 55,906 60,155
On Peak kWh 4,643,330 9,672,373
Off Peak kWh 13,606,430 8,577,387
----------- ---------
Total kWh 18,249,760 18,249,760
2 Total Design Revenue:EEC Rates $1,622,781
MECO 3/1/99 Rates $1,380,328
3 Increase (Decrease) in Total Revenue ($242,452)
-14.94%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($67,922) $376,004 $308,082
Transmission $30,003 $53,107 $83,109
Transition ($204,533) $432,655 $228,122
Standard Service $0 $693,491 $693,491
DSM/Renewables $0 $67,524 $67,524
---
($242,452)
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: G6 TO G3 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 13 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
G-6 to G-3
===================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
G-6 to G-3 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
===================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 380 $43.87 $16,671 380 $67.27 $25,563
2 Demand Charge Distribution Charge 439,150 $2.22 $974,913 513,806 $3.63 $1,865,116
Transition Charge 439,150 $4.78 $2,099,137 513,806 $0.00 $0
------ ----------- ------ ----------
Total $7.00 $3,074,050 $3.63 $1,865,116
----------- ----------
3 Total Customer & Demand Revenues $3,090,721 $1,890,679
4 Total kWh 194,448,972 194,448,972
Distribution Charge: On Peak 194,448,972 $0.00839 $1,631,427 85,557,548 $0.01183 $1,012,146
Distribution Charge: Off Peak 108,891,424 $0.00000 $0
Transmission Charge 194,448,972 $0.00291 $565,847 194,448,972 $0.00460 $894,465
Transition Charge: On Peak 38,898,442 $0.01679 $653,105 85,557,548 $0.01250 $1,069,469
Transition Charge: Off Peak 155,550,530 $0.01127 $1,753,054 108,891,424 $0.01250 $1,361,143
Standard Service Charge 194,448,972 $0.03800 $7,389,061 194,448,972 $0.03800 $7,389,061
DSM/Renewables Charge 194,448,972 $0.00370 $719,461 194,448,972 $0.00370 $719,461
--------- ----------
5 Total Bill $15,802,675 $14,336,424
6 High Voltage Metering @ -1%
Distribution -1.00% ($134,420)
Transmission -1.00% ($8,945)
--------
Total ($143,364)
7 High Voltage Delivery @ -$.45 439,150 513,806 ($0.45) ($231,213)
----------
8 Total Revenue $15,802,675 $13,961,847
===================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 380 380
KW 439,150 513,806
On Peak kWh 38,898,442 85,557,548
Off Peak kWh 155,550,530 108,891,424
------------ ------------
Total kWh 194,448,972 194,448,972
2 Total Design Revenue:EEC Rates $15,802,675
MECO 3/1/99 Rates $13,961,847
3 Increase (Decrease) in Total Revenue ($1,840,828)
-11.65%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($85,818) $2,623,010 $2,537,193
Transmission $319,674 $565,847 $885,521
Transition ($2,074,684) $4,505,296 $2,430,612
Standard Service $0 $7,389,061 $7,389,061
DSM/Renewables $0 $719,461 $719,461
---
($1,840,828)
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: T2 TO G1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 14 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
T-2 to G-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
T-2 to G-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 297 $12.84 $3,813 $8.32 $2,471
2 Demand Charge
Distribution Charge 4,390 $2.92 $12,819 $0.00 $0
Transition Charge 4,390 $6.29 $27,613 $0.00 $0
------ -------- ------ --
Total $9.21 $40,432 $0.00 $0
-------- --
3 Total Customer & Demand Revenues $44,245 $2,471
4 Total kWh 1,178,927
Distribution Charge 1,178,927 $0.00231 $2,723 $0.03843 $45,306
Transmission Charge 1,178,927 $0.00291 $3,431 $0.00568 $6,696
Transition Charge: On Peak 205,124 $0.01536 $3,151 $0.01250 $2,564
Transition Charge: Off Peak 973,803 $0.00923 $8,988 $0.01250 $12,173
Standard Service Charge 1,178,927 $0.03800 $44,799 $0.03800 $44,799
DSM/Renewables Charge 1,178,927 $0.00370 $4,362 $0.00370 $4,362
------- -------
5 Total Revenue $111,700 $118,371
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 297
KW 4,390
KWh 1,178,927
2 Total Design Revenue:EEC Rates $111,700
MECO 3/1/99 Rates $118,371
3 Increase (Decrease) in Total Revenue $6,672
5.97%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $28,422 $19,356 $47,777
Transmission $3,266 $3,431 $6,696
Transition ($25,015) $39,752 $14,737
Standard Service $0 $44,799 $44,799
DSM/Renewables $0 $4,362 $4,362
---
$6,672
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: T2 TO G2 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 15 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
T-2 to G-2
================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
T-2 to G-2 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
===============================================================================================================================
Section 1: Revenue Calculation
<S> <C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 554 $12.84 $7,113 554 $15.23 $8,437
2 Demand Charge
Distribution Charge 42,478 $2.92 $124,036 45,027 $5.92 $266,560
Transition Charge 42,478 $6.29 $267,187 45,027 $0.00 $0
------ --------- ------ --
Total $9.21 $391,222 $5.92 $266,560
--------- --------
3 Total Customer & Demand Revenues $398,336 $274,997
4 Total kWh 18,743,578 18,743,578
Distribution Charge 18,743,578 $0.00231 $43,298 18,743,578 $0.00138 $25,866
Transmission Charge 18,743,578 $0.00291 $54,544 18,743,578 $0.00513 $96,155
Transition Charge: On Peak 3,623,614 $0.01536 $55,659 18,743,578 $0.01250 $234,295
Transition Charge: Off Peak 15,119,964 $0.00923 $139,557
Standard Service Charge 18,743,578 $0.03800 $712,256 18,743,578 $0.03800 $712,256
DSM/Renewables Charge 18,743,578 $0.00370 $69,351 18,743,578 $0.00370 $69,351
-------- ----------- -------
5 Total Revenue $1,473,000 $1,412,919
================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 554
KW 42,478
KWh 18,743,578
2 Total Design Revenue: EEC Rates $1,473,000
MECO 3/1/99 Rates $1,412,919
3 Increase (Decrease) in Total Revenue ($60,081)
-4.08%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $126,416 $174,447 $300,863
Transmission $41,611 $54,544 $96,155
Transition ($228,108) $462,403 $234,295
Standard Service $0 $712,256 $712,256
DSM/Renewables $0 $69,351 $69,351
---
($60,081)
=================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge: Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: T2 TO G3 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 16 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
T-2 to G-3
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
T-2 to G-3 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 348 $12.84 $4,468 348 $67.27 $23,410
2 Demand Charge
Distribution Charge 108,745 $2.92 $317,535 111,790 $3.63 $405,798
Transition Charge 108,745 $6.29 $684,006 111,790 $0.00 $0
------ ---------- ------ --------
Total $9.21 $1,001,541 $3.63 $405,798
---------- --------
3 Total Customer & Demand Revenues $1,006,010 $429,208
4 Total kWh 53,151,417 53,151,417
Distribution Charge: On Peak 53,151,417 $0.00231 $122,780 22,323,595 $0.01183 $264,088
Distribution Charge: Off Peak $0 30,827,822 $0.00000 $0
Transmission Charge 53,151,417 $0.00291 $154,671 53,151,417 $0.00460 $244,497
Transition Charge: On Peak 10,316,557 $0.01536 $158,462 22,323,595 $0.01250 $279,045
Transition Charge: Off Peak 42,834,860 $0.00923 $395,366 30,827,822 $0.01250 $385,348
Standard Service Charge 53,151,417 $0.03800 $2,019,754 53,151,417 $0.03800 $2,019,754
DSM/Renewables Charge 53,151,417 $0.00370 $196,660 53,151,417 $0.00370 $196,660
--------- --------
5 Total Revenue $4,053,702 $3,818,599
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 348 348
KW 108,745 111,790
On Peak kWh 10,316,557 22,323,595
Off Peak kWh 42,834,860 30,827,822
----------- ----------
Total kWh 53,151,417 53,151,417
2 Total Design Revenue:EEC Rates $4,053,702
MECO 3/1/99 Rates $3,818,599
3 Increase (Decrease) in Total Revenue ($235,103)
-5.80%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $248,512 $444,783 $693,296
Transmission $89,826 $154,671 $244,497
Transition ($573,441) $1,237,834 $664,393
Standard Service $0 $2,019,754 $2,019,754
DSM/Renewables $0 $196,660 $196,660
-----------
($235,103)
=================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: H1 TO G1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 17 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
H-1 to G-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
H-1 to G-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Rate Design
<C> <C> <C> <C> <C> <C>
1 Customer Charge 1,231 $5.39 $6,635 $8.32 $10,242
2 Location Charge $6.48 $0
3 Total kWh 2,545,293
Distribution Charge 2,545,293 $0.02669 $67,934 $0.03843 $97,816
Transmission Charge 2,545,293 $0.00291 $7,407 $0.00568 $14,457
Transition Charge 2,545,293 $0.02300 $58,542 $0.01250 $31,816
Standard Service Charge 2,545,293 $0.03800 $96,721 $0.03800 $96,721
DSM/Renewables Charge 2,545,293 $0.00370 $9,418 $0.00370 $9,418
------- ------
4 Total Revenue $246,656 $260,470
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 1,231
Location Charge 0
KWh 2,545,293
2 Total Design Revenue:EEC Rates $246,656
MECO 3/1/99 Rates $260,470
3 Increase (Decrease) in Total Revenue $13,814
5.60%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $33,489 $74,569 $108,058
Transmission $7,050 $7,407 $14,457
Transition ($26,726) $58,542 $31,816
Standard Service $0 $96,721 $96,721
DSM/Renewables $0 $9,418 $9,418
---
$13,814
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: H1 TO G2 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 18 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
H-1 to G-2
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
H-1 to G-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 35 $5.39 $189 35 $15.23 $533
2 Demand Charge
Distribution Charge 3,427 $0.00 $0 3,427 $5.92 $20,288
Transition Charge 3,427 $0.00 $0 3,427 $0.00 $0
Total $0.00 $0 $5.92 $20,288
3 Total Customer & Demand Revenues $189 $20,821
4 Total kWh 704,880 704,880
Distribution Charge 704,880 $0.02669 $18,813 704,880 $0.00138 $973
Transmission Charge 704,880 $0.00291 $2,051 704,880 $0.00513 $3,616
Transition Charge 704,880 $0.02300 $16,212 704,880 $0.01250 $8,811
Standard Service Charge 704,880 $0.03800 $26,785 704,880 $0.03800 $26,785
DSM/Renewables Charge 704,880 $0.00370 $2,608 704,880 $0.00370 $2,608
5 Total Revenue $66,659 $63,614
===================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 35
KW 3,427
KWh 704,880
2 Total Design RevEECeRates $66,659
MECO 3/1/99 Rates $63,614
3 Increase (Decrease) in Total Revenue ($3,045)
-4.57%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $2,792 $19,002 $21,794
Transmission $1,565 $2,051 $3,616
Transition ($7,401) $16,212 $8,811
Standard Service $0 $26,785 $26,785
DSM/Renewables $0 $2,608 $2,608
($3,045)
==================================================================================================================================
Sources:
Distribution ChargeEastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission ChargeEastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges:Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service ChEastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables:Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: H1 TO G3 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 19 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
H-1 to G-3
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
H-1 to G-3 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C> <C>
1 Customer Charge 48 $5.39 $259 48 $67.27 $3,229
2 Demand Charge
Distribution Charge 34,790 $0.00 $0 38,617 $3.63 $140,180
Transition Charge 34,790 $0.00 $0 38,617 $0.00 $0
------ --- ------ --
Total $0.00 $0 $3.63 $140,180
--- --------
3 Total Customer & Demand Revenues $259 $143,409
4 Total kWh 6,702,200 6,702,200
Distribution Charge: On Peak 6,702,200 $0.02669 $178,882 3,552,166 $0.01183 $42,022
Distribution Charge: Off Peak $0 3,150,034 $0.00000 $0
Transmission Charge 6,702,200 $0.00291 $19,503 6,702,200 $0.00460 $30,830
Transition Charge 6,702,200 $0.02300 $154,151 6,702,200 $0.01250 $83,778
Standard Service Charge 6,702,200 $0.03800 $254,684 6,702,200 $0.03800 $254,684
DSM/Renewables Charge 6,702,200 $0.00370 $24,798 6,702,200 $0.00370 $24,798
-------- -------
5 Total Revenue $632,276 $579,520
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 48 48
KW 34,790 38,617
On Peak kWh 3,552,166
Off Peak kWh 3,150,034
---------
Total kWh 6,702,200 6,702,200
2 Total Design Revenue:EEC Rates $632,276
MECO 3/1/99 Rates $579,520
3 Increase (Decrease) in Total Revenue ($52,756)
-8.34%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $6,291 $179,140 $185,431
Transmission $11,327 $19,503 $30,830
Transition ($70,373) $154,151 $83,778
Standard Service $0 $254,684 $254,684
DSM/Renewables $0 $24,798 $24,798
---
($52,756)
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: H2 TO G1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 20 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
H-2 to G-1
==================================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
H-2 to G-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==================================================================================================================================
Section 1: Revenue Calculation
<C> <C> <C> <C> <C> <C>
1 Customer Charge 1,979 $1.35 $2,672 $8.32 $16,465
2 Location Charge $6.48 $0
3 Total kWh 2,299,322
Distribution Charge 2,299,322 $0.02828 $65,025 $0.03843 $88,363
Transmission Charge 2,299,322 $0.00291 $6,691 $0.00568 $13,060
Transition Charge 2,299,322 $0.02300 $52,884 $0.01250 $28,742
Standard Service Charge 2,299,322 $0.03800 $87,374 $0.03800 $87,374
DSM/Renewables Charge 2,299,322 $0.00370 $8,507 $0.00370 $8,507
------- ------
4 Total Revenue $223,154 $242,511
==================================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 1,979
Location Charge 0
KWh 2,299,322
2 Total Design Revenue:EEC Rates $223,154
MECO 3/1/99 Rates $242,511
3 Increase (Decrease) in Total Revenue $19,358
8.67%
Component
Inc/(Dec)
4 Revenue by Component
Distribution $37,131 $67,696 $104,828
Transmission $6,369 $6,691 $13,060
Transition ($24,143) $52,884 $28,742
Standard Service ($0) $87,374 $87,374
DSM/Renewables $0 $8,507 $8,507
---
$19,358
==================================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge:Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: H2 TO G2 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 21 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
H-2 to G-2
====================================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO MECO
H-2 to G-2 Units Rate Revenues Units Rate Revenues Comments
(1) (2) (3) (4) (5) (6)
====================================================================================================================
Section 1: Revenue Calculation
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge 12 $1.35 $16 12 $15.23 $183
2 Demand Charge
Distribution Charge 496 $0.00 $0 496 $5.92 $2,936
Transition Charge 496 $0.00 $0 496 $0.00 $0
------ --- ------ --
Total $0.00 $0 $5.92 $2,936
--- ------
3 Total Customer & Demand Revenues $16 $3,119
4 Total kWh 135,360 135,360
Distribution Charge 135,360 $0.02828 $3,828 135,360 $0.00138 $187
Transmission Charge 135,360 $0.00291 $394 135,360 $0.00513 $694
Transition Charge 135,360 $0.02300 $3,113 135,360 $0.01250 $1,692
Standard Service Charge 135,360 $0.03800 $5,144 135,360 $0.03800 $5,144
DSM/Renewables Charge 135,360 $0.00370 $501 135,360 $0.00370 $501
----- ----
5 Total Revenue $12,996 $11,337
====================================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 12
On Peak kWh 496
KWh 135,360
2 Total Design EEC Rates $12,996
Revenue: MECO 3/1/99 Rates $11,337
3 Increase (Decrease) in Total Revenue ($1,659)
-12.76%
Component
Inc/(Dec)
4 Revenue by Component
Distribution ($538) $3,844 $3,306
Transmission $301 $394 $694
Transition ($1,421) $3,113 $1,692
Standard Service $0 $5,144 $5,144
DSM/Renewables $0 $501 $501
---
($1,659)
====================================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge: Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges: Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge: Eastern Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables: Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
File: S:\RADATA1\EASTED\2001\01VS01A.WK4 New England Electric System
Range: W1 TO G1 Eastern Utilities Associates
Date: 04-May-99 M.D.T.E. Docket No. 99-__
Time: 09:05 AM Workpaper TMB-1, Revised
Page 22 of 25
Massachusetts Electric Company
Eastern Edison Company
Revenue Analysis for Rate
W-1 to G-1
==========================================================================================================
Estimated Year 2001 Consolidated Year 2001
EEC EEC MECO MECO
W-1 to G-1 Units Rate Revenues Rate Revenues Comments
(1) (2) (3) (4) (5)
==========================================================================================================
Section 1: Revenue Calculation
1 Customer Charge 2,715 $0.90 $2,444 $8.32 $22,589
2 Total kWh 779,421
Distribution Charge 779,421 $0.02343 $18,262 $0.03843 $29,953
Transmission Charge 779,421 $0.00291 $2,268 $0.00568 $4,427
Transition Charge 779,421 $0.02300 $17,927 $0.01250 $9,743
Standard Service Charge 779,421 $0.03800 $29,618 $0.03800 $29,618
DSM/Renewables Charge 779,421 $0.00370 $2,884 $0.00370 $2,884
------- -------
5 Total Revenue $73,402 $99,214
==========================================================================================================
Section 2: Summary
1 Total Units - Number of Bills 2,715
KWh 779,421
2 Total Design EEC Rates $73,402
Revenue: MECO 3/1/99 Rates $99,214
3 Increase (Decrease) in Total Revenue $25,812
35.17%
Component
Inc/(Dec)
---------
4 Revenue by Component
Distribution $31,837 $20,705 $52,542
Transmission $2,159 $2,268 $4,427
Transition ($8,184) $17,927 $9,743
Standard Service ($0) $29,618 $29,618
DSM/Renewables ($0) $2,884 $2,884
---------
$25,812
==========================================================================================================
Sources:
Distribution Charges: Eastern Edison: Currently Effective Tariffs
Mass. Electric: Currently Effective Tariffs
Transmission Charge" Eastern Edison: Workpaper TMB-2
Mass. Electric: Workpaper TBM-3
Transition Charges" Eastern Edison: Workpaper TMB-5
Mass. Electric: Workpaper TMB-4
Standard Service Charge: Eastern:Edison: Settlement Agreement
Mass. Electric: Settlement Agreement
DSM and Renewables" Eastern Edison: Utility Restructuring Act
Mass. Electric: Utility Restructuring Act
<PAGE>
<CAPTION>
Massachusetts Electric Company
Eastern Edison Company
Streetlight Revenue Analysis
EEC EEC EEC
EEC EEC Annual Total EEC Annual
Lighting Lumen Service Special 12/98 kWh Annual Annual Distribution
Code Wattage Size & Pole Type Pricing Quantity per Light kWh Price Revenue
-------- ------- ------ -------- ---- ------- -------- --------- ------ ------ ------------
METAL HALIDE
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
3004120 250 20,000 OH_WoodLine FldLt 9 1,180 10,620 $98.66 $888
3004220 250 20,000 OH_WoodLitg FldLt 2 1,180 2,360 $188.89 $378
4664120 400 40,000 OH_WoodLine FldLt 39 1,832 71,448 $138.15 $5,388
10804120 1,000 115,000 OH_WoodLine FldLt 4 4,247 16,988 $123.98 $496
------ ------
Total Metal Halide 54 101,416 $7,149
- -----------------------------------------------------------------------------------------------------------------------------
INCANDESCENT
1031110 103 1,000 OH_WoodLine StLt 2 405 810 $40.22 $80
2021110 202 2,500 OH_WoodLine StLt 1 794 794 $49.52 $50
--- ---
Total Incandescent 3 1,604 $130
- -----------------------------------------------------------------------------------------------------------------------------
MERCURY VAPOR
1302110 100 4,200 OH_WoodLine StLt 269 511 137,459 $54.85 $14,755
1302810 100 4,200 URD_LamWood StLt 14 511 7,154 $215.15 $3,012
1302811 100 4,200 URD_LamWood StLt CustPaidPole 2 511 1,022 $59.13 $118
1302941 100 4,200 URD_WoodPost T&C CustPaidPole 4 511 2,044 $52.09 $208
2092110 175 8,600 OH_WoodLine StLt 39 822 32,058 $62.28 $2,429
2092130 175 8,600 OH_WoodLine PBU 226 822 185,772 $68.08 $15,386
2092211 175 8,600 OH_WoodLitg StLt CustPaidPole 1 822 822 $62.28 $62
2092231 175 8,600 OH_WoodLitg PBU CustPaidPole 7 822 5,754 $68.08 $477
2092541 175 8,600 UG_Steel T&C CustPaidPole 37 822 30,414 $59.52 $2,202
2092610 175 8,600 UG_Aluminum StLt 5 822 4,110 $222.57 $1,113
3002110 250 12,100 OH_WoodLine StLt 3 1,180 3,540 $77.01 $231
4742110 400 22,500 OH_WoodLine StLt 15 1,864 27,960 $94.83 $1,422
4742120 400 22,500 OH_WoodLine FldLt 174 1,864 324,336 $97.08 $16,892
4742130 400 22,500 OH_WoodLine PBU 30 1,864 55,920 $98.50 $2,955
4742211 400 22,500 OH_WoodLitg StLt CustPaidPole 8 1,864 14,912 $94.83 $759
4742221 400 22,500 OH_WoodLitg FldLt CustPaidPole 42 1,864 78,288 $97.08 $4,077
4742231 400 22,500 OH_WoodLitg PBU CustPaidPole 1 1,864 1,864 $98.50 $99
11352120 1,000 63,000 OH_WoodLine FldLt 34 4,463 151,742 $175.49 $5,967
11352221 1,000 63,000 OH_WoodLitg FldLt CustPaidPole 5 4,463 22,315 $175.49 $877
-- ------- ------
Total Mercury Vapor 916 1,087,486 $73,041
- ----------------------------------------------------------------------------------------------------------------------------
SODIUM VAPOR
613110 50 3,300 OH_WoodLine StLt 4,424 240 1,061,76 $45.14 $199,699
613211 50 3,300 OH_WoodLitg StLt CustPaidPole 5 240 1,200 $45.14 $226
613941 50 3,300 URD_WoodPost T&C CustPaidPole 2 240 480 $44.38 $89
853110 70 5,800 OH_WoodLine StLt 14,491 334 4,839,99 $47.39 $686,728
853120 70 5,800 OH_WoodLine FldLt 111 334 37,074 $59.87 $6,646
853210 70 5,800 OH_WoodLitg StLt 3 334 1,002 $119.97 $360
853211 70 5,800 OH_WoodLitg StLt CustPaidPole 20 334 6,680 $47.39 $948
853221 70 5,800 OH_WoodLitg FldLt CustPaidPole 2 334 668 $59.87 $120
<PAGE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Workpaper TMB-1, Revised
Page 23 of 25
MECO MECO MECO Increase
MECO Annual Total MECO Annual (Decrease) in
MECO Lumen 12/98 kWh Annual Annual Distribution Distribution
Code Size Type Quantity per Light kWh Price Revenue Revenue
----- ------ ---- -------- --------- ------ ------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
77 27,500 Flood 9 1,255 11,295 $143.82 $1,294 $406
77 27,500 Flood 2 1,255 2,510 143.82 $288 ($90)
P wood pole $41.90 $84 $84
78 50,000 Flood 39 1,968 76,752 $163.80 $6,388 $1,000
80 140,000 Flood 4 4,578 18,312 $220.41 $882 $386
-- ------
54 108,869 $8,936 $1,786
- -----------------------------------------------------------------------------------------
10 1,000 StLt 2 440 880 $48.46 $97 $16
11 2,500 StLt 1 845 845 $59.83 $60 $10
-- --- ---- ----
3 1,725 $157 $27
- ----------------------------------------------------------------------------------------
3 4,000 StLt 269 561 150,909 $48.49 $13,044 ($1,711)
3 4,000 StLt 14 561 7,854 $48.49 $679 ($2,333)
R fiberglass w/o base $49.36 $691 $691
3 4,000 StLt 2 561 1,122 $48.49 $97 ($21)
1 4,000 Post Top 4 561 2,244 $57.46 $230 $21
4 8,000 StLt 39 908 35,412 $53.89 $2,102 ($327)
4 8,000 StLt 226 908 205,208 $53.89 $12,179 ($3,207)
4 8,000 StLt 1 908 908 $53.89 $54 ($8)
4 8,000 StLt 7 908 6,356 $53.89 $377 ($99)
2 8,000 Post Top 37 908 33,596 $76.89 $2,845 $643
4 8,000 StLt 5 908 4,540 $53.89 $269 ($843)
T metal w/foundation $128.30 $642 $642
16 11,000 StLt 3 1,248 3,744 $69.43 $208 ($23)
5 22,000 StLt 15 1,897 28,455 $89.34 $1,340 ($82)
23 22,000 Flood 174 1,897 330,078 $107.27 $18,665 $1,773
5 22,000 StLt 30 1,897 56,910 $89.34 $2,680 ($275)
5 22,000 StLt 8 1,897 15,176 $89.34 $715 ($44)
23 22,000 Flood 42 1,897 79,674 $107.27 $4,505 $428
5 22,000 StLt 1 1,897 1,897 $89.34 $89 ($9)
24 63,000 Flood 34 4,569 155,346 $195.22 $6,637 $671
24 63,000 Flood 5 4,569 22,845 $195.22 $976 $99
-- ------- ------ -----
916 1,142,274 $69,025 ($4,016)
- ----------------------------------------------------------------------------------------
70 4,000 StLt 4,424 248 1,097,152 $55.82 $246,948 $47,248
70 4,000 StLt 5 248 1,240 $55.82 $279 $53
83 4,000 Post Top 2 248 496 $61.22 $122 $34
71 5,800 StLt 14,491 349 5,057,359 $67.52 $978,432 $291,704
77 27,500 Flood 111 1,255 139,305 $143.82 $15,964 $9,318
71 5,800 StLt 3 349 1,047 $67.52 $203 ($157)
P wood pole $41.90 $126 $126
71 5,800 StLt 20 349 6,980 $67.52 $1,350 $403
77 27,500 Flood 2 1,255 2,510 $143.82 $288 $168
<PAGE>
<CAPTION>
C:\eua files on disk\wptmb-1.WK4
15-Jun-99
Massachusetts Electric Company
Eastern Edison Company
Streetlight Revenue Analysis
EEC EEC EEC
EEC EEC Annual Total EEC Annual
Lighting Lumen Service Special 12/98 kWh Annual Annual Distribution
Code Wattage Size & Pole Type Pricing Quantity per Light kWh Price Revenue
------- ------- ----- -------- ---- ------- -------- --------- ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
853441 70 5,800 URD_Fiberglass T&C CustPaidPole 118 334 39,412 $45.55 $5,375
853461 70 5,800 URD_Fiberglass SBA CustPaidPole 146 334 48,764 $87.16 $12,725
853641 70 5,800 UG_Aluminum T&C CustPaidPole 3 334 1,002 $45.55 $137
853711 70 5,800 UG_WoodLitg StLt CustPaidPole 7 334 2,338 $56.72 $397
853811 70 5,800 URD_LamWood StLt CustPaidPole 199 334 66,466 $51.66 $10,280
853941 70 5,800 URD_WoodPost T&C CustPaidPole 222 334 74,148 $45.55 $10,112
1213110 100 9,500 OH_WoodLine StLt 7,510 476 3,574,76 $51.05 $383,386
1213130 100 9,500 OH_WoodLine PBU 357 476 169,932 $55.98 $19,985
1213211 100 9,500 OH_WoodLitg StLt CustPaidPole 88 476 41,888 $51.05 $4,492
1213230 100 9,500 OH_WoodLitg PBU 1 476 476 $128.54 $129
1213231 100 9,500 OH_WoodLitg PBU CustPaidPole 39 476 18,564 $55.98 $2,183
1213441 100 9,500 URD_Fiberglass T&C CustPaidPole 46 476 21,896 $50.49 $2,323
1213460 100 9,500 URD_Fiberglass SBA 4 476 1,904 $191.25 $765
1213461 100 9,500 URD_Fiberglass SBA CustPaidPole 28 476 13,328 $99.88 $2,797
1213610 100 9,500 UG_Aluminum StLt 29 476 13,804 $211.33 $6,129
1213631 100 9,500 UG_Aluminum PBU CustPaidPole 3 476 1,428 $65.30 $196
1213641 100 9,500 UG_Aluminum T&C CustPaidPole 31 476 14,756 $50.49 $1,565
1213651 100 9,500 UG_Aluminum PMA CustPaidPole 18 476 8,568 $69.30 $1,247
1213711 100 9,500 UG_WoodLitg StLt CustPaidPole 29 476 13,804 $60.35 $1,750
1213811 100 9,500 URD_LamWood StLt CustPaidPole 41 476 19,516 $55.53 $2,277
1213940 100 9,500 URD_WoodPost T&C 3 476 1,428 $118.61 $356
1213941 100 9,500 URD_WoodPost T&C CustPaidPole 279 476 132,804 $50.49 $14,087
1763110 150 16,000 OH_WoodLine StLt 125 692 86,500 $56.20 $7,025
1763120 150 16,000 OH_WoodLine FldLt 90 692 62,280 $69.53 $6,258
1763211 150 16,000 OH_WoodLitg StLt CustPaidPole 10 692 6,920 $56.20 $562
1763220 150 16,000 OH_WoodLitg FldLt 2 692 1,384 $142.11 $284
1763221 150 16,000 OH_WoodLitg FldLt CustPaidPole 2 692 1,384 $69.53 $139
1763610 150 16,000 UG_Aluminum StLt 37 692 25,604 $216.49 $8,010
1763611 150 16,000 UG_Aluminum StLt CustPaidPole 2 692 1,384 $68.22 $136
1763614 150 16,000 UG_Aluminum StLt AddlFixt 15 692 10,380 $68.22 $1,023
3243110 250 25,000 OH_WoodLine StLt 2,129 1,274 2,712,34 $76.33 $162,507
3243120 250 25,000 OH_WoodLine FldLt 1,030 1,274 1,312,22 $83.44 $85,943
3243124 250 25,000 OH_WoodLine FldLt AddlFixt 1 1,274 1,274 $83.44 $83
3243210 250 25,000 OH_WoodLitg StLt 1 1,274 1,274 $148.91 $149
3243211 250 25,000 OH_WoodLitg StLt CustPaidPole 46 1,274 58,604 $76.33 $3,511
<PAGE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Workpaper TMB-1, Revised
Page 24 of 25
MECO MECO MECO Increase
MECO Annual Total MECO Annual (Decrease) in
MECO Lumen 12/98 kWh Annual Annual Distribu Distribution
Code Size Type Quantity per Light kWh Price Revenue Revenue
<S> <C> <C> <C> <C> <C> <C> <C> <C>
83 4,000 Post Top 118 248 29,264 $61.22 $7,224 $1,849
71 5,800 StLt 146 349 50,954 $67.52 $9,858 ($2,867)
83 4,000 Post Top 3 248 744 $61.22 $184 $47
71 5,800 StLt 7 349 2,443 $67.52 $473 $76
71 5,800 StLt 199 349 69,451 $67.52 $13,436 $3,156
83 4,000 Post Top 222 248 55,056 $61.22 $13,591 $3,479
72 9,600 StLt 7,510 490 3,679,900 $71.23 $534,937 $151,552
72 9,600 StLt 357 490 174,930 $71.23 $25,429 $5,444
72 9,600 StLt 88 490 43,120 $71.23 $6,268 $1,776
72 9,600 StLt 1 490 490 $71.23 $71 ($57)
P wood pole $41.90 $42 $42
72 9,600 StLt 39 490 19,110 $71.23 $2,778 $595
79 9,600 Post Top 46 490 22,540 $65.50 $3,013 $690
72 9,600 StLt 4 490 1,960 $71.23 $285 ($480)
72 9,600 StLt 28 490 13,720 $71.23 $1,994 ($802)
72 9,600 StLt 29 490 14,210 $71.23 $2,066 ($4,063)
T metal w/foundation $128.30 $3,721 $3,721
72 9,600 StLt 3 490 1,470 $71.23 $214 $18
79 9,600 Post Top 31 490 15,190 $65.50 $2,031 $465
79 9,600 Post Top 18 490 8,820 $65.50 $1,179 ($68)
72 9,600 StLt 29 490 14,210 $71.23 $2,066 $316
72 9,600 StLt 41 490 20,090 $71.23 $2,920 $644
79 9,600 Post Top 3 490 1,470 $65.50 $197 ($159)
R fiberglass w/o base $49.36 $148 $148
79 9,600 Post Top 279 490 136,710 $65.50 $18,275 $4,188
73 16,000 StLt 125 714 89,250 $75.78 $9,473 $2,448
77 27,500 Flood 90 1,255 112,950 $143.82 $12,944 $6,686
73 16,000 StLt 10 714 7,140 $75.78 $758 $196
77 27,500 Flood 2 1,255 2,510 $143.82 $288 $3
P wood pole $41.90 $84 $84
77 27,500 Flood 2 1,255 2,510 $143.82 $288 $149
73 16,000 StLt 37 714 26,418 $75.78 $2,804 ($5,206)
T metal w/foundation $128.30 $4,747 $4,747
73 16,000 StLt 2 714 1,428 $75.78 $152 $15
73 16,000 StLt 15 714 10,710 $75.78 $1,137 $113
74 27,500 StLt 2,129 1,284 2,733,636 $94.06 $200,254 $37,747
77 27,500 Flood 1,030 1,255 1,292,650 $143.82 $148,135 $62,191
77 27,500 Flood 1 1,255 1,255 $143.82 $144 $60
74 27,500 StLt 1 1,284 1,284 $94.06 $94 ($55)
P wood pole $41.90 $42 $42
74 27,500 StLt 46 1,284 59,064 $94.06 $4,327 $816
<PAGE>
<CAPTION>
C:\eua files on disk\wptmb-1.WK4
15-Jun-99
Massachusetts Electric Company
Eastern Edison Company
Streetlight Revenue Analysis
EEC EEC EEC
EEC EEC Annual Total EEC Annual
Lighting Lumen Service Special 12/98 kWh Annual Annual Distribution
Code Wattage Size & Pole Type Pricing Quantity per Light kWh Price Revenue
------- ------- ------ ----------- ---- ------- -------- --------- ------ ------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
3243220 250 25,000 OH_WoodLitg FldLt 1 1,274 1,274 $156.02 $156
3243221 250 25,000 OH_WoodLitg FldLt CustPaidPole 85 1,274 108,290 $83.44 $7,092
3243610 250 25,000 UG_Aluminum StLt 681 1,274 867,594 $236.61 $161,131
3243611 250 25,000 UG_Aluminum StLt CustPaidPole 9 1,274 11,466 $88.36 $795
3243621 250 25,000 UG_Aluminum FldLt CustPaidPole 1 1,274 1,274 $98.82 $99
3243624 250 25,000 UG_Aluminum FldLt AddlFixt 10 1,274 12,740 $98.82 $988
3243711 250 25,000 UG_WoodLitg StLt CustPaidPole 1 1,274 1,274 $85.64 $86
5003110 400 50,000 OH_WoodLine StLt 581 1,966 1,142,246 $97.42 $56,601
5003120 400 50,000 OH_WoodLine FldLt 4,258 1,966 8,371,228 $105.45 $449,006
5003124 400 50,000 OH_WoodLine FldLt AddlFixt 2 1,966 3,932 $105.45 $211
5003210 400 50,000 OH_WoodLitg StLt 2 1,966 3,932 $170.00 $340
5003211 400 50,000 OH_WoodLitg StLt CustPaidPole 67 1,966 131,722 $97.42 $6,527
5003220 400 50,000 OH_WoodLitg FldLt 48 1,966 94,368 $178.03 $8,545
5003221 400 50,000 OH_WoodLitg FldLt CustPaidPole 426 1,966 837,516 $105.45 $44,922
5003224 400 50,000 OH_WoodLitg FldLt AddlFixt 1 1,966 1,966 $105.45 $105
5003610 400 50,000 UG_Aluminum StLt 99 1,966 194,63 $257.70 $25,512
5003614 400 50,000 UG_Aluminum StLt AddlFixt 6 1,966 11,796 $109.45 $657
5003620 400 50,000 UG_Aluminum FldLt 28 1,966 55,048 $269.09 $7,535
5003621 400 50,000 UG_Aluminum FldLt CustPaidPole 10 1,966 19,660 $120.81 $1,208
5003624 400 50,000 UG_Aluminum FldLt AddlFixt 111 1,966 218,226 $120.81 $13,410
5003721 400 50,000 UG_WoodLitg FldLt CustPaidPole 1 1,966 1,966 $114.77 $115
6483612 500 25,000 UG_Aluminum StLt TwinFixts 61 2,548 155,428 $330.50 $20,161
--- ------- -------
Total Sodium Vapor 38,238 26,758,978 $2,458,340
- -----------------------------------------------------------------------------------------------------------------------------
TOTAL STREETLIGHT DISTRIBUTION REVENUE 39,211 27,949,484 $2,538,661
- --------------------------------------
Year 2001
Estimated
Rates
---------
TRANSMISSION 27,949,484 $0.00291 $81,333
- ------------
TRANSITION 27,949,484 $0.02300 $642,838
- ----------
DSM AND RENEWABLES 27,949,484 $0.00370 $103,413
- ------------------
STANDARD SERVICE 27,949,484 $0.03800 $1,062,080
- ---------------- ----------
TOTAL STREETLIGHT REVENUE $4,428,326
- ------------------------- ==========
<PAGE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-__
Workpaper TMB-1, Revised
Page 25 of 25
MECO MECO MECO Increase
MECO Annual Total MECO Annual (Decrease) in
MECO Lumen 12/98 kWh Annual Annual Distribution Distribution
Code Size Type Quantity per Light kWh Price Revenue Revenue
------ ----- ----- -------- --------- ------ ------- ------------ -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
77 27,500 Flood 1 1,255 1,255 $143.82 $144 ($12)
P wood pole $41.90 $42 $42
77 27,500 Flood 85 1,255 106,675 $143.82 $12,225 $5,132
74 27,500 StLt 681 1,284 874,404 $94.06 $64,055 ($97,077)
T metal w/foundation $128.30 $87,372 $87,372
74 27,500 StLt 9 1,284 11,556 $94.06 $847 $51
77 27,500 Flood 1 1,255 1,255 $143.82 $144 $45
77 27,500 Flood 10 1,255 12,550 $143.82 $1,438 $450
74 27,500 StLt 1 1,284 1,284 $94.06 $94 $8
75 50,000 StLt 581 1,968 1,143,408 $130.65 $75,908 $19,307
78 50,000 Flood 4,258 1,968 8,379,744 $163.80 $697,460 $248,454
78 50,000 Flood 2 1,968 3,936 $163.80 $328 $117
75 50,000 StLt 2 1,968 3,936 $130.65 $261 ($79)
P wood pole $41.90 $84 $84
75 50,000 StLt 67 1,968 131,856 $130.65 $8,754 $2,226
78 50,000 Flood 48 1,968 94,464 $163.80 $7,862 ($683)
P wood pole $41.90 $2,011 $2,011
78 50,000 Flood 426 1,968 838,368 $163.80 $69,779 $24,857
78 50,000 Flood 1 1,968 1,968 $163.80 $164 $58
75 50,000 StLt 99 1,968 194,832 $130.65 $12,934 ($12,578)
T metal w/foundation $128.30 $12,702 $12,702
75 50,000 StLt 6 1,968 11,808 $130.65 $784 $127
78 50,000 Flood 28 1,968 55,104 $163.80 $4,586 ($2,948)
T metal w/foundation $128.30 $3,592 $3,592
78 50,000 Flood 10 1,968 19,680 $163.80 $1,638 $430
78 50,000 Flood 111 1,968 218,448 $163.80 $18,182 $4,772
78 50,000 Flood 1 1,968 1,968 $163.80 $164 $49
74 27,500 StLt 122 1,284 156,648 $94.06 $11,475 ($8,685)
T metal w/foundation $128.30 $7,826 $7,826
38,299 27,287,893 $3,376,806 $918,466
- ---------------------------------------------------------------------------------------------------
39,272 28,540,761 $3,454,923 $916,262
difference due to twin 25,000 lumen streetlights doubled under MECO's rate structure
Year 2001
Consolidated
Rates
------------
28,540,761 $0.00482 $137,566 $56,233
28,540,761 $0.01250 $356,760 ($286,079)
28,540,761 $0.00370 $105,601 $2,188
28,540,761 $0.03800 $1,084,549 $22,469
---------- -------
$5,139,399 $711,073
========== ========
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Workpaper TMB-2
Eastern Edison Company
Estimated Retail Transmission Rate in Year 2001
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\Eectrana.wk4 New England Electric System
EEC TRANSM Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Workpaper TMB-2, Revised
Page 1 of 1
Eastern Edison Company
Calendar Year 2001
Estimated Montaup Stand-Alone Transmission Charge Calculation
<S> <C> <C>
(1) Projected 1999 Transmission Cost to Serve Eastern Customers from Montaup $5,440,383
(2) Projected 1999 Transmission Cost to Serve Eastern Customers from NEPOOL $2,136,194
----------
(3) Total Projected 1999 Transmission Cost to Serve Eastern Customers $7,576,577
2000 2001
---- ----
(4) Adjusted for 2.2% Inflation $7,743,262 $7,913,613
(5) Total Eastern kWh Sales 2,711,961,115 2,711,961,115
--------------
(6) Estimated Annual Average Transmission Rate to
Retail Customers $0.00285 $0.00291
========= ========
(1) Per FERC Section 205 Filing, Exhibit__(PAV-4), Statement BH, Schedule 1, Page 3 of 3
(2) Estimate of NEPOOL transmission expenses
(3) Line (1) + Line (2)
(4) Line (3) x 1.022% per year
(5) Actual 1998 kWh sales
(6) Line (4) / Line (5), truncated after 5 decimal places
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Workpaper TMB-3
Massachusetts Electric Company
Consolidated Retail Transmission Rates
Assuming Rate Consolidation on January 1, 2001
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\Tran-01a.wk4 Massachusetts Electric Company
COMBINED TRANSM Eastern Edison Company
M.D.T.E. Docket No.
Workpaper TMB-3, Revised
Page 1 of 3
Massachusetts Electric Company
Nantucket Electric Company
Eastern Edison Company
Calendar Year 2001
Combined Transmission Charge Calculation
Total R-1/R-2/E R-4 G-1 G-2 G-3 Streetlights
----- --------- --- --- --- --- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
(1) 1999 Estimate of Combined
Transmission $99,174,277
(2) Inflated Transmission
Expense to 2001 $103,585,946
-------------------------------------------------------------------------------------------------------------------------
(3) Combined Coincident Peak
with NEP's Peak (KW) 35,627,600 14,218,120 102,837 3,760,755 5,050,497 12,275,322 220,068
(4) Coincident Peak Allocator 100.00% 39.91% 0.29% 10.56% 14.18% 34.45% 0.62%
-------------------------------------------------------------------------------------------------------------------------
(5) Allocated Combined
Transmission Expense $103,585,946 $41,338,666 $298,995 $10,934,258 $14,684,136 $35,690,049 $639,841
(6) Forecasted kWh Sales 19,958,898,115 7,231,927,275 58,543,000 1,922,930,824 2,859,452,245 7,753,477,287 132,567,484
(7) Combined Transmission
Charge per kWh $0.00518 $0.00571 $0.00510 $0.00568 $0.00513 $0.00460 $0.00482
(1) FERC Section 205 Filing, Exhibit__ (PAV-4), Statements BG & BH, plus estimate of NEPOOL transmission costs for 1999
(2) Line (1) x 1.022% for 2 years
(3) Page 2 of 3
(4) Line (3) as a percent of total Line (3)
(5) Line (3) x Line (4)
(6) Page 3 of 3
<PAGE>
S:\RADATA1\EASTED\2001\Tran-01a.wk4 Massachusetts Electric Company
PEAK Eastern Edison Company
M.D.T.E. Docket No.
Workpaper TMB-3, Revised
Page 2 of 3
Massachusetts Electric Company
1997 Coincident Peak Data
Total R-1/R-2/E R-4 G-1 G-2 G-3 Streetlights
Total Mass. Electric
(including Nantucket) 30,289,338 11,907,601 102,837 2,899,941 4,244,281 10,964,364 170,313
Eastern in Mass.
Electric
Rate Structure 5,338,262 2,310,519 0 860,814 806,216 1,310,958 49,755
---------- ---------- ------- --------- --------- --------- --------
Total 35,627,600 14,218,120 102,837 3,760,755 5,050,497 12,275,322 220,068
========== ========== ======= ========= ========= ========== =======
Source: Company Load Data for 1997
Eastern Load Data allocated to Mass. Electric rate structure based on mapping of retail
billing determinants
<PAGE>
S:\RADATA1\EASTED\2001\Tran-01a.wk4 Massachusetts Electric Company
KWH Eastern Edison Company
M.D.T.E. Docket No.
Workpaper TMB-3, Revised
Page 3 of 3
Massachusetts Electric Company
Nantucket Electric Company
Eastern Edison Company
Forecasted kWh Sales
Total R-1/R-2/E R-4 G-1 G-2 G-3 Streetlights
(1) Mass. Electric 17,246,937,000 6,147,502,000 58,543,000 1,565,201,000 2,408,497,000 6,962,576,000 104,618,000
(incl. Nantucket
Electric)
(2) Eastern Edison 2,711,961,115 1,084,425,275 0 357,729,824 450,955,245 790,901,287 27,949,484
------------- ------------- - ----------- ----------- ----------- ----------
(3) Total 19,958,898,115 7,231,927,275 58,543,000 1,922,930,824 2,859,452,245 7,753,477,287 132,567,484
============== ============= ========== ============= ============= ============= ===========
(1) Company Forecast for Calendar Year 2000
(2) Actual 1998 kWh Sales Mapped to Mass. Electric rate classes
(3) Line (1) + Line (2)
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Workpaper TMB-4
Massachusetts Electric Company
Estimated Combined Transition Charge in Year 2001
<PAGE>
<TABLE>
<CAPTION>
S:\RADATA1\EASTED\2001\Mecoctc.wk4 Massachusetts Electric Company
CTC ESTIMATE Eastern Edison Company
15-Jun-99 M.D.T.E. Docket No.
Workpaper TMB-4
Page 1 of 1
Massachusetts Electric Company
Eastern Edison Company
Combined Contract Termination Charge
2001 2002 2003 2004
---- ---- ---- ----
<S> <C> <C> <C> <C>
(1) Mass. Electric's Share of
Contract Termination Charge $184,000 $186,000 $175,000 $169,000
(2) Eastern Edisons's Share of
Contract Termination Charge $64,404 $62,925 $52,943 $49,617
------- ------- ------- -------
(3) Total Combined
Contract Termination Charge $248,404 $248,925 $227,943 $218,617
------------------------------------------------------------------------------
(4) Estimated Mass. Electric GWh
Deliveries 17,131 17,349 17,603 17,917
(5) Estimated Eastern Edison GWh
Deliveries 2,803 2,835 2,878 2,928
----- ----- ----- -----
(6) Total Combined GWh
Deliveries 19,934 20,184 20,481 20,845
------------------------------------------------------------------------------
(7) Combined CTC 1.25 1.23 1.11 1.05
</TABLE>
(1) Ex. 3, Schedule 1 of NEP's December 1, 1998 CTC Reconciliation
(2) Ex. 3, Schedule 1 of NEP's December 1, 1998 CTC Reconciliation
(3) Line (1) + Line (2)
(4) Ex. MEC-DTS-6-EEC, Schedule 1 of Montaup's February 12, 1999 CTC Filing
(5) Ex. MEC-DTS-6-EEC, Schedule 1 of Montaup's February 12, 1999 CTC Filing
(6) Line (4) + Line (5)
(7) Line (3) / Line (6)
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Workpaper TMB-5
Eastern Edison Company
Estimated Transition Charges in Year 2001
<PAGE>
S:\RADATA1\EASTED\2001\Eecctc1.wk4 New England Electric System
EEC CTC Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-__
Workpaper TMB-5
Page 1 of 1
Eastern Edison Company
Calendar Year 2001
Estimated Stand-Alone Transition Charge Calculation
(1) Year 2001 CTC per Divestiture Filing $0.02300
(2) CTC for Remainder of 1999 $0.02100
(3) Ratio 109.524%
Current Transition Estimated Transition
Charge Ratio Charge
(4) (5) (6)
R-1, R-2, R-3, G-1, H-1, H-2, W-1, S-1
all kWh $0.02100 109.524% $0.02300
R-4
on peak kwh $0.09952 109.524% $0.10899
off peak kw $0.00797 109.524% $0.00872
G-2
all KW $5.55 109.524% $6.07
all kWh $0.00181 109.524% $0.00198
G-4
all KW $5.52 109.524% $6.04
on peak kwh $0.01235 109.524% $0.01352
off peak kw $0.00676 109.524% $0.00740
G-5
all KW $4.37 109.524% $4.78
on peak kwh $0.01204 109.524% $0.01318
off peak kw $0.00700 109.524% $0.00766
G-6
all KW $4.37 109.524% $4.78
on peak kwh $0.01533 109.524% $0.01679
off peak kw $0.01029 109.524% $0.01127
T-2
all KW $5.75 109.524% $6.29
on peak kwh $0.01403 109.524% $0.01536
off peak kw $0.00843 109.524% $0.00923
A-6
KW $4.46 109.524% $4.88
on peak kwh $0.00997 109.524% $0.01091
off peak kw $0.00493 109.524% $0.00539
(1) Per February 12, 1999 Divestiture Filing
(2) Currently Effective Transition Charge
(3) Line (1) / Line (2)
(4) Per Currently Effective Tariffs
(5) Line (3)
(6) Line (4) x Line (5), truncated after 2 or 5 decimal places, depending
upon charge
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
JAMES J. BONNER, Jr.
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF TELECOMMUNICATIONS AND ENERGY
- -----------------------------------
)
New England Electric System ) Docket D.T.E. 99-___
Eastern Utilities Associates )
)
- -----------------------------------
DIRECT TESTIMONY
OF
JAMES J. BONNER, Jr.
Table of Contents
Page
I. Introduction and Qualifications..................................... 1
II. Purpose of Testimony................................................ 3
III. Mapping of Eastern's Customers to Mass. Electric's Rates............ 4
IV. Derivation of Billing Determinants for Eastern's Customers under
Mass. Electric's Rates............................. ................ 14
V. Conclusion.......................................................... 18
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 1 of 18
<S> <C>
1 I. Introduction and Qualifications
2 Q. Please state your full name and business address.
3 A. My name is James J. Bonner, Jr. My business address is 750 West Center Street, West
4 Bridgewater, Massachusetts.
5
6 Q. Please state your present position and responsibilities.
7 A. I am Manager of Retail Pricing and Rate Administration for EUA Service Corporation.
8 My responsibilities include the direct supervision of EUA Service Corporation's Retail
9 Pricing and Rate Administration supervisor and staff. Among the responsibilities of that
10 staff are the study, analysis, and design of retail delivery service rates for Eastern Edison
11 Company ("Eastern" or "EECo").
12
13 Q. Please describe your educational background and work experience.
14 A. I graduated from Northeastern University in 1976 with a Bachelor of Science degree in
15 Electrical Engineering (Power Systems). I attended the Edison Electric Institute's
16 ("EEI") Rate Fundamentals Course at Indiana University in November 1985 and the EEI
17 Advanced Rate Course at Indiana University in August 1986 and in August 1988. I was
18 Chairman of the Electric Council of New England's Rate and Regulatory Committee
19 from 1993 through 1995.
20
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 2 of 18
1 From August 1976 through February 1983, I was employed by the Belcher Division of
2 Dayton Malleable Inc., a malleable iron foundry located in Easton, Massachusetts, as
3 Plant Engineer. My duties included plant maintenance management, energy
4 management, capital budgeting, and production engineering.
5
6 In March 1983, I joined Eastern as Consumer Service Engineer for the Brockton
7 Division. In that capacity, I served as Eastern's representative for its fifty largest
8 commercial-industrial customers in the Brockton Division's service area and as a staff
9 assistant to the Consumer Service Manager.
10
11 I transferred to the Rate Department of EUA Service Corporation in February 1985 as an
12 Associate Rate Engineer. I was promoted to Rate Engineer in February 1987, to Senior
13 Rate Engineer in February 1989, to Supervisor of Rate Design in January 1991, and to
14 Manager of Retail Pricing and Rate Administration in January 1999. Since assuming the
15 position of Supervisor of Rate Design in 1991, I have supervised the preparation of
16 Eastern's retail rates approved by the Department of Telecommunications and Energy
17 ("Department") in subsequent regulatory proceedings.
18
19 Q. Have you previously testified before the Department?
20 A. Yes, I have testified before the Department on several occasions. Most recently, I
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 3 of 18
1 testified in D.P.U./D.T.E. 96-100, Electric Industry Restructuring, as part of the
2 Basic/Universal Service panel in June 1996, and I testified in support of Eastern's
3 proposed rates in D.P.U. 92-148, Eastern's last general rate case, in September 1992.
4
5 Q. Were the schedules attached to your direct testimony prepared by you or under your
6 supervision and direction?
7 A. Yes, they were.
8
9 II. Purpose of Testimony
10 Q. What is the purpose of your testimony?
11 A. The purpose of my testimony is to present and support the mapping of Eastern's customers
12 under Eastern's retail delivery service rates to Massachusetts Electric
13 Company's ("Mass. Electric's") retail delivery service rates and the derivation of the
14 billing determinants for Eastern's customers mapped to Mass. Electric's rates. Ms. Burns
15 makes use of this mapping and these billing determinants in her testimony and exhibits
16 regarding the proposed Mass. Electric/Eastern merger rate plan and its impact on revenue.
17
18 Q. Please explain how you have organized your testimony.
19 A. My testimony is organized as follows: (1) An explanation of the mapping process
20 that we used to align the schedule of rates between Eastern and Mass. Electric, and (2) an
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 4 of 18
1 explanation of the derivation of the billing determinants used for transferring Eastern's
2 customers to Mass. Electric's rates.
3
4 III. Mapping of Eastern's Customers to Mass. Electric's Rates
5 Q. Please describe how Eastern's customers were mapped to Mass. Electric's retail delivery
6 service rates.
7 A. A mapping of Eastern's retail delivery service rates to Mass. Electric's retail delivery
8 service rates was performed by comparing the availability provisions between Eastern's
9 rates and Mass. Electric's rates. Exhibit JJB-1 demonstrates this comparing of rates. This
10 exhibit shows a comparison of the availability provisions of Eastern's and Mass.
11 Electric's rates. A summary of the mapping of Eastern's rates to Mass. Electric's is
12 provided by Ms. Burns in her Exhibit TMB-3.
13
14 Although Eastern's schedule of rates is comparable to Mass. Electric's schedule of rates,
15 Eastern's applicability and rate structures are not identical to those of Mass. Electric's
16 schedule of rates. Eastern has, in some customer classes, more available rates than Mass.
17 Electric. Eastern uses different billing determinant breakpoints to subdivide its general
18 service (commercial-industrial) customer class into several rates. Eastern uses fewer
19 optional rates than does Mass. Electric. And Eastern makes use of supplementary1 rates,
- ---------------
1 A supplementary rate is a rate that is available only to customers who also receive part of their
electric service under another rate, called a principal rate. A principal rate can be the only rate
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 5 of 18
1 whereas Mass. Electric does not.
2
3 Q. How were the determinants necessary for developing the rate mapping proposal
4 developed?
5 A. EECo based the mapping of Eastern's rates to Mass. Electric's rates on its customer
6 billing information for calendar year 1998. For each of Eastern's rate classes, the number
7 of bills rendered and annual energy consumption were determined. Where required for
8 certain rate classes, monthly billing demands and annual peak and off-peak energy
9 consumption were determined. In many cases, especially for those current Eastern rate
10 classes that were subdivided into two or more Mass. Electric rate classes, these
11 determinants were required to be developed on a customer-by-customer basis and
12 transformed from Eastern's definition of a determinant--e.g., billing demand--to Mass.
13 Electric's definition of the same determinant.
14
15 Q. Please describe Eastern's Schedule of Rates.
16 A. Eastern's Schedule of Rates consists of four (4) residential rates,
17 Residential Retail Delivery Service Rate R-1
- ---------------
under which a customer receives service at a given location, but a supplementary rate cannot.
For example, Eastern's Controlled Water Heating Service Rate W-1 is a supplementary rate. To
be eligible for Rate W-1, a customer must also receive service under one or more of Eastern's
residential or general service rates at the same service location.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 6 of 18
Low Income Residential Retail Delivery Service Rate R-2
Residential Space Heating Retail Delivery Service Rate R-3
TOU Residential Retail Delivery Service Rate R-4
seven (7) general service rates,
Small Secondary Voltage General Retail Delivery Service Rate G-1
Medium Secondary Voltage General Retail Delivery Service Rate G-2
Large Secondary Voltage General Retail Delivery Service Rate G-4
Medium Primary Voltage General Retail Delivery Service Rate G-5
Large Primary Voltage General Retail Delivery Service Rate G-6
Medium TOU Secondary Voltage General Retail Delivery Service Rate T-2
Large Pri. Voltage Auxiliary General Retail Delivery Service Rate A-6
General Space Heating Retail Delivery Service Rate H-1
two (2) supplementary rates,
General Heating Retail Delivery Service Rate H-2
Controlled Water Heating Retail Delivery Service Rate W-1
and a lighting service rate,
Lighting Retail Delivery Service Rate S-1.
In addition to the foregoing, Eastern's Schedule of Rates contains the following terms
and conditions, adjustment clauses, generation services, and rate riders:
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 7 of 18
Terms and Conditions for Distribution Service
Terms and Conditions for Competitive Suppliers
Transition Cost Adjustment Clause
Standard Offer Service
Demand Side Management Clause
Renewable Energy Clause
Farm Discount Rate Rider
Interim Default Service
Q. Please describe Mass. Electric's Schedule of Rates.
A. Mass. Electric's Schedule of Rates consists of three (3) residential rates,
Residential Regular R-1 Retail Delivery Service
Residential Low Income R-2 Retail Delivery Service
Residential - Time-of-Use (Optional) R-4 Retail Delivery Service
four (4) general service rates,
General Service - Small Commercial & Industrial G-1 Retail Delivery Service
General Service - Demand G-2 Retail Delivery Service
Time-of-Use G-3 Retail Delivery Service
Experimental Flexible Time-Of-Use Pricing (G-5)
one (1) interruptible rate,
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 8 of 18
Scheduled Interruptible Service Rate I-1
and four (4) lighting service rates,
Street & Security Lighting - Co. Owned Equipment S-1 Retail Delivery Service
Street Lighting - Overhead - Cust.-Owned Equipment S-2 Retail Delivery Service
Street Lighting - Underground - Div. Of Ownership S-3 Retail Delivery Service
Street Lighting - Company Owned Equipment S-20 Retail Delivery Service
Street Lighting - Customer Owned Equipment S-5 Retail Delivery Service2
In addition to the foregoing, Mass. Electric's Schedule of Rates contains the following
terms and conditions, adjustment provisions, generation service tariffs, and interruptible
service provisions:
Terms and Conditions for Distribution Service
Terms and Conditions for Competitive Suppliers
Transmission Service Cost Adjustment Provision
Transition Cost Adjustment Provision
Demand Side Management Provision
Renewables Provision
Standard Service Cost Adjustment Provision
Default Service Adjustment Provision
- ---------------
2 Currently pending approval in M.D.T.E. Docket No. 98.69.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 9 of 18
1 Tariff for Standard Service
2 Tariff for Default Service
3 Cooperative Interruptible Service Provisions For I-3
4 Cooperative Interruptible Service Provisions For I-4
5 Cooperative Interruptible Service Provisions For I-5
6
7 Q. How are Eastern's residential rates mapped to Mass. Electric's residential rates?
8 A. Eastern's residential rates are available only to residential customers for domestic
9 purposes. Rate R-1 is the ordinary residential retail delivery service rate, Rate R-2 is
10 restricted to low-income customers, Rate R-3 is available only to electric space heating
11 customers, and Rate R-4 is Eastern's optional time-of-use rate.
12
13 Like Eastern, Mass. Electric's residential rates are available to residential customers for
14 domestic purposes. Rate R-1 is Mass. Electric's ordinary residential retail delivery
15 service rate, Rate R-2 is restricted to low-income customers, and Rate R-4 is Mass.
16 Electric's optional time-of-use rate.
17
18 As shown on Exhibit TMB-3, Eastern's Rates R-1, R-3, and R-4 are mapped to Mass.
19 Electric's Rate R-1. Eastern's Low Income Residential Rate R-2 is mapped to Mass.
20 Electric's Residential Low Income Rate R-2.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 10 of 18
1 Q. Why was Eastern's time-of-use residential service rate, Rate R-4, mapped to Mass.
2 Electric's regular residential service rate, Rate R-1, instead of Mass. Electric's time-of-
3 use residential service rate, Rate R-4?
4 A. None of Eastern's current Rate R-4 customers meet Mass. Electric's Rate R-4's minimum
5 energy usage eligibility requirement of an average of 2,500 kWh/month and 30,000
6 kWh/year; therefore, Eastern's Rate R-4 customers are mapped to Mass. Electric's Rate
7 R-1.
8
9 Q. How are Eastern's general service rates mapped to Mass. Electric's general service rates?
10 A. Eastern's general service rates are open to all customers, including residential customers,
11 provided a customer otherwise meets the availability and/or the applicability provisions
12 of the rate.
13
14 Eastern's "G" series rates form the main sequence of Eastern's general service tariffs.
15 The "G" series rates are divided into two groups: (1) Secondary distribution voltage
16 rates--Rates G-1, G-2, and G-4, and (2) primary distribution voltage rates--Rates G-5
17 and G-6. The availability of the secondary voltage rates is as follows: Rate G-1 is
18 available to customers whose monthly demand is less than 10 kW and whose average
19 monthly energy consumption is less than 3,000 kWh. Rate G-2 is available to customers
20 whose monthly demand is at least 10 kW but less than 500 kW or whose average monthly
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 11 of 18
1 energy consumption is 3,000 kWh or more. Rate G-4 is required for customers whose
2 monthly demand is 500 kW or more. For general service customers served at primary
3 voltage, Rate G-5 is required if a customer's monthly demand is less than 500 kW;
4 otherwise Rate G-6 applies.
5
6 The remaining Eastern general service rates are as follows: Eastern's Rate T-2 is an
7 optional time-of-use rate available to Rate G-2 customers. Rate A-6 is Eastern's large
8 primary distribution voltage auxiliary3 service rate and is closed to new customers. Rate
9 H-1 is available only to certain non-residential electric space heating customers.
10
11 Mass. Electric's general service rates are considerably simpler than Eastern's. Mass.
12 Electric's has four general service rates (Rates G-1, G-2, G-3, and G-5) which apply to
13 customers as follows: Rate G-1 is available to customers whose monthly demand is 200
14 kW or less and whose average monthly energy consumption is 10,000 kWh or less. Rate
15 G-2 is available to customers whose monthly demand is 200 kW or less and whose
16 average monthly energy consumption is more than 10,000 kWh. Rate G-3 is available to
17 customers whose monthly demand is more than 200 kW. Rate G-5 is an experimental
---------------
1 3 Auxiliary service is one or more of the following services: supplementary power, backup
2 power, and maintenance power. Eastern provides auxiliary service to customers who self-
3 generate all or part of their electric service requirements and whose generation facilities are
4 Qualifying Facilities pursuant to 220 CMR 8.00 et seq.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 12 of 18
1 rate with a "real-time pricing"-like structure. It has been closed to new customers since
2 1997.
3
4 As shown in Exhibit TMB-3, Eastern's Rate G-1 was mapped to Mass. Electric's Rate G-
5 1. Eastern's Rates G-2 and T-2 were mapped to Mass. Electric's Rates G-1, G-2, and G-
6 3. Eastern's Rate G-4 was mapped Mass. Electric's Rate G-3. Eastern's Rate G-5 was
7 mapped to Mass. Electric's Rates G-2 and G-3. Eastern's Rate G-6 was mapped to Mass.
8 Electric's Rate G-3. Eastern's Rate H-1 was mapped to Mass. Electric's Rates G-1, G-2,
9 and G-3.
10
11 Q. How is Eastern's auxiliary service Rate A-6 mapped to Mass. Electric's rates?
12 A. Mass. Electric does not have an auxiliary service rate. Eastern's sole Rate A-6 customer
13 is transferred to Mass. Electric Rate G-3, which is the rate closest to Eastern's Rate A-6,
14 and will receive auxiliary service under Mass. Electric's current auxiliary service
15 provision.
16
17 Q. How are Eastern's supplementary service rates mapped to Mass. Electric's rates?
18 A. In general, customers receiving service under Eastern's supplementary rates, Rates H-2
19 and W-1, are first matched with their companion principal rate, then mapped to the Mass.
20 Electric rate which corresponds to the companion principal rate. Thus, the residential
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 13 of 18
1 portion of Eastern's Rate W-1 is mapped to Mass. Electric's Rate R-1, and the
2 non-residential portion of Eastern's Rate W-1 is mapped to Mass. Electric's Rate G-1.
3 Eastern's Rate H-2 is mapped to two of Mass. Electric's rates: Rates G-1 and G-2.
4
5 Q. Are any of Eastern's customers transferred to Mass. Electric's interruptible service rates
6 or are any of Mass. Electric's interruptible service provisions applied?
7 A. No. Eastern does not have any interruptible service customers currently, nor does Eastern
8 have any rates or rate riders applicable to such service. Moreover, all of the foregoing
9 Mass. Electric rates and provisions are closed to new customers.
10
11 Q. How is Eastern's lighting service rate mapped to Mass. Electric's lighting service rates?
12 A. Eastern offers only one lighting service rate to its customers, Rate S-1. Eastern's Rate
13 S-1 provides customers with a wide choice of lighting fixtures (streetlights, floodlights,
14 and area lights) mounted on distribution or specialty lighting poles served from overhead
15 or underground conductors. All lighting equipment (luminaires, poles, conductors, etc.)
16 required to provide service under Rate S-1 is furnished, installed, owned, and maintained
17 by Eastern. For certain fixture-pole combinations, Eastern permits customers to pay the
18 initial cost of installation by a contribution in aid of construction to obtain a lower
19 monthly rate.
20
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 14 of 18
1 Mass. Electric provides a broader selection of lighting services than does Eastern. Mass.
2 Electric offers four lighting service rates to its customers: Rates S-1, S-2, S-3, and S-20.
3 Rate S-1 is similar in its applicability to Eastern's Rate S-1. Rates S-2 and S-3 provide
4 for partial or full ownership of lighting equipment by customers. Rate S-20 is a special
5 rate for customers seeking to convert their existing incandescent and mercury vapor lights
6 to sodium vapor lights. Mass. Electric also has currently pending before the Department
7 Rate S-5 for municipal customers choosing to purchase streetlighting equipment from
8 Mass. Electric pursuant to Section 34A of the Electric Utility Restructuring Act of 1997.
9
10 Eastern's Rate S-1 is mapped to Mass. Electric's Rate S-1 because of the similarity in
11 their applicability provisions.
12
13 IV. Derivation of Billing Determinants for Eastern's Customers under Mass. Electric's
14 Rates
15 Q. Please summarize how billing determinants for Eastern's customers under Mass.
16 Electric's rates are derived.
17 A. Billing determinants are customer usage parameters that are applied to the component
18 charges of a rate schedule to calculate a customer's bill. Examples of commonly used
19 billing determinants are the number of bills, monthly energy consumption, and monthly
20 maximum demand. The precise definition of a billing determinant is dependent upon the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 15 of 18
1 rate to which it is applied. Consequently, the derivation of billing determinants for a
2 customer depends upon which rate the customer is currently served as well as the rate
3 which the customer is to be transferred.
4
5 In some cases, the billing determinants for Eastern's customers under Mass. Electric's
6 rates are the same determinants Eastern uses to bill these same customers under its rates.
7 This is exactly the case for Eastern's customers served under Rates R-1, R-2, R-3, R-4,
8 G-1, W-1, and S-1 that will be transferred to Mass. Electric's Rates R-1, R-2, G-1, and S-
9 1.
10
11 In all other cases, the billing determinants for Eastern's customers under Mass. Electric's
12 rates must be calculated or estimated, at least for some of the customers being transferred
13 from a particular Eastern rate to a particular Mass. Electric rate. All of Eastern's
14 customers served under its general service rates and all of Eastern's customers served
15 under its supplementary rates require the calculation or estimation of billing determinants
16 under Mass. Electric's rates.
17
18 Exhibit JJB-2 shows the billing determinants for each Eastern to Mass. Electric rate
19 mapping. Each mapping is shown on a separate page, and, where appropriate,
20 explanatory notes detailing how the billing determinants were derived is included on the
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 16 of 18
1 page.
2
3 Q. Why is it necessary to estimate billing determinants for some customers?
4 A. It is necessary to estimate billing determinants for customers where Eastern's definition
5 of a billing determinant is different from that of Mass. Electric's and/or Eastern does not
6 record, or does not have readily available, the data required to calculate the determinant.
7 The determinants estimated are billing demands and time-differentiated energy
8 consumption. For example, Eastern's Rate H-1 non-demand metered customers
9 transferring to Mass. Electric's Rate G-2 require the estimation of billing demands. A
10 second example are Eastern's Rate G-6 customers transferring to Mass. Electric's Rate
11 G-3. This transfer requires the estimation of peak-hours maximum demand, peak-hours
12 energy, and off-peak-hours energy values. Exhibit JJB-2 details each instance where
13 estimated determinants are required.
14
15 Q. In general, is Eastern's definition of billing demand substantially different from Mass.
16 Electric's?
17 A. No, it is not. Both companies define demand as a fifteen-minute integrated demand,
18 define billing demand as the maximum demand over all hours for non-time-differentiated
19 rates, and define billing demand as the maximum demand within peak hours for time-
20 differentiated rates. The companies differ in the details of their definitions with respect to
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 17 of 18
1 minimum billing demand (Mass. Electric only), maximum billing demand (Eastern only),
2 and conversion of kilovolt-ampere demand to kilowatt demand (Mass. Electric only).
3
4 Q. Is Eastern's definition of time periods for its time-differentiated rates substantially
5 different from Mass. Electric's?
6 A. Yes, it is. Eastern defines it time periods as follows:
7 Peak Hours
8 Monday through Friday excluding holidays:
9 April through September, 11:00 a.m. to 4:00 p.m.
10 October through March, 8:00 a.m. to 12:00 noon, and
11 4:00 p.m. to 7:00 p.m.
12 Off-Peak Hours
13 All other hours.
14
15 Mass. Electric defines it time periods as follows:
16 Peak Hours
17 Monday through Friday excluding holidays:
18 January through December 8:00 a.m. to 9:00 p.m.
19 Off-Peak Hours
20 All other hours.
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of James J. Bonner, Jr.
Page 18 of 18
1 Both companies define holidays as follows:
2 New Year's Day Columbus Day
3 President's Day Veteran's Day
4 Memorial Day Thanksgiving Day
5 Independence Day Christmas Day
6 Labor Day
7
8 V. Conclusion
9 Q. Does this conclude your testimony?
10 A. Yes, it does.
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
EXHIBITS
OF
JAMES J. BONNER, JR.
Exhibit JJB-1 Comparison of Availability Provisions of Rates
Exhibit JJB-2 Billing Determinants
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JJB-1
Comparison of Availability Provisions of Rates
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-___
Exhibit JJB-1
Page 1 of 6
MASSACHUSETTS ELECTRIC COMPANY
EASTERN EDISON COMPANY
Comparison of Availability Provisions of Rates
EASTERN'S RATE MASS. ELECTRIC'S RATE
RESIDENTIAL RETAIL DELIVERY SERVICE RESIDENTIAL REGULAR R-1 RETAIL
RATE R-1 DELIVERY SERVICE
Available only to residential Available for all domestic purposes
customers for domestic purposes. in an individual private dwelling
or an individual apartment and for
church and farm purposes.
LOW INCOME RESIDENTIAL RETAIL RESIDENTIAL LOW INCOME R-2 RETAIL
DELIVERY SERVICE RATE R-2 DELIVERY SERVICE
Available upon verification of a Available upon verification of a
low-income Customer receipt of low-income Customer's receipt of
any means-tested public benefit, or any means-tested public benefit, or
verification of eligibility for the verification of eligibility for the
low- income home energy assistance low- income home energy assistance
program, or its successor program, program, or its successor program,
for which eligibility does not for which eligibility does not
exceed 175 percent of the federal exceed 175 percent of the federal
poverty level based on a poverty level based on a
household's gross income. The household's gross income. It is the
customer will be required to responsibility of the customer to
annually certify his or her annually certify, by forms provided
continued eligibility for this Rate by the utility, the continued
Schedule. compliance with the foregoing
qualifications.
RESIDENTIAL SPACE HEATING RETAIL
DELIVERY SERVICE RATE R-3
Available only to residential
customers where electricity is the
sole source of energy used for
comfort heating and water heating.
TOU RESIDENTIAL RETAIL DELIVERY RESIDENTIAL TIME-OF-USE (OPTIONAL)
SERVICE RATE R-4 R-4 RETAIL DELIVERY SERVICE
Available only to residential Available for all domestic purposes
customers. in an individual private dwelling
or an individual apartment and for
church and farm purposes. Any
residential customer whose average
usage exceeds 2,500 kWh/month for a
12 month period may elect delivery
service under this rate effective
with installation of appropriate
metering.
SMALL SECONDARY VOLTAGE GENERAL GENERAL SERVICE -- SMALL COMMERCIAL
RETAIL DELIVERY SERVICE RATE G-1 AND INDUSTRIAL G-1 RETAIL DELIVERY
SERVICE
Available to customers whose actual
or estimated annual maximum monthly Available for all purposes. A new
demand is less than 10 kW and Customer will begin service on this
annual energy consumption is less rate if the Company estimates that
than 36,000 kWh. its average use will not exceed
10,000 kWh/month or 200 kW of
demand.
MEDIUM SECONDARY VOLTAGE GENERAL GENERAL SERVICE DEMAND G-2 RETAIL
RETAIL DELIVERY SERVICE RATE G-2 DELIVERY SERVICE
Available only to customers whose Available for all purposes. A new
actual or estimated annual maximum customer will begin delivery on
monthly demand is at least 10 kW this rate if the Company estimates
but less than 500 kW or whose that its average use will exceed
actual or estimated annual energy 10,000 kWh/month, but not exceed
consumption is 36,000 kWh or more. 200 kW of Demand.
TIME-OF-USE G-3 RETAIL DELIVERY
SERVICE
Available for all purposes. A new
Customer will begin delivery
service on this rate if the
Company estimates that its average
use will exceed 200 kW of Demand.
LARGE SECONDARY VOLTAGE GENERAL
RETAIL DELIVERY SERVICE RATE G-4
Mandatory for all customers whose
actual or estimated annual maximum
monthly demand is 500 kW or more.
MEDIUM PRIMARY VOLTAGE GENERAL
RETAIL DELIVERY SERVICE RATE G-5
Mandatory for all customers whose
actual or estimated annual maximum
monthly demand is at least 100 kW
but less than 500 kW.
LARGE PRIMARY VOLTAGE GENERAL
RETAIL DELIVERY SERVICE RATE G-6
Mandatory for all customers whose
actual or estimated annual maximum
monthly demand is 500 kW or more.
MEDIUM TOU SECONDARY VOLTAGE
GENERAL RETAIL DELIVERY SERVICE
RATE T-2
Available to all customers whose
actual or estimated annual maximum
monthly demand is at least 10 kW
but less than 500 kW or whose
actual or estimated annual energy
consumption is 36,000 kWh or more.
LARGE PRIMARY VOLTAGE AUXILIARY
GENERAL RETAIL DELIVERY SERVICE
RATE A-6
Available to any Customer of record
prior to March 1, 1997, who
furnishes its own electric power
supply for all or part of its total
electric retail delivery service
requirements.
EXPERIMENTAL FLEXIBLE TIME-OF-USE
PRICING G-5
Not available to new customers
after February 26, 1997. Customers
may remain on this rate until the
contract anniversary date
following the date of retail
access for all Customers. However,
Customers choosing to leave the
rate before their annual
anniversary date will be required
to refund any Customer base load
savings achieved over the
Company's U-3 Rate and/or G-3
Rate, between the termination date
of service under the G-5 Rate and
the previous contract anniversary
date. All customers served on this
rate must elect to take their
total electric service under the
metering installation as approved
by the Company.
SCHEDULED INTERRUPTIBLE SERVICE
RATE I-1
This rate is closed to new
customers as of February 26, 1997.
Service under this rate is
available only for electric
equipment under the control of the
Company. Electric service for all
other purposes at the customer
location will be provided under
the applicable rate in effect and
available.
GENERAL SPACE HEATING RETAIL
DELIVERY SERVICE RATE H-1
Available only to non-residential
Customers where electricity, or
electricity in conjunction with a
renewable energy source, is the
sole source of energy used for
comfort heating and water heating.
GENERAL HEATING RETAIL DELIVERY
SERVICE RATE H-2
Closed to new Customers. Available
to customers that were taking
service under former General
Heating Service Rate 35 before
1-24-89, where electricity, or
electricity in conjunction with a
renewable energy source, is the
sole source of energy used for
space heating, cooking, air
conditioning or water heating for
other than industrial purposes.
CONTROLLED WATER HEATING RETAIL
DELIVERY SERVICE RATE W-1
Closed to new Customers. Available
to Customers that were taking
retail delivery service from the
Company under former Off-Peak Water
Heating Rate 41 before 1-24-89.
LIGHTING RETAIL DELIVERY SERVICE STREET AND SECURITY LIGHTING
RATE S-1 COMPANY OWNED EQUIPMENT S-1
Available only to Customers where Available to any Customer where the
electricity is supplied to lighting necessary fixtures can be supported
equipment owned and maintained by on the Company's existing poles and
the Company on Company owned poles, where such service can be supplied
for dusk-to-dawn operation of directly from existing secondary
approximately 4,000 burning hours voltage circuits.
per year.
STREET LIGHTING -OVERHEAD-CUSTOMER
OWNED EQUIPMENT S-2
Available for street lighting
installations owned by any city or
town or other public authority,
hereinafter referred to as the
Customer, for street lighting
installations served by overhead
conductors. This rate is closed
for service to new applicants or
lights effective March 1, 1998.
STREET LIGHTING - UNDERGROUND -
DIVISION OF OWNERSHIP S-3
Available to any city, town or
other public authority,
hereinafter referred to as the
Customer, only for street lighting
installations served by
underground conductors and
involving a division of ownership
and service.
STREET LIGHTING - COMPANY OWNED
EQUIPMENT S-20
Available to any Customer on Rate
S-1 which agrees to convert all
existing incandescent and mercury
vapor source lights to
sodium-vapor source lights.
<PAGE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
Exhibit JJB-2
Billing Determinants
<PAGE>
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
R-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 1 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Eastern's Rate R-1 v. Mass. Electric's Rate R-1
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- ------------------------------------------------
Bills 1,705,214 1,705,214
Energy (kWh) 897,383,838 897,383,838
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
R-2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 2 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Eastern's Rate R-2 v. Mass. Electric's Rate R-2
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- --------------------------------------------------
Bills 168,433 168,433
Energy (kWh) 67,148,463 67,148,463
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
R-3 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 3 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Eastern's Rate R-3 v. Mass. Electric's Rate R-1
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- ---------------------------------------------------
Bills 70,418 70,418
Energy (kWh) 70,618,533 70,618,533
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
R-4 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 4 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Eastern's Rate R-4 v. Mass. Electric's Rate R-1
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- ---------------------------------------------------
Bills 544 544
Energy (kWh) 577,111 577,111
Peak Energy (kWh) 82,953 n/a
Off-Peak Energy (KWh) 494,158 n/a
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
G-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 5 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Eastern's Rate G-1 v. Mass. Electric's Rate G-1
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------
Bills 213,705 213,705
Energy (kWh) 109,098,086 109,098,086
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
G-2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 6 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Note:
Eastern's Rate G-2: Total
1. Eastern's Rate G-2
Eastern's determinants were apportioned
Billing Billing among Mass. Electric's Rates
Parameter Determinant G-1, G-2 and G-3 based on the
- ------------------------------- availability provisions of
Bills 82,096 Mass. Electric's rates.
Demand (kW) 2,850,756
Energy (kWh) 839,614,746 2. For those Eastern Rate G-2
customers to be transferred to
Mass. Electric's Rate G-3, the
billing determinants were
estimated based upon Eastern's
Rate G-2 load research data
using Mass. Electric's TOU
hours. Kilowatthours were split
equally between peak and off
peak periods.
Eastern's Rate G-2 v. Mass.
Electric's Rate G-1
- ---------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------
Bills 61,760 61,760
Demand (kW) 1,041,483 n/a
Energy (kWh) 241,828,775 241,828,775
Eastern's Rate G-2 v. Mass. Electric's Rate G-2
- -----------------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- --------------------------------------------------
Bills 18,542 18,542
Demand (kW) 1,300,741 1,300,741
Energy (kWh) 424,245,027 424,245,027
Eastern's Rate G-2 v. Mass. Electric's Rate G-3
- ------------------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- ---------------------------------------------------
Bills 1,794 1,794
Demand (kW) 508,532 513,617
Energy (kWh) 173,540,944 173,540,944
Peak Energy (kWh) n/a 86,770,472
Off-Peak Energy (kWh) n/a 86,770,472
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
G-4 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 7 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Eastern's Rate G-4 v. Mass. Note:
Electric's Rate G-3 1. The billing determinants were
estimated based upon Eastern's
Rate G-4 load research data
using Mass. Electric's TOU
hours.
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------
Bills 1,097 1,097
Demand (kW) 794,802 822,620
Energy (kWh) 344,807,994 344,807,994
Peak Energy (kWh) 76,958,311 162,059,757
Off-Peak Energy (267,849,683 182,748,237
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
G-5 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 8 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998,
Billing Determinants
Note:
Eastern's Rate G-5: Total 1. Eastern's Rate G-5 billing
demand is maximum monthly peak
Eastern's hours demand. Mass. Electric's
Billing Billing Rate G-2 billing demand is
Parameter Determinant maximum monthly demand.
- ------------------------------------ Eastern's Rate G-5 billing
Bills 402 demand was recalculated to
Demand (kW) 76,191 conform with Mass. Electric's
Energy (kWh) 25,376,160 definition.
Peak Energy (kWh) 6,315,790
Off-Peak Energy (kWh) 19,060,370 2. For those Eastern Rate G-5
customers to be transferred to
Mass. Electric's Rate G-3, the
billing determinants were
estimated based upon Eastern's
Rate G-5 load research data
using Mass. Electric's TOU
hours.
Eastern's Rate G-5 v. Mass.
Electric's Rate G-2
- ---------------------------
Eastern's Mass. Electric 3. Eastern's Rate G-5 is a
Billing Billing Billing primary distribution voltage
Parameter Determinant Determinant rate. By definition, all of
- ------------------------------------------ Eastern's Rate G-5 customers
Bills 168 168 meet the criteria for receiving
Demand (kW) 20,285 21,096 Mass. Electric's Rate G-3 high
Energy (kWh) 7,126,400 7,126,400 voltage discount.
Peak Energy (kWh) 1,672,460 n/a
Off-Peak Energy (kWh) 5,453,940 n/a
Eastern's Rate G-5 v. Mass. Electric's
Rate G-3
- --------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- --------------------------------------------------
Bills 234 234
Demand (kW) 55,906 60,155
Energy (kWh) 18,249,760 18,249,760
Peak Energy (kWh) 4,643,330 9,672,373
Off-Peak Energy (kWh) 13,606,430 8,577,387
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
G-6 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 9 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing
Determinants
Note:
Eastern's Rate G-6 v. Mass. 1. The billing determinants
Electric's Rate G-3 were estimated based upon
- ----------------------------- Eastern's Rate G-6 load
research data using Mass.
Electric's TOU hours.
Eastern's Mass. Electric's
Billing Billing Billing 2. Eastern's Rate G-6 is a
Parameter Determinant Determinant primary distribution voltage
- ------------------------------------------ rate. By definition, all of
Eastern's Rate G-6 customers
Bills 380 380 meet the criteria for
Demand (kW) 439,150 513,806 receiving Mass. Electric's
Energy (kWh) 194,448,972 194,448,972 Rate G-3 high voltage
Peak Energy (kWh) 38,898,442 85,557,548 discount.
Off-Peak Energy
(kWh) 155,550,530 108,891,424
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
T-2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 10 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Note:
Eastern's Rate T-2: Total 1. Eastern's Rate T-2 billing
Eastern's demand is maximum monthly
Billing Billing peak hours demand. Mass.
Parameter Determinant Electric's Rate G-2 billing
- ----------------------------------- demand is maximum monthly
Bills 1,199 demand. Eastern's Rate T-2
Demand (kW) 155,613 billing demand was
Energy (kWh) 73,073,922 recalculated to conform with
Peak Energy (kWh) 14,145,295 Mass. Electric's definition.
Off-Peak Energy (kWh) 58,928,627
2. For those Eastern Rate T-2
customers to be transferred
Eastern's Rate T-2 v. Mass. to Mass. Electric's Rate G-3,
Electric's Rate G-1 the billing determinants were
- --------------------------- estimated based upon
Eastern's Rate T-2 load
Mass research data using Mass.
Eastern's Electric's Electric's TOU hours.
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------
Bills 297 297
Demand (kW) 4,390 n/a
Energy (kWh) 1,178,927 1,178,927
Peak Energy (kWh) 205,124 n/a
Off-Peak Energy (kWh) 973,803 n/a
Eastern's Rate T-2 v. Mass. Electric's
Rate G-2
- ---------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------
Bills 554 554
Demand (kW) 42,478 45,027
Energy (kWh) 18,743,578 18,743,578
Peak Energy (kWh) 3,623,614 n/a
Off-Peak Energy (kWh) 15,119,964 n/a
Eastern's Rate T-2 v. Mass.
Electric's Rate G-3
- ---------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- --------------------------------------------------
Bills 348 348
Demand (kW) 108,745 111,790
Energy (kWh) 53,151,417 53,151,417
Peak Energy (kWh) 10,316,557 22,323,595
Off-Peak Energy (kWh) 42,834,860 30,827,822
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
H-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 11 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing
Determinants
Note:
Eastern's Rate H-1: Total 1. Eastern's Rate H-1
non-demand metered customers
Eastern's are to be transferred to
Billing Billing Mass. Electric's Rate G-1.
Parameter Determinant
- ------------------------------- 2. Eastern's Rate H-1
determinants were apportioned
Bills 1,314 among Mass. Electric's Rates
Demand (kW) 38,217 G-1, G-2 and G-3 based on the
availability provisions of
Mass. Electric's rates.
3. For Eastern's Rate H-1
customers to be transferred
to Mass. Electric's Rate G-2,
all of the customers are
demand metered.
Eastern's Rate H-1 v. Mass. Electric's 4. For Eastern's Rate H-1
Rate G-1 customers to be transferred
- -------------------------------------- to Mass. Electric's Rate G-3,
Mass the billing determinants were
Eastern's Electric estimated based upon
Billing Billing Billing Eastern's Rate H-1 load
Parameter Determinant Determinant research data using Mass.
- ------------------------------------------- Electric's TOU hours.
Bills 1,231 1,231
Energy (kWh) 2,545,293 2,545,293
Eastern's Rate H-1 v. Mass. Electric's
Rate G-2
- ---------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------
Bills 35 35
Demand (kW) 3,427 3,427
Energy (kWh) 704,880 704,880
Eastern's Rate H-1 v. Mass. Electric's
Rate G-3
- --------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -----------------------------------------------
Bills 48 48
Demand (kW) 34,790 38,617
Energy (kWh) 6,702,200 6,702,200
Peak Energy (kWh) n/a 3,552,166
Off Peak Energy (kWh) n/a 3,150,034
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
H-2 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 12 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing
Determinants
Note:
Eastern's Rate H-2: Total 1. Eastern's Rate H-2
determinants were apportioned
Eastern's among Mass. Electric's Rates
Billing Billing G-1 and G-2 based on the
Parameter Determinant availability provisions of
- ------------------------------- Mass. Electric's rates.
Bills 1,991
Demand (kW) 496
Energy (kWh) 2,434,682
Eastern's Rate H-2 v. Mass.
Electric's Rate G-1
- -----------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- ------------------------------------------------
Bills 1,979 1,979
Energy (kWh) 2,299,322 2,299,322
Eastern's Rate H-2 v. Mass. Electric's
Rate G-2
- ---------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- --------------------------------------------------
Bills 12 12
Demand (kW) 496 496
Energy (kWh) 135,360 135,360
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
W-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 13 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998,
Billing Determinants
Note:
Eastern's Rate W-1: Total 1. Eastern's Rate W-1
determinants were apportioned
Eastern's among Mass. Electric's Rates
Billing Billing R-1 and G-1 based on the
Parameter Determinant availability provisions of
- ------------------------- Mass. Electric's rates.
Bills 189,269
Energy (kWh) 49,476,751
Eastern's Rate W-1 v. Mass.
Electric's Rate R-1
- ---------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------
Bills 186,554 186,554
Energy (kWh) 48,697,330 48,697,330
Eastern's Rate W-1 v. Mass. Electric's
Rate G-1
- --------------------------------------
Eastern's Mass. Electric's
Billing Billing Billing
Parameter Determinant Determinant
- --------------------------------------------
Bills 2,715 2,715
Energy (kWh) 779,421 779,421
Fixture
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
S-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 14 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Month Ending December 31, 1998, Billing Determinants
Eastern's Rate S-1 Streetlighting Rate
<TABLE>
<CAPTION>
Eastern's Service Eastern's Eastern's
Eastern's Lamp Lumen & Pole Fixture Special Fixture Annual kWh Total Annual
Lighting Code Wattage Size Type Type Pricing Option Count per Light Energy
- ----------------------------------------------------------------------------------------------------------
Metal Halide
<S> <C> <C> <C> <C> <C> <C> <C> <C>
0300-4-120 250 20,000 OH_WoodLine FldLt 9 1,180 10,620
0300-4-220 250 20,000 OH_WoodLitg FldLt 2 1,180 2,360
0466-4-120 400 40,000 OH_WoodLine FldLt 39 1,832 71,448
1080-4-120 1,000 115,000 OH_WoodLine FldLt 4 4,247 16,988
---------- -----------
Total Metal Halide 54 101,416
- -----------------------------------------------------------------------------------------------------
Incandescent
0103-1-110 103 1,000 OH_WoodLine StLt 2 405 810
0202-1-110 202 2,500 OH_WoodLine StLt 1 794 794
---------- -----------
Total Incandescent 3 1,604
- -------------------------------------------------------------------------------------------------
Mercury Vapor
0130-2-110 100 4,200 OH_WoodLine StLt 269 511 137,459
0130-2-810 100 4,200 URD_LamWood StLt 14 511 7,154
0130-2-811 100 4,200 URD_LamWood StLt CustPaidPole 2 511 1,022
0130-2-941 100 4,200 URD_WoodPost T&C CustPaidPole 4 511 2,044
0209-2-110 175 8,600 OH_WoodLine StLt 39 822 32,058
0209-2-130 175 8,600 OH_WoodLine PBU 226 822 185,772
0209-2-211 175 8,600 OH_WoodLitg StLt CustPaidPole 1 822 822
0209-2-231 175 8,600 OH_WoodLitg PBU CustPaidPole 7 822 5,754
0209-2-541 175 8,600 UG_Steel T&C CustPaidPole 37 822 30,414
0209-2-610 175 8,600 UG_Aluminum StLt 5 822 4,110
0300-2-110 250 12,100 OH_WoodLine StLt 3 1,180 3,540
0474-2-110 400 22,500 OH_WoodLine StLt 15 1,864 27,960
0474-2-120 400 22,500 OH_WoodLine FldLt 174 1,864 324,336
0474-2-130 400 22,500 OH_WoodLine PBU 30 1,864 55,920
0474-2-211 400 22,500 OH_WoodLitg StLt CustPaidPole 8 1,864 14,912
0474-2-221 400 22,500 OH_WoodLitg FldLt CustPaidPole 42 1,864 78,288
0474-2-231 400 22,500 OH_WoodLitg PBU CustPaidPole 1 1,864 1,864
1135-2-120 1,000 63,000 OH_WoodLine FldLt 34 4,463 151,742
1135-2-221 1,000 63,000 OH_WoodLitg FldLt CustPaidPole 5 4,463 22,315
---------- -----------
Total Mercury Vapor 916 1,087,486
- -------------------------------------------------------------------------------------------------
Sodium Vapor
0061-3-110 50 3,300 OH_WoodLine StLt 4,424 240 1,061,760
0061-3-211 50 3,300 OH_WoodLitg StLt CustPaidPole 5 240 1,200
0061-3-941 50 3,300 URD_WoodPost T&C CustPaidPole 2 240 480
0085-3-110 70 5,800 OH_WoodLine StLt 14,491 334 4,839,994
0085-3-120 70 5,800 OH_WoodLine FldLt 111 334 37,074
0085-3-210 70 5,800 OH_WoodLitg StLt 3 334 1,002
0085-3-211 70 5,800 OH_WoodLitg StLt CustPaidPole 20 334 6,680
0085-3-221 70 5,800 OH_WoodLitg FldLt CustPaidPole 2 334 668
0085-3-441 70 5,800 URD_FiberglasT&C CustPaidPole 118 334 39,412
0085-3-461 70 5,800 URD_FiberglasSBA CustPaidPole 146 334 48,764
0085-3-641 70 5,800 UG_Aluminum T&C CustPaidPole 3 334 1,002
S:\RADATA1\EASTED\Jjb_2a.wk4 New England Electric System
S-1 Eastern Utilities Associates
15-Jun-99 M.D.T.E. Docket No. 99-____
Exhibit JJB-2
Page 15 of 15
Massachusetts Electric Company
Eastern Edison Company
Apportionment of Company Billing Determinants
Month Ending December 31, 1998, Billing Determinants
Eastern's Rate S-1 Streetlighting Rate
Eastern's Service Eastern's Eastern's
Eastern's Lamp Lumen & Pole Fixture Special Fixture Annual kWh Total Annual
Lighting Code Wattage Size Type Type Pricing Option Count per Light Energy
- ----------------------------------------------------------------------------------------------------------
0085-3-711 70 5,800 UG_WoodLitg StLt CustPaidPole 7 334 2,338
0085-3-811 70 5,800 URD_LamWood StLt CustPaidPole 199 334 66,466
0085-3-941 70 5,800 URD_WoodPost T&C CustPaidPole 222 334 74,148
0121-3-110 100 9,500 OH_WoodLine StLt 7,510 476 3,574,760
0121-3-130 100 9,500 OH_WoodLine PBU 357 476 169,932
0121-3-211 100 9,500 OH_WoodLitg StLt CustPaidPole 88 476 41,888
0121-3-230 100 9,500 OH_WoodLitg PBU 1 476 476
0121-3-231 100 9,500 OH_WoodLitg PBU CustPaidPole 39 476 18,564
0121-3-441 100 9,500 URD_FiberglasT&C CustPaidPole 46 476 21,896
0121-3-460 100 9,500 URD_FiberglasSBA 4 476 1,904
0121-3-461 100 9,500 URD_FiberglasSBA CustPaidPole 28 476 13,328
0121-3-610 100 9,500 UG_Aluminum StLt 29 476 13,804
0121-3-631 100 9,500 UG_Aluminum PBU CustPaidPole 3 476 1,428
0121-3-641 100 9,500 UG_Aluminum T&C CustPaidPole 31 476 14,756
0121-3-651 100 9,500 UG_Aluminum PMA CustPaidPole 18 476 8,568
0121-3-711 100 9,500 UG_WoodLitg StLt CustPaidPole 29 476 13,804
0121-3-811 100 9,500 URD_LamWood StLt CustPaidPole 41 476 19,516
0121-3-940 100 9,500 URD_WoodPost T&C 3 476 1,428
0121-3-941 100 9,500 URD_WoodPost T&C CustPaidPole 279 476 132,804
0176-3-110 150 16,000 OH_WoodLine StLt 125 692 86,500
0176-3-120 150 16,000 OH_WoodLine FldLt 90 692 62,280
0176-3-211 150 16,000 OH_WoodLitg StLt CustPaidPole 10 692 6,920
0176-3-220 150 16,000 OH_WoodLitg FldLt 2 692 1,384
0176-3-221 150 16,000 OH_WoodLitg FldLt CustPaidPole 2 692 1,384
0176-3-610 150 16,000 UG_Aluminum StLt 37 692 25,604
0176-3-611 150 16,000 UG_Aluminum StLt CustPaidPole 2 692 1,384
0176-3-614 150 16,000 UG_Aluminum StLt AddlFixt 15 692 10,380
0324-3-110 250 25,000 OH_WoodLine StLt 2,129 1,274 2,712,346
0324-3-120 250 25,000 OH_WoodLine FldLt 1,030 1,274 1,312,220
0324-3-124 250 25,000 OH_WoodLine FldLt AddlFixt 1 1,274 1,274
0324-3-210 250 25,000 OH_WoodLitg StLt 1 1,274 1,274
0324-3-211 250 25,000 OH_WoodLitg StLt CustPaidPole 46 1,274 58,604
0324-3-220 250 25,000 OH_WoodLitg FldLt 1 1,274 1,274
0324-3-221 250 25,000 OH_WoodLitg FldLt CustPaidPole 85 1,274 108,290
0324-3-610 250 25,000 UG_Aluminum StLt 681 1,274 867,594
0324-3-611 250 25,000 UG_Aluminum StLt CustPaidPole 9 1,274 11,466
0324-3-621 250 25,000 UG_Aluminum FldLt CustPaidPole 1 1,274 1,274
0324-3-624 250 25,000 UG_Aluminum FldLt AddlFixt 10 1,274 12,740
0324-3-711 250 25,000 UG_WoodLitg StLt CustPaidPole 1 1,274 1,274
0500-3-110 400 50,000 OH_WoodLine StLt 581 1,966 1,142,246
0500-3-120 400 50,000 OH_WoodLine FldLt 4,258 1,966 8,371,228
0500-3-124 400 50,000 OH_WoodLine FldLt AddlFixt 2 1,966 3,932
0500-3-210 400 50,000 OH_WoodLitg StLt 2 1,966 3,932
0500-3-211 400 50,000 OH_WoodLitg StLt CustPaidPole 67 1,966 131,722
0500-3-220 400 50,000 OH_WoodLitg FldLt 48 1,966 94,368
0500-3-221 400 50,000 OH_WoodLitg FldLt CustPaidPole 426 1,966 837,516
0500-3-224 400 50,000 OH_WoodLitg FldLt AddlFixt 1 1,966 1,966
0500-3-610 400 50,000 UG_Aluminum StLt 99 1,966 194,634
0500-3-614 400 50,000 UG_Aluminum StLt AddlFixt 6 1,966 11,796
0500-3-620 400 50,000 UG_Aluminum FldLt 28 1,966 55,048
0500-3-621 400 50,000 UG_Aluminum FldLt CustPaidPole 10 1,966 19,660
0500-3-624 400 50,000 UG_Aluminum FldLt AddlFixt 111 1,966 218,226
0500-3-721 400 50,000 UG_WoodLitg FldLt CustPaidPole 1 1,966 1,966
0648-3-612 500 25,000 UG_Aluminum StLt TwinFixts 61 2,548 155,428
---------- -----------
Total Sodium Vapor 38,238 26,758,978
- -------------------------------------------------------------------------------------------------
Total Streetlighting Billing Determinants 39,211 27,949,484
========== ===========
</TABLE>
<PAGE>
New England Electric System and
Eastern Utilities Associates
Massachusetts Electric Company and
Eastern Edison Company Rate Plan
Filing in Support of Merger
Volume 3
Testimony and Exhibits of:
David J. Hoffman & Richard J. Levin
April 30, 1999
Submitted to:
Massachusetts Department of
Telecommunications and Energy
Docket D.T.E. 99-_____
Submitted by:
Nees Logo
Eastern Utilities Associates Logo
<PAGE>
Commonwealth of Massachusetts
Department of Telecommunications and Energy
- ------------------------------------
)
New England Electric System ) Docket D.T.E. 99-__
Eastern Utilities Associates )
)
- ------------------------------------
DIRECT TESTIMONY
OF
DAVID J. HOFFMAN AND
RICHARD J. LEVIN
Table of Contents
Page
I. Introduction and Qualifications.................................... 1
II. Summary of Testimony............................................... 6
III. Detailed Estimate of Cost Savings.................................. 12
A. Summary of Personnel and Non-Personnel Savings................ 12
B. Personnel Savings............................................. 13
C. Information Systems Savings (Non-Personnel)................... 17
D. Supply Chain Savings (Non-Personnel).......................... 18
E. Facilities Savings (Non-Personnel)............................ 20
F. Administrative and General Savings (Non-Personnel)............ 20
G. Comparison with Other Transactions............................ 24
IV. Detailed Estimate of Cost to Achieve............................... 26
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 1 of 29
<S> <C> <C>
1 I. Introduction and Qualifications
2 Q. Please state your names, current positions and business addresses.
3 A. My name is David J. Hoffman. I am a Vice President with Mercer Management
4 Consulting, Lexington, Massachusetts.
5
6 My name is Richard J. Levin. I am a management consultant with Mercer
7 Management Consulting, Lexington, Massachusetts.
8
9 Q. Mr. Hoffman, please summarize your educational and professional background.
10 A. I received a B.S. degree in finance in 1976 and a MBA degree (with honors) in
11 management information systems in 1980 from Boston University.
12
13 My professional experience includes over 15 years as a consultant to electric and gas
14 utilities. I joined Mercer in 1982 and prior to that, worked for United Information
15 Systems (from 1980 to 1982).
16
17 During my consulting career, I have led a broad range of assignments, encompassing:
18 o Merger and acquisition analysis
19 o Organizational and performance improvement
20 o Strategic and business planning
21 o Information systems strategy
22
Hoffman/Levin
-1-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 2 of 29
1 Q. Mr. Levin, please summarize your educational and professional background.
2 A. I received a B.A. in economics from Washington University in 1972 and an M.A. in
3 economics from The Ohio State University in 1974. In 1977, I received a J.D. degree
4 from Ohio State and was admitted to the Ohio Bar.
5
6 My professional experience includes over nineteen years as a management consultant
7 specializing in the management and regulation of utilities. I joined Mercer in May 1983 and,
8 prior to that, worked as an independent consultant (June 1982 through April 1983) and for
9 Booz, Allen & Hamilton, Inc. (April 1979 through May 1982).
10
11 During my consulting career, I have served as a project manager or lead consultant on a broad
12 range of assignments for utilities and regulatory commissions. The subject matter of these
13 assignments has encompassed:
14 o Merger and acquisition analysis
15 o Organizational and performance improvement
16 o Strategic and business planning
17 o Management audits
18 o Rate of return and cost of capital studies
19 o Financial forecasting and planning
20 o Economic and financial feasibility evaluations
21
22 Prior to my consulting career, I was a lecturer at Ohio State in economic theory and corporate
23 finance. I held that position from January 1978 through March 1979. From June 1975 to
24 September 1978, I was employed by the Public Utilities Commission of Ohio. From 1975 to
Hoffman/Levin
-2-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 3 of 29
1 1977, I served as a financial economist with the Commission's staff and testified on rate of
2 return and financial issues in electric, gas, telephone, and water rate cases. After graduation
3 from law school in 1977, I became a Hearing Examiner for the Commission. My primary
4 responsibilities in that position were presiding over rate and other proceedings, drafting
5 proposed rules, and preparing written orders for the Commission's consideration.
6
7 I have testified before the Massachusetts Department of Public Utilities, the Maine
8 Public Utilities Commission, and the Ohio Public Utilities Commission on the cost of
9 capital. I have also testified before the Maine PUC, New Mexico Public Service
10 Commission, the Iowa State Commerce Commission, the Pennsylvania Public Utility
11 Commission, and the Massachusetts Appellate Tax Board on other regulatory issues.
12
13 Q. Mr. Hoffman and Mr. Levin, please summarize your relevant experience.
14 A. Over the past several years, we have both been actively involved in the merger and
15 acquisitions (M&A) area. This work has included 1) screening and evaluating
16 potential merger candidates, 2) estimating cost savings for approximately 15 potential
17 mergers, and 3) assisting utilities in post-merger integration planning.
18
19 We have also been involved in organizational and/or performance improvement work at more
20 than 30 utilities. This work has been done for utility clients and on behalf of regulatory
21 commissions (as part of management audits). This work has included organizational design,
Hoffman/Levin
-3-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 4 of 29
1 determining appropriate staffing levels, process redesign, and identifying opportunities to
2 reduce costs. The work has encompassed all aspects of the utility business (generation,
3 transmission, distribution, customer and marketing-related, and A&G functions). With
4 respect specifically to A&G activities, we have both been involved in assignments dealing
5 with the following functions: information services, accounting, human resources, finance and
6 treasury, supply chain management, legal, rates and regulatory affairs, and corporate
7 communication and external affairs.
8
9 Important elements of this work have been benchmarking a particular utility's performance
10 against other companies and understanding the drivers of costs on the overall business and on
11 specific functions. We are also two of the principal authors of Mercer's utility staffing
12 survey. This survey has become an industry standard for evaluating staffing levels; its
13 definition of utility functions and sub-functions is also widely used in merger analysis and
14 testimony.
15
16 Q. Please describe Mercer's experience in working with NEES.
17 A. Mercer Management Consulting has worked extensively with NEES since 1992. Our
18 work with the Company has included the following types of assignments:
19 o Organizational transformation
20 o Process improvement
21 o Business strategy
Hoffman/Levin
-4-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 5 of 29
1 o Mergers and acquisitions analysis
2
3 These assignments have encompassed all operating, customer-related, and A&G
4 functions in the operating companies and the service company.
5
6 Mercer's extensive knowledge of NEES management and operations was extremely
7 helpful in discussing integration strategies, identifying cost savings opportunities and
8 ultimately, in developing sound estimates of savings and cost to achieve for the
9 proposed NEES-EUA merger.
10
11 Q. Please describe some of these assignments.
12 A. In 1992 and 1993, Mercer assisted NEES in a major organizational transformation,
13 which included the creation of business units, the alignment and clarification of roles
14 and responsibilities, and a significant streamlining of organizational structure and
15 staffing. In 1993 and 1994, we assisted NEES in developing a customer call center
16 strategy which led to the successful consolidation of Massachusetts Electric's six
17 individual call centers into a single center (the Northboro Customer Service Center).
18 During the 1996-1998 period, Mercer helped NEES in the transition from a
19 fully-integrated utility into a "wires" utility; this particular effort included identifying
20 corporate support services required after the divestiture of generation assets.
Hoffman/Levin
-5-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 6 of 29
1
2 Q. In addition to this testimony, has Mercer been retained to assist in other aspects
3 of the proposed NEES-EUA merger?
4 A. Yes. Mercer has been retained to assist in the post-merger integration process.
5
6 II. Summary of Testimony
7 Q. What is the purpose of your testimony?
8 A. We have been asked to describe the analysis conducted to estimate the potential cost
9 savings associated with a merger of the New England Electric System ("NEES") and
10 Eastern Utilities Associates ("EUA"). Mercer Management Consulting (Mercer)
11 assisted NEES and EUA (also referred to as the "Companies") in 1) identifying areas
12 with potential cost saving or cost to achieve, 2) collecting relevant data, 3) developing
13 related operating and financial assumptions, and 4) estimating potential savings and
14 costs.
15
16 This testimony presents the results of the analysis, including:
17 o A summary of results (this section)
18 o A detailed estimate of savings (Section III)
19 o A detailed estimate of cost to achieve (Section IV)
20
Hoffman/Levin
-6-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 7 of 29
1 Exhibit DJH-1 provides a summary of potential merger cost savings for the first 10
2 years (2000-2009) and the cost to achieve. Exhibit DJH-2 contains the
3 non-confidential working papers that support the estimates. Exhibit DJH-3 contains our
4 confidential working papers.
5
6 Q. Please summarize your testimony.
7 A. The planned merger will result in savings that would not otherwise be achieved by
8 the stand-alone operations of NEES (through its Massachusetts Electric, Narragansett
9 Electric, Granite State Electric, Nantucket Electric, and New England Power Service
10 Company subsidiaries) and EUA (through its Eastern Edison, Blackstone Valley
11 Electric, Newport Electric and EUA Service Corporation subsidiaries). Based on
12 information provided by NEES and EUA and the analysis conducted by NEES
13 management and Mercer, merger-related savings were estimated at approximately
14 $31.1 million in 2005, as shown below:
15 Estimated Savings in 2005
16 Savings Component ($ Millions)
----------------- ------------
17 Personnel Savings $21.5
18 Information Systems Savings 0.1
19 Supply Chain Savings 0.6
20 Facilities Savings 4.7
21 Administrative and General Savings 4.2
---
22 Total Savings 31.1
23
Hoffman/Levin
-7-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 8 of 29
1 The figures above include merger-related savings related only to the regulated "wires"
2 and A&G-related operations of NEES and EUA. No revenue enhancements were
3 identified for the regulated business.
4
5 Only cost savings that would result from the merger were included in estimated
6 savings. These types of savings are derived from the elimination of duplication, cost
7 avoidance, adoption of different management practices and policies, and the improved
8 utilization of assets and employees. Savings which could be achieved without a
9 merger (e.g., position reductions resulting from a process improvement in one
10 company) were not included in the estimated savings.
11
12 Q. When will the savings commence?
13 A. Savings will begin in 2000 and continue permanently. Exhibit DJH-1 presents savings
14 for only the first 10 years (2000-2009). The cost to achieve the merger savings will
15 occur primarily in the 1999-2002 period.
16
17 Q. Could the cost savings discussed above and in detail in Section III be achieved
18 without a merger?
19 A. No. The savings are based upon the elimination of redundancies (in personnel,
20 facilities and other areas) and the gaining of economies brought about by a merger. In
Hoffman/Levin
-8-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 9 of 29
1 addition, the savings would not result without incurring the cost to achieve discussed
2 above and in detail in Section IV.
3
4 Q. Please describe the process utilized to estimate merger cost savings and cost to
5 achieve.
6 A. Mercer worked with senior and middle managers at both NEES and EUA to gather
7 the information required to estimate savings and costs. We also met with EUA
8 managers to develop a fuller understanding of the company's business practices,
9 operations, and costs. As discussed earlier, we already had an extensive
10 understanding of NEES business practices, operations, and costs.
11
12 We also worked with NEES management to determine how the merged companies
13 would operate in the future, e.g., the expected level of integration in the A&G,
14 customer-related, and T&D functions.
15
16 Based on information collected and assumptions about how the merged companies
17 would operate, estimates of merger savings and costs were developed, discussed, and
18 refined. The process used to develop the estimated savings and cost to achieve was
19 reasonable, and captured the significant sources of savings available and costs that
20 would be incurred in a merger.
21
Hoffman/Levin
-9-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 10 of 29
1 Q. What assumptions were made in the analysis?
2 A. The following assumptions were made in estimating cost savings:
3 o The combined companies will begin integrated operations on January 1, 2000
4 o The "wires" business will be run with one principal operating company in each
5 state (Massachusetts, Rhode Island, and New Hampshire) and one service
6 company
7 o A high-degree of integration will occur, e.g.:
8 - Financial, accounting, human resources, legal, external affairs, and corporate
9 planning functions will be fully integrated
10 - IS data centers will be consolidated
11 - Call centers will be consolidated
12 - Central T&D planning, engineering, and support will be fully integrated, as
13 will transmission field forces
14 o Annual savings will escalate at a rate of 2.2 percent
15
16 Q. How were capital-related savings calculated?
17 A. Capital-related savings were calculated using a revenue requirement methodology.
18 Under this methodology, for example, a capital deferral or avoidance of $1 million in
19 2000 would not result in a merger savings of $1 million in that year; rather annual
20 savings relating to the fixed charges (cost of capital, depreciation, insurance, and
21 taxes on the $1 million deferral or avoided) are calculated. The revenue requirements
22 methodology reflects the timing of merger savings and how capital or
23 construction-related costs are treated for ratemaking purposes.
Hoffman/Levin
-10-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 11 of 29
1 Fixed charge rates for NEES and EUA were estimated and then blended, based on the
2 relative size of the companies. A levelized fixed charge rate of 13.5 percent was used
3 for capital items other than IS-related. A levelized fixed charge rate of 28.6 percent
4 was used for IS-related items; the higher rate is due to a more rapid (five-year)
5 depreciation period.
6
7 Q. Is the level of estimated cost savings achievable?
8 A. We believe that the level of savings identified in our study has a high likelihood of
9 achievement. Beyond that level, we are aware that Mr. Jesanis is testifying that he
10 expects the savings to be achieved from the acquisition of EUA will be $35 million
11 per year or more in 2005. We believe that this higher level of savings is likely to be
12 achieved for the following reasons:
13 o NEES management approach: During our previous assignments with NEES, the
14 Company has been very creative and aggressive in identifying opportunities to
15 reduce costs; the early creation of a transition team to facilitate the merger
16 illustrates NEES's aggressive approach to opportunities.
17 o NEES "track record": NEES has successfully addressed many of the same
18 issues that arise in a merger, e.g., designing a streamlined organization,
19 integrating multiple call centers, and optimizing field forces and work out
20 locations.
21 o National Grid-related synergies: Additional synergies are expected to result
22 from the National Grid-NEES merger, e.g., taking advantage of National Grid
23 best practices and financing capabilities.
24
Hoffman/Levin
-11-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 12 of 29
1 o Additional sources of savings: Opportunities may arise which have not been
2 captured in our estimates. These include 1) outsourcing functions (given the
3 greater volume of work for the merged companies); 2) taking advantage of new
4 technologies (given the merged companies greater scale); and 3) achieving
5 longer-term IS savings by avoiding duplicative efforts.
6
7 As such, we agree with Mr. Jesanis that actual savings are likely to exceed our
8 estimated savings.
9
10 III. Detailed Estimate of Cost Savings
11
12 A. Summary of Personnel and Non-Personnel Savings
13 Q. You have estimated merger cost savings of $31.1 million in 2005. Would you
14 define the principal components of cost savings and the estimated savings in each
15 component?
16 A. As illustrated in the table on page 7 of this testimony and in Exhibit DJH-2, savings
17 have been classified into five components:
18 o Personnel savings: related to position reductions in A&G, customer,
19 transmission and distribution, and other functions
20 o Information systems savings (non-personnel): related to integration of
21 applications; mainframe, network, midrange/server, and PC/workstation
22 operations; projects; and telecommunications
23 o Supply chain savings (non-personnel): related to reductions in inventory; lower
24 costs for materials, equipment, and contractor services; and reductions in the
25 number of vehicles
Hoffman/Levin
-12-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 13 of 29
1 o Facilities savings (non-personnel): related to the closing of facilities, including
2 office space
3 o Administrative and general savings (non-personnel): related to A&G
4 overheads, advertising, association dues, benefits administration, corporate
5 governance (i.e., shareholder services and board fees), financing costs and fees,
6 insurance, professional services, and regulatory expenses
7
8 The level of estimated savings (in 2005 dollars unless otherwise indicated) and the
9 bases for the estimates are discussed below.
10
11 B. Personnel Savings
12 Q. Please discuss the analysis supporting your personnel savings estimate of $21.5
13 million in 2005.
14 A. Personnel savings were estimated using the following process:
15 o First, staffing levels for NEES and EUA were estimated as of January 1, 2000.
16 Both companies provided detailed organizational and functional breakdowns that
17 assigned each employee to one of the following functions:
18
Hoffman/Levin
-13-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 14 of 29
1 -------------------------------------------------------------------------------------------------------
A&G Functions Customer Functions
o Purchasing and Material Management o Retail Marketing and Sales
(excluding Storeroom Personnel)
o Customer Service
o Human Resources
Electric Transmission and Distribution Functions
o Finance, Accounting, and Planning o Electric Distribution
o Information Services and Telecommunications o Electric System Technical Support
o External Relations o Electric Transmission
o Legal o Transportation, Real Estate, and Facilities
Maintenance
o Administrative and Support Services (excluding
Transportation, Real Estate, and Facilities o Storeroom Personnel
Maintenance)
Other
o Executive Management
o Other Activities
2 -------------------------------------------------------------------------------------------------------
3 Within these functions, employees were also assigned to specific sub-functions.
4 For example, within Customer Service, an employee could be assigned to meter
5 reading, customer inquiry, credit and collections, or another sub-function. The
6 complete list of functions and sub-functions used in this analysis is included in
7 the Exhibit DJH-3 working papers. The use of a common format (Mercer's staffing
8 survey function and sub-function classification) allowed for an "apples-to-apples"
9 staffing analysis.
10 o Second, the number of positions that could be eliminated as a result of the merger
11 was estimated. The magnitude of the reduction in each sub-function was based
12 upon identified duplication or redundant activities; the expected degree of
13 integration; potential changes in policies or practices; and any incremental
14 workloads that would result in that area. The number of position reductions in
15 any one sub-function were not allowed to exceed the smaller of the number of
16 positions of either NEES or EUA on a stand-alone basis. For example, if NEES
17 had 15 positions in a sub-function and EUA had 5 positions, the reduction could
18 not exceed 5 positions.
Hoffman/Levin
-14-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 15 of 29
1 o Third, an average compensation was calculated for each sub-function and then
2 multiplied by the number of positions reduced in that sub-function. The
3 compensation figures used were the average of NEES and EUA compensation
4 levels. Compensation figures included base compensation (wages or salaries) and
5 benefits. Benefits included such items as pension plans, medical insurance, life
6 insurance, savings (401K) plans, bonuses and incentives, and payroll taxes. The
7 average total compensation (salary and benefits) for positions reduced was
8 $84,900 (in 2000 dollars).
9
10 Q. Please describe the results of the personnel analysis.
11 A. NEES was estimated to have 3,240 positions in utility operations and EUA was
12 estimated to have 869 positions as of January 1, 2000. Total position reductions were
13 estimated at 234, or approximately 6 percent of the 4,109 combined positions. These
14 reductions consist of 88 A&G, 62 customer, 78 T&D, and 6 other function positions,
15 as shown below.
Position Reductions
----------------------------------------------------------------------------------------
A&G Customer T&D Other Total
NEES Positions 461 722 2,057 0 3,240
EUA Positions 173 201 488 7 869
--- --- --- - ---
Combined Positions 634 923 2,545 7 4,109
Estimated Reductions (88) (62) (78) (6) (234)
Reduction as a % of 14% 7% 3% 86% 6%
Combined Positions
Reduction as a % of 51% 31% 16% 86% 27%
EUA Positions
16
17 The 234 position reductions also equals 27 percent of EUA's 869 positions. At this
18 point, no decisions have been made as to which reductions will come from current
19 NEES positions or EUA positions.
Hoffman/Levin
-15-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 16 of 29
1
2 As shown above, the percentage reductions in the A&G functions are significantly
3 higher than the percentage reductions in the customer and T&D functions. The
4 relative difference reflects the fact that "headquarter" or "office" type functions
5 offer greater opportunities for savings than do "field" functions, such as line maintenance
6 and construction.
7
8 Q. What was the assumed timing of the estimated reduction in positions?
9 A. In the A&G (except for IS), customer, and T&D functions, 75 percent of reductions
10 were assumed to occur in 2000 with the remaining 25 percent occurring in 2001. In
11 the IS area, reductions were assumed to be 0 percent in 2000, 50 percent in 2001, and
12 the remaining 50 percent in 2002. The slower timing of reductions in IS reflects the
13 complicated work required to integrate the two companies' systems.
14
15 Q. How were capital-related personnel savings calculated?
16 A. The percent of payroll savings allocated to capital was 0 percent for the A&G and
17 customer functions and 35 percent for the T&D functions. These rates were based on
18 payroll allocation figures provided by the companies, weighted by their relative sizes.
19 As discussed earlier, capital-related savings were translated into revenue
20 requirements, based on estimated fixed charge rates.
21
Hoffman/Levin
-16-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 17 of 29
1 C. Information Systems Savings (Non-Personnel)
2 Q. Please describe the information systems functions at NEES and EUA.
3 A. NEES information systems operate on an IBM mainframe computer, an IBM
4 midrange computer, approximately 60 servers, and approximately 2,500 PCs.
5 Corporate, financial and administrative systems utilize Walker software; HR/payroll
6 will utilize PeopleSoft; and the customer information system was developed in-house.
7 The company also has numerous operational systems running on the midrange and
8 mainframe computers. The NEES data center is located in the Westborough
9 headquarters.
10
11 EUA information systems operate on an Amdahl mainframe computer, approximately
12 20 servers, and approximately 600 PCs. EUA operates various financial packages; a
13 CYBORG HR/payroll system; a customer information system developed in-house;
14 and numerous operational systems. The EUA data center is located in the West
15 Bridgewater headquarters.
16
17 Q. Please discuss estimated cost savings in the IS area?
18 A. Merger savings were estimated based on two major assumptions: first, that data
19 centers will be consolidated; second, that the combined companies will migrate to
20 NEES applications including Walker, PeopleSoft, and the NEES customer
21 information system.
Hoffman/Levin
-17-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 18 of 29
1
2 Most of the savings come from a reduction in personnel, which was discussed earlier.
3 Non-personnel savings relating to the consolidation of data centers are largely offset
4 by the cost of adding computing capacity for combined mainframe and midrange
5 computer operations. In 2005, non-personnel IS savings were estimated at
6 approximately $0.1 million.
7
8 D. Supply Chain Savings (Non-Personnel)
9 Q. What are the potential areas of cost savings in the supply chain area?
10 A. Cost savings in supply chain can potentially occur in the following areas:
11 o A reduction in inventory, based on the consolidation of the companies'
12 storerooms and a sharing of spare parts
13 o Lower prices paid for materials, equipment and contractor services, based on
14 greater purchasing leverage and the potential for more standardization and vendor
15 consolidation
16 o A reduction in the number of vehicles, based on a reduction in the number of
17 field and headquarter positions
18
19 Q. Please discuss the estimated level of savings in supply chain?
20 A. Supply chain-related savings in 2005 of $0.6 million were estimated.
21
Hoffman/Levin
-18-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 19 of 29
1 Inventory savings were $0.1 million of the total. Savings were based on a reduction
2 in fixed charges associated with a 25 percent reduction in EUA's current inventory of
3 $3.6 million.
4
5 Procurement savings on materials and equipment were estimated at $0.3 million in
6 2005. These savings were based on an estimated 3 percent reduction in the cost of
7 EUA's annual purchases of approximately $9.4 million. Merger-related savings for
8 contractor services were minimal, since EUA does not have significant contractor
9 services costs (estimated at $2.4 million for vegetation control and $0.2 million for
10 other services in 1998). In addition, the ability to gain purchasing leverage on
11 contractor services is difficult.
12
13 Vehicle-related savings were estimated at $0.2 million in 2005. Vehicle savings will
14 occur as a result of the reductions in the number of positions. An elimination of 5
15 heavy duty vehicles (due to the reduction of 5 T&D crews) and 10 passenger vehicles
16 (due to the reduction of approximately 90 A&G personnel) were estimated. Savings were
17 based on annual operating and fixed costs of $20,000 per heavy duty vehicle
18 and $5,000 per passenger vehicle.
19
Hoffman/Levin
-19-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 20 of 32
1 E. Facilities Savings (Non-Personnel)
2 Q. Does the merger of NEES and EUA create an opportunity to consolidate
3 facilities?
4 A. Yes. As a result of the NEES-EUA merger, only one headquarters building will be
5 required, since A&G functions will be fully integrated. Based on planned T&D
6 operations, the EUA service centers and work out locations will continue to operate in
7 order to meet customer needs. As a result, no other opportunities to reduce facility
8 costs were identified.
9 Q. What are the estimated facilities-related savings?
10 A. The consolidation of headquarters will provide an estimated savings of $4.7 million in
11 2005. The savings reflect reductions in both operating expenses (e.g., maintenance
12 and outside services) and capital-related costs.
13
14 F. Administrative and General Savings (Non-Personnel)
15 Q. What are the potential areas of non-personnel savings related to administrative
16 and general functions?
17 A. We identified the following nine potential areas of cost savings: A&G overheads;
18 advertising; association dues; benefits administration; corporate governance (i.e.,
19 shareholder services and board-related costs); financial fees; insurance; professional
20 services; and regulatory expenses.
21
Hoffman/Levin
-20-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 21 of 29
1 Q. What level of non-personnel A&G savings were estimated in the merger
2 analysis?
3 A. Savings in 2005 of $4.2 million were estimated. Sources of significant savings
4 included the professional services and corporate governance areas. Savings estimates
5 for each area are discussed below.
6
7 Q. Please discuss estimated savings related to A&G overheads in 2005.
8 A. Estimated A&G overhead-related merger savings of $0.8 million were identified.
9 A&G overheads include expenses for office supplies, publications, personal
10 computers, and other miscellaneous expenses. These types of expenses are often
11 captured in FERC Account 921.
12
13 Using NEES and EUA FERC data and other reports, we estimated overheads at
14 $3,000 per employee (in 2000 dollars). This figure was multiplied by the number of
15 position reductions to estimate annual savings.
16
17 Q. Please discuss estimated savings related to advertising.
18 A. Estimated savings in the advertising area were $0.3 million in 2005. Savings will
19 result from an elimination of duplicative costs, e.g., some media purchases. For this
20 transaction, savings were estimated at 50 percent of EUA's annual, normalized
21 advertising expenses.
Hoffman/Levin
-21-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 22 of 29
1
2 Q. Please discuss estimated savings related to association dues.
3 A. Association dues-related savings of $0.1 million in 2005 were identified. Savings
4 were based on lower expenditures for combined membership in the Edison Electric
5 Institute and the termination of membership in other associations.
6
7 Q. Please discuss estimated savings related to benefits administration.
8 A. Estimated merger savings in this area were $0.1 million in 2005. Although total
9 benefit costs for medical, dental, life and other insurance, pensions, and savings
10 plans are significant, the opportunity to reduce costs is very limited. For example, NEES'
11 HMO benefits are self-insured and do not provide an opportunity for savings.
12
13 Q. Please discuss estimated savings related to corporate governance.
14 A. Merger savings related to a reduction in corporate governance costs were estimated
15 at $0.9 million in 2005. Savings related to shareholder services result from the
16 elimination of duplicate activities and costs, such as preparation of the annual
17 shareholders' report and transfer agent fees. Additional savings result from the
18 elimination of director fees and expenses for one company.
19
20 Q. Please discuss estimated savings related to financing costs and fees.
Hoffman/Levin
-22-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 23 of 29
1 A. Merger savings in this area were estimated at $0.3 million in 2005, based on a
2 reduction in line of credit fees for the combined company. The savings related to
3 lines of credit are based on a 100 percent elimination of EUA's stand-alone fees.
4
5 Q. Please discuss estimated savings related to insurance.
6 A. Merger-related insurance savings were estimated at $0.7 million in 2005. Savings
7 were based on expected reductions in property and liability coverage premiums (due
8 to reduction in cost per additional dollar of coverage); reductions in directors and
9 officers insurance premiums (due to the elimination of one board of directors); and
10 reductions in brokerage fees (due to the consolidation of insurance purchasing).
11
12 Q. Please discuss estimated savings related to professional services.
13 A. Merger-related savings for professional services were estimated at $1.0 million in
14 2005. Professional services savings result from the elimination of duplicative efforts
15 in areas such as external auditing, legal support, legislative services, and general
16 consulting. The savings were based on an approximate 40 percent reduction in
17 EUA's stand-alone annual professional services costs.
18
18 Q. Please discuss estimated savings related to regulatory expenses.
Hoffman/Levin
-23-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 24 of 29
1 A. Merger-related savings for regulatory expenses were estimated at $0.1 million in
2 2005. Savings (non-personnel) in this area are relatively small, since annual
3 assessments (the largest component of costs) are not likely to be reduced when the
4 two companies merge. The savings estimate is based on a 20 percent reduction in
5 EUA's annual reporting, filing, and miscellaneous expenses of approximately $0.3
6 million, to reflect the elimination of some duplication and gains from integrating
7 regulatory affairs management.
8
9 G. Comparison with Other Transactions
10 Q. Did you compare the NEES-EUA merger to other transactions?
11 A. Yes. We reviewed a number of transactions, including the BEC Energy-COM/Energy
12 merger.
13
14 The 6 percent reduction in positions for the NEES-EUA merger falls in the 3
15 percent-11 percent range for other transactions that we reviewed. We would not expect the
16 NEES-EUA percentage reductions to be at the high end of the range given the
17 significant difference in staffing levels between NEES and EUA (NEES has 3.7 times
18 the staffing of EUA). In the other transactions, the ratio of employees for the merger
19 partners is typically in the 1 to 2 times range, which creates the potential for higher
20 percentage savings.
Hoffman/Levin
-24-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 25 of 29
1 Q. Why did you conclude that the NEES-EUA merger has a more limited
2 opportunity to reduce costs?
3 A. First, NEES and EUA are relatively "lean" utilities. This limits the ability to reduce
4 staffing (the largest source of savings) in a merger situation.
5
6 For example, NEES and EUA were estimated to have a combined pre-merger staffing
7 of 4,109 or 2.5 employees per thousand customers (based on a total of 1.66 million
8 customers). The comparable figures for BEC Energy and COM/Energy are combined
9 pre-merger staffing of 3,338 or 3.2 employees per thousand customers (based on a
10 total of 1.04 electric customers). Based on estimated position reductions in each
11 transaction, post-merger NEES-EUA will have 2.3 employees per thousand customers
12 compared to 2.9 employees per thousand customers for post-merger BEC
13 Energy-COM/Energy.
14
15 Second, EUA has a relatively small cost base. For example, in 1997, combined T&D,
16 customer (excluding demand-side management) and A&G-related expenses were $77
17 million. COM/Energy's expenses were $116 million for the same electric functions
18 and $147 million if gas-related A&G expenses are included. Again, the lower cost
19 base limits the potential savings.
20
21 Q. Please summarize this section of your testimony.
Hoffman/Levin
-25-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 26 of 29
1 A. Merger cost savings of $31.1 million in 2005 were estimated. Approximately 70
2 percent of savings ($21.5 million) were personnel-related. The savings are based
3 upon an assumed merger of NEES and EUA and would not result otherwise.
4
5 IV. Detailed Estimate of Cost to Achieve
6 Q. What types of costs are incurred when two companies merge?
7 A. Costs fall into the following four categories:
8 o Transaction costs: primarily the fees paid to investment bankers for advice on
9 the merger transaction and to outside legal counsel for advice on the merger
10 transaction and support in regulatory proceedings
11 o Personnel costs: primarily the out-of-pocket costs incurred to achieve the
12 reduction in positions, e.g., early retirement/severance packages; other costs
13 include retention payments to employees deemed necessary for a successful
14 integration, as well as relocation and retraining costs
15 o Transition costs: the costs incurred to integrate the two companies, e.g., support
16 for organizational redesign and process integration; communication costs; and
17 costs related to the closing of facilities
18 o Information systems costs: the costs associated with integrating systems,
19 consolidating data centers, creating a common meter reading standard, and
20 connecting telecommunication networks
21
22 Q. How were these costs estimated for the potential merger of NEES and EUA?
Hoffman/Levin
-26-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 27 of 29
1 A. Banker and legal fees were estimated by NEES and EUA management. Other
2 estimated costs to achieve were based on information provided by NEES and EUA
3 and on discussions with NEES management concerning the degree of integration
4 expected, planned corporate policies, and the resulting integration requirements. This
5 process addressed all significant costs to achieve.
6
7 Q. Please summarize the estimated cost to achieve for the merger.
8 A. The cost to achieve was estimated at $63.6 million - approximately $11.4 million for
9 transaction costs, $40.1 million for personnel costs; $4.6 million for transition costs,
10 and $7.6 million for information systems costs. Details are provided in Exhibits
11 DJH-1 and 2 and below. Approximately 85 percent of the costs will be incurred in the
12 1999-2000 period.
13
14 Q. Please discuss the estimated transaction costs of approximately $11.4 million.
15 A. The primary transaction costs are for merger assistance provided by investment
16 bankers and merger and regulatory assistance from outside counsel. These costs
17 were estimated by NEES and EUA at $7.5 million for banker fees and $3.5 million for legal
18 fees. The other transaction cost included is for director and officer tail liability
19 coverage ($0.4 million).
20
Hoffman/Levin
-27-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 28 of 29
1 Q. Please discuss the estimated personnel costs of approximately $40.1 million.
2 A. The most significant personnel costs incurred in a merger are related to achieving
3 targeted reductions in the workforce.
4
5 Separation and retention costs were estimated at $35.2 million. These costs include
6 payments to employees for early retirement, severance and/or other separation
7 packages; payments to executives other than EUA parent company, generation-related,
8 and unregulated business executives; and retention of key employees.
9
10 Other costs were estimated at $5 million. These costs include estimated relocation
11 and miscellaneous costs ($2.8 million) and estimated retraining and reorientation
12 costs for customer services, T&D, and administrative personnel to learn about future work
13 processes, as well as company policies and practices ($2.2 million).
14
Hoffman/Levin
-28-
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 29 of 29
1 Q. Please discuss the estimated transition costs of $4.6 million.
2 A. Transition costs are costs incurred to integrate the separate operations of the two
3 companies. Estimated costs for the NEES-EUA merger included $2.0 million for
4 outside organizational and change management support; $0.8 million for internal
5 process integration teams; $0.5 million for communications about the merger and
6 integration process to employees and external parties, e.g., shareholders, regulatory
7 commissions, vendors, and the investment community; $1.0 million for the closing of
8 some facilities and for the reconfiguration of other facilities; and $0.3 million for
9 changes to corporate signage and stationary.
10
11 Q. Please discuss the estimated information systems costs of $7.6 million.
12 A. The most significant IS cost was an estimated $6.6 million for applications
13 integration, data conversion, and the consolidation of data centers. Other costs
14 included $0.6 million to outfit EUA meter readers with NEES-standard meter reading
15 devices; and $0.4 million to link the two telecommunications networks and to
16 reconfigure/reprogram customer service center switches.
17
18 Q. Does this conclude your testimony?
19 A. Yes, it does.
Hoffman/Levin
-29-
</TABLE>
New England Electric System
Eastern Utilities Associates
M.D.T.E. Docket No. 99-_____
EXHIBITS
OF
DAVID J. HOFFMAN & RICHARD J. LEVIN
Exhibit DJH-1 Summary of Savings and Cost to Achieve
Exhibit DJH-2 Supporting Working Papers
Exhibit DJH-3 Supporting Working Papers (Confidential)
<PAGE>
Narragansett Electric
BVE/Newport Electric
M.D.T.E. Docket No. 99- _____
Exhibit DJH-1
Exhibit DJH-1
Summary of Savings and
Cost to Achieve
<PAGE>
<TABLE>
<CAPTION>
Exhibit DJH-1
Savings Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Personnel 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728
Non-Personnel
Information Systems 17 34 52 53 55 56 57 58 60 61 502
Supply Chain 247 513 539 566 594 622 651 680 710 741 5,862
Facilities - 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
Administrative and General 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
-------------------------------------------------------------------------------------------------------
Total Savings 16,137 26,442 28,224 29,149 30,095 31,061 32,049 33,059 34,090 35,145 295,452
Cost to Achieve 54,060 8,350 1,200 - - - - - - - 63,610
-------------------------------------------------------------------------------------------------------
Net Savings (37,923) 18,092 27,024 29,149 30,095 31,061 32,049 33,059 34,090 35,145 231,842
Confidential
Page 1 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Personnel Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
A&G Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized--- IS 0% 50% 100% 100% 100% 100% 100% 100% 100% 100%
% Realized---Other 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
----------
Ongong savings - IS 1,528 18
Ongoing savings - Other 6,680 70
Total Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
O&M Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
1 Capital Savings - - - - - - - - - -
2 - - - - - - - - -
3 - - - - - - - -
4 - - - - - - -
5 - - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
--------------------------------------------------------------------------------------------------------
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
Confidential
Page 2 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
Customer Related Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
Ongoing savings 4,930 62
Total Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
O&M Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
1 Capital Savings - - - - - - - - - -
2 - - - - - - - - -
3 - - - - - - - -
4 - - - - - - -
5 - - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
Total O&M + Rev Req Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
Confidential
Page 3 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
T&D Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 35%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
Ongoing savings 6,088 78
Total Savings 4,566 6,222 6,359 6,499 6,642 6,788 6,938 7,090 7,246 7,406 65,757
O&M Savings 2,968 4,045 4,133 4,224 4,317 4,412 4,509 4,609 4,710 4,814 42,742
1 Capital Savings 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598
2 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178
3 2,226 2,226 2,226 2,226 2,226 2,226 2,226 2,226
4 2,275 2,275 2,275 2,275 2,275 2,275 2,275
5 2,325 2,325 2,325 2,325 2,325 2,325
6 2,376 2,376 2,376 2,376 2,376
7 2,428 2,428 2,428 2,428
8 2,482 2,482 2,482
9 2,536 2,536
10 2,592
--------------------------------------------------------------------------------------------------------
Total Capital Savings 1,598 3,776 6,002 8,276 10,601 12,977 15,405 17,887 20,423 23,015 119,961
Rev Req Savings 216 510 810 1,117 1,431.16 1,752 2,080 2,415 2,757 3,107 16,195
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937
Confidential
Page 4 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
Other Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
Ongoing savings 632 6
Total Savings 474 646 661 675 690 705 721 737 753 769 6,831
O&M Savings 474 646 661 675 690 705 721 737 753 769 6,831
1 Capital Savings - - - - - - - - - -
2 - - - - - - - - -
3 - - - - - - - -
4 - - - - - - -
5 - - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
--------------------------------------------------------------------------------------------------------
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 474 646 661 675 690 705 721 737 753 769 6,831
Total Personnel Savings
A&G 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
Customer-Related 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
T&D 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937
Other 474 646 661 675 690 705 721 737 753 769 6,831
--------------------------------------------------------------------------------------------------------
Total 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728
Confidential
Page 5 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
IS Savings Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Rev Req Rate 28.6%
Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 33% 67% 100% 100% 100% 100% 100% 100% 100% 100%
O&M Savings
A&G Applications - - - - - - - - - - -
T&D Applications - - - - - - - - - - -
Customer Applications - - - - - - - - - - -
Mainframe and Network 17 34 52 53 55 56 57 58 60 61 502
Midrange/Servers - - - - - - - - - - -
PC/Workstations - - - - - - - - - - -
Projects - - - - - - - - - - -
Telecommunications - - - - - - - - - - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total O&M Savings 17 34 52 53 55 56 57 58 60 61 502
Capital Savings
A&G Applications
T&D Applications
Customer Applications
Mainframe and Network
Midrange/Servers
PC/Workstations
Projects (PeopleSoft) - -
Telecommunications
Total Capital Savings - - - - - - - - - - -
1 Capital Savings - - - - -
2 - - - - -
3 - - - - -
4 - - - - -
5 - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
--------------------------------------------------------------------------------------------------------
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 17 34 52 53 55 56 57 58 60 61 502
Confidential
Page 6 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Supply Chain Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Inventory
% Capitalized 100%
Carrying Cost 13.7%
Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Inventory Reduction 899
Annual Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485
O&M Savings 0 0 0 0 0 0 0 0 0 0 0
Capital Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485
Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299
-----------------------------------------------------------------------------------------------
O&M +Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299
Confidential
Page 7 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Procurement
% Capitalized 35%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing savings 290
Total Savings 145 296 303 310 316 323 330 338 345 353 3,060
O&M Savings 94 193 197 201 206 210 215 220 224 229 1,989
1 Capital Savings 51 51 51 51 51 51 51 51 51 51
2 104 104 104 104 104 104 104 104 104
3 106 106 106 106 106 106 106 106
4 108 108 108 108 108 108 108
5 111 111 111 111 111 111
6 113 113 113 113 113
7 116 116 116 116
8 118 118 118
9 121 121
10 123
-----------------------------------------------------------------------------------------------
Total Capital Savings 51 154 260 369 480 593 708 827 947 1,071 5,460
Rev Req Savings 7 21 35 50 65 80 96 112 128 145 737
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 101 214 232 251 270 290 310 331 352 374 2,726
Confidential
Page 8 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Contractor Services
% Capitalized 35%
Rev Req Rate 13.5%
Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing savings 27
Total Savings 14 28 28 29 29 30 31 31 32 33 285
O&M Savings 9 18 18 19 19 20 20 20 21 21 185
1 Capital Savings 5 5 5 5 5 5 5 5 5 5
10 10 10 10 10 10 10 10 10
10 10 10 10 10 10 10 10
10 10 10 10 10 10 10
10 10 10 10 10 10
11 11 11 11 11
11 11 11 11
11 11 11
11 11
11 11
Total Capital Savings 5 14 24 34 45 55 66 77 88 100 508
Rev Req Savings 1 2 3 5 6 7 9 10 12 13 69
Total O&M + Rev Req Savings 9 20 22 23 25 27 29 31 33 35 254
Confidential
Page 9 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Vehicles
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing savings 150
Total Savings 75 153 157 160 164 167 171 175 179 182 1,583
O&M Savings 75 153 157 160 164 167 171 175 179 182 1,583
1 Capital Savings 0 0 0 0 0 0 0 0 0 0
2 0 0 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0
5 0 0 0 0 0 0
6 0 0 0 0 0
7 0 0 0 0
8 0 0 0
9 0 0
10 0
-----------------------------------------------------------------------------------------------
Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0
Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 75 153 157 160 164 167 171 175 179 182 1,583
Total SCM Savings
Inventory 62 126 129 131 134 137 140 143 147 150 1,299
Procurement 101 214 232 251 270 290 310 331 352 374 2,726
Contractor Services 9 20 22 23 25 27 29 31 33 35 254
Vehicles 75 153 157 160 164 167 171 175 179 182 1,583
-----------------------------------------------------------------------------------------------
Total 247 513 539 566 594 622 651 680 710 741 5,862
Confidential
Page 10 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Facilities Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
Phase-in 0% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing Savings 4,179
Total Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
O&M Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
1 Capital Savings 0 0 0 0 0 0 0 0 0 0
2 0 0 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0
5 0 0 0 0 0 0
6 0 0 0 0 0
7 0 0 0 0
8 0 0 0
9 0 0
10 0
-----------------------------------------------------------------------------------------------
Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0
Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
Confidential
Page 11 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Non-Labor A&G Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
A&G Overheads 486 690 733 749 766 783 800 818 835 854 7,514
Advertising 273 279 285 291 298 304 311 318 325 332 3,017
Association Dues 82 84 86 88 89 91 93 95 98 100 906
Benefits Administration 0 0 52 53 55 56 57 58 60 61 451
Corporate Governance 787 804 822 840 859 877 897 916 937 957 8,697
Financing Costs and Fees 272 278 284 290 297 303 310 317 324 331 3,006
Insurance 646 660 675 690 705 720 736 752 769 786 7,139
Professional Services 905 925 945 966 987 1,009 1,031 1,054 1,077 1,101 10,001
Regulatory Expenses 57 58 60 61 62 64 65 66 68 69 630
Total Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
O&M Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
1 Capital Savings 0 0 0 0 0 0 0 0 0 0
2 0 0 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0
5 0 0 0 0 0 0
6 0 0 0 0 0
7 0 0 0 0
8 0 0 0
9 0 0
10 0
-----------------------------------------------------------------------------------------------
Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0
Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
Confidential
Page 12 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Cost to Achieve Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Transaction Costs
Bankers fees 7,500 7,500
Legal fees 3,500 3,500
D&O liability tail coverage 400 400
Total Transaction Costs 11,400 - - 11,400
Personnel Costs
Separation / Retention 25,850 8,100 1,200 35,150
Relocation, Retraining,
Reorientation and Miscellaneous 4,950 4,950
Total Personnel Costs 30,800 8,100 1,200 40,100
Transition Costs
Internal/Outside Support 2,810 2,810
Communications 500 500
Facilities Consolidation 750 250 1,000
Other 250 250
Total Transition Costs 4,310 250 - 4,560
Information Systems
Systems Integration and Data
Center Consolidation 6,600 6,600
Meter Reading Hardware 600 600
Telecommunications Costs 350 350
Total Information Systems Costs 7,550 7,550
Total Cost to Achieve 54,060 8,350 1,200 63,610
Confidential
Page 13 of 13
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
M.D.T.E. Docket No. 99-_____
Exhibit DJH-2
Exhibit DJH-2
Supporting Working Papers
(Non-Confidential)
<PAGE>
Exhibit DJH-2
Information Systems
Savings
<PAGE>
<TABLE>
<CAPTION>
Software comparisons Confidential
- ----------------------------------------------------------------------------------------------------------------------
Application NEES EUA Comments
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Corporate, Financial, and o Walker o Various financial packages
Administrative Systems
- Significant programming/ - IVIS (AP, 1993, Y2K
customization has upgrade scheduled
improved speed 1Q99)
- Works well for NEES' - GEAC (Fixed assets, 1988)
business model
(intracompany billing,
etc.)
- Limited decision support - In-house S/W (Purchasing/
capabilities Materials Mgmt, 1992)
- Expandable for similar - Lawson (General Ledger, 12/98)
business model
o Focus for 1999 on Y2K upgrades
- -----------------------------------------------------------------------------------------------------------------------
HR/Payroll o PeopleSoft o CYBORG
- Installation complete in - Y2K upgrade in 1999
early 1999
- Expandable, but license
may be restrictive
- -----------------------------------------------------------------------------------------------------------------------
2
<PAGE>
Software comparisons Confidential
- -----------------------------------------------------------------------------------------------------------------------
Application NEES EUA Comments
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Customer System o CIS - developed in-house o CIS - developed in-house
- GUI front-end placed - GUI front-end placed
on mainframe system on mainframe system
- Expandable, but only - Major upgrade 1997
for one dimensional
(e.g., electric only) - Integrated with Radix
customers hand-held meter
reading devices
- -----------------------------------------------------------------------------------------------------------------------
Operational Systems o Numerous o Numerous
- Many systems running - Many systems running
on midrange and on mainframe
mainframe
- Intergraph digital
- Major GIS system topology mapping
implementation half system
complete
- Map-based trouble
reporting system
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
3
<PAGE>
<TABLE>
<CAPTION>
Hardware comparisons Confidential
- -----------------------------------------------------------------------------------------------------------------------
Device NEES EUA
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Mainframes o IBM 390 SP; CMOS 4 engines 220 o Amdahl 45 MIPS
MIPS
- Expandable up to 540-600 MIPS
- -----------------------------------------------------------------------------------------------------------------------
Midrange o IBM RS6000
- Runs decision support, PeopleSoft
and retail applications
- -----------------------------------------------------------------------------------------------------------------------
Servers o DEC alpha and IBM AIX o Sun (Unix)
o Few Digital VAXes left
- ~60 o Compaq, Gateway
o Migrating to NT
o Approximately 20 servers total
- -----------------------------------------------------------------------------------------------------------------------
PCs o 2500 Pentium PCs o 600 Pentium PCs (Gateway, Compaq)
o Additional 400 devices o 150 "Dumb" terminals
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
4
<PAGE>
<TABLE>
<CAPTION>
System environment comparisons Confidential
- -----------------------------------------------------------------------------------------------------------------------
Device NEES EUA
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Mainframes o VMS, IMS, CICS, DB2 o VMS, CICS, Sybase
- -----------------------------------------------------------------------------------------------------------------------
Servers o Unix (primary), NT (becoming o Unix, NT (becoming standard
standard)
- -----------------------------------------------------------------------------------------------------------------------
Networks o Novell 4.11 o Eliminate TAO e-mail and standardize
on MS-Outlook (MS-Exchange-based)
- Considering 5.0
o Ethernet 100%
- -----------------------------------------------------------------------------------------------------------------------
PCs o Windows 3.1, 95, NT o MS Office
- Standard is 95 for A&G positions
- Standard is NT for operations
positions
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
5
<PAGE>
<TABLE>
<CAPTION>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Savings opportunities
- -----------------------------------------------------------------------------------------------------------------------------------
Area Opportunity Savings Assumptions Savings
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Applications o Corporate, financial, administrative
systems:
- Integrate EUA data into Walker - No incremental license fees for
-> NEES
- Discontinue EUA's financial - Reduce 1/3 of EUA's financial - 3 positions
systems applications support positions
- Move data onto NEES' - Reduce 100% of EUA's HR and - 1 position
PeopleSoft system payroll applications support
- Discontinue EUA's CYBORG -> positions
HR and payroll system
----------------------------------------------------------------------------------------------------------
o Customer and related systems:
- Integrate EUA call center - Reduce 1/3 of EUA's call center - 3 positions
applications into NEES' system -> applications support positions
- Discontinue EUA's CIS systems
----------------------------------------------------------------------------------------------------------
o T&D systems:
- Migrate EUA's work -> - Reduce 1/3 of EUA's T&D - 3 positions
management system to NEES' applications support positions
WIN system
- Migrate topological info from
EUA's Intergraph into NEGIS
and re-digitize if appropriate
- Discontinue EUA's T&D
systems
- -----------------------------------------------------------------------------------------------------------------------------------
6
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Savings opportunities
- -----------------------------------------------------------------------------------------------------------------------------------
Area Opportunity Savings Assumptions Savings
- -----------------------------------------------------------------------------------------------------------------------------------
Hardware/System o Data center/mainframe:
Software - Close EUA's data center -> - Reduce EUA's data center and - 5 positions
tech support positions by 50%
- Reduce EUA's associated $2M - $1M
non-labor IS cost for mainframe
maintenance, S/W licenses, and
disaster recovery by $1M;
remaining $1M to focus on
software licenses and support
----------------------------------------------------------------------------------------------------------
o Midrange system:
- - -
- -
----------------------------------------------------------------------------------------------------------
o Servers/network:
- - -
----------------------------------------------------------------------------------------------------------
o PCs/workstations:
- Reduce end-user/help desk -> - Reduce EUA's help desk/end - 1 position
support staff user support by 20%
- -----------------------------------------------------------------------------------------------------------------------------------
7
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Savings opportunities
- -----------------------------------------------------------------------------------------------------------------------------------
Area Opportunity Savings Assumptions Savings
- -----------------------------------------------------------------------------------------------------------------------------------
Telecommunications o Integrates NEES's and EUA's -> - Reduce 15% of EUA's network - 1 position
telecommunications networks support positions
- -----------------------------------------------------------------------------------------------------------------------------------
Facilities o Cost savings captured in the -> - Cost savings captured in
closing of West Bridgewater; IS Facilities section
is a portion
o Integrate EUA's bill printing, -> - Cost avoidance of outsourcing - $250K
stuffing, and mailing operations bill printing, stuffing, and
into NEES' operations mailing (one additional resource
required is already reflected in
office services)
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
8
<PAGE>
<TABLE>
<CAPTION>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Cost to achieve
- -----------------------------------------------------------------------------------------------------------------------------------
Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Applications o Corporate, financial,
administrative systems:
- System "combination" costs -> - Cost for application and - $2.1 M1
data conversion
---------------------------------------------------------------------------------------------------------------
o Customer and related systems:
- System "combination" costs -> - Cost for application and - $2.1M1
data conversion
- Outfit meter readers with -> - 55 devices @$10,000 each - $0.6M
ITRON devices (including device,
training, programming,
transfer of routing info)
---------------------------------------------------------------------------------------------------------------
o T&D systems:
- System "combination" costs -> - Cost for application and - $2.1M1
data conversion
- -----------------------------------------------------------------------------------------------------------------------------------
- ---------------
1 Prorated from base of $6.3M.
9
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Cost to achieve
- -----------------------------------------------------------------------------------------------------------------------------------
Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost
- -----------------------------------------------------------------------------------------------------------------------------------
Hardware/System o Data center/mainframe:
Software - Discontinuation of EUA -> - Closing cost -$0.3M
data center
- Increase NEES' processing -> - Turn up 2 additional - - $1.0M
power CMOS enginees (cost of
H/W & S/W)
---------------------------------------------------------------------------------------------------------------
o Midrange system:
- Transfer midrange -> - Turn up 2 additional - - $0.2M
application to NEES nodes of IBM RS6000
midrange system
---------------------------------------------------------------------------------------------------------------
o Servers/networks:
- Network reconfiguration -> - - -
---------------------------------------------------------------------------------------------------------------
o PCs/workstations:
- No costs incurred -> - Freed-up PCs available to - -
replace dumb terminals
- -----------------------------------------------------------------------------------------------------------------------------------
10
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Cost to achieve
- -----------------------------------------------------------------------------------------------------------------------------------
Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost
- -----------------------------------------------------------------------------------------------------------------------------------
Telecommunications o Costs to integrate both companies' - $100K
networks
o Customer service center switch: - Switch capacity sufficient - $250K
Cost to reconfigure EUA's tie-lines to handle EUA's
and reprogram switch additional inbound calls
- -----------------------------------------------------------------------------------------------------------------------------------
Facilities o Costs are captured in the closing of
West Bridgewater facility
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
11
<PAGE>
Purchases
35
1
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
35 Annual materials and equipment purchases by commodity class
a) T&D related
b) Corporate and other
See attached.
<PAGE>
ADDRL
#35
35
2
N35 Annual materials and equipment purchases by commodity class, T&D
Issues from M&S Total T&D Corp. &
Stock, Cap,&Exp. Purchases Other
Blackstone Valley 990,780 442,254 1,433,034 195,459
Eastern Edison 2,404,158 840,142 3,244,300 377,438
Newport Electric 604,470 187,815 792,285 101,099
--------------------------------------------------
3,999,408 1,470,211 5,469,619 673,996
========= =======
Meters 998,000
Transformers 2,249,000
Inputs
<PAGE>
<TABLE>
<CAPTION>
EUA DISTRIBUTION COMPANIES & MONTAUP TRANSMISSION
1999 Capital Budget BVE EECo NECo VEC
Blankets:
Priority Priority Req 1999 1999 Cumm Distrib Transm
No Code No Title Expenditures Expenditures OH Lines UG Substation OH Lines
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1 1-99 New Business $4,484.0 $ 4,484.0 30,400 11,500 0 0
2 2-99 Routine Distribution Imps/Rets 2,445.0 6,929.0 20,900 2,060 0 0
3 3-99 Meter Devices & Installations 998.0 7,927.0 0 0 0 0
4 4-99 Line Transf Capacitors & Regs 2,249.0 10,176.0 0 0 0 0
5 5-99 Distribution Substations 235.0 10,411.0 67 0 1,634 0
6 6-99 Street & Area Lighting 786.9 11,197.9 5,960 1,090 0 0
7 7-99 Building Imps/Rets 108.1 11,306.0 0 0 0 0
8 8-99 Transmission Lines & Subs 388.0 11,694.0 400 0 0 45000
9 9-99 Damages and/or Failures 534.0 12,228.0 4,750 2,192 0 0
10 10-99 Furniture, Tools, Lab & Comm 263.9 12,491.9 0 0 0 0
Equip
11 12-99 Land & Land Rights 90.0 12,581.9 0 0 0 0
12 13-99 Misc. Production Imps/Rets 0.0 12,581.9 0 0 0 0
Blanket Subtotal $12,581.9 62,477 16,842 1,634 4,500
Specifics: General Projects
1 HP.B Fire Alarm Replacement $35.0 $35.0 0 0 0 0
2 HP.O BVE Operations Roof 120.0 155.0 0 0 0 0
Replacement
Specifics: Substation
Projects
1 HP.D Dupont Sub Capacitor Bank $102.0 $102.0 0 120 269 0
Addition
2 MP.C 690 Swansea DFP Upgrades 76.9 178.9 0 0 696 0
3 MP.C Scituate Substation Relay 44.0 222.9 0 0 192 0
Upgrades
4 MP.C Riverside Substation Rebuild 1,108.0 1,330.9 0 576 4,416 0
5 MP.C Mill St. Substation Relay 61.0 1,391.9 0 0 288 0
Upgrades
6 MP.C Jepson Sub Ground Gnd 143.0 1,534.9 0 0 864 0
Replacement
7 MP.C 199 Jepson Sub Bus Thermal 65.5 1,600.4 0 0 290 0
Upgrade
8 MP.C Install 2nd Transformer at 222.0 1,822.4 0 0 1,728 0
Eldred
9 MP.C 198 Gate II Overcurrent Relay 78.0 1,900.4 0 0 851 0
Upgrade
10 LP.A Repl Jepson Sub Breaker 3729 55.0 1,955.4 0 0 346 0
11 LP.B Repl Gate II Transformer 33.0 1,988.4 0 0 288 0
Bushings
Substation Subtotal $1,988.4 0 696 10,228 0
Specifics: Transmission Projects
1 HP. EMI/Tiverton Power Plant $1,070.0 $1,070.0 0 0 0 6,400
2 HP. EMI/Tiverton Power Plant 260.0 1,330.0 0 0 1800 0
3 HP. 839 EMI/Tiverton Power Plant 1,950.0 3,305.0 0 0
<PAGE>
4 HP. 837 EMI/Dignton Interconnection 220.0 3,525.0 0 0
5 HP. ANP Power Plant 1,135.0 4,660.0 0 0 3,200 440
6 HP.D 238 Sherman Rd Sub Foundations 40.0 4,700.0 0 0 2 0
7 HP.D Belmont Replace Switch S1-1 29.0 4,729.0 0 0 0 307
8 MP.C Washington Substation Doub 2,100.0 6,829.0 0 180 3,643 4,151
End
Transmission Subtotal $6,829.0 0 180 8,893 18,998
Specifics: Distribution
Projects
1 HP.A Gate II Feeder Addition $86.0 $86.0 220 170 220 0
2 HP.C 692 Marvel St. Swansea Road Imps 18.9 104.9 75 0 0
0
3 HP.C 283 Main St. Easton - Road 74.8 179.7 302 128 0 0
Widening
4 HP.C 691 Bank St. Swansea Road Imps. 86.1 265.8 180 0 0 0
Phase II
5 HP.C 1999 Street Light Conversion 385.0 650.8 1,200 800 0 0
Program
6 HP.C 1999 St. Light Conversion, 57.0 707.8 300 0 0 0
Portsmouth
7 HP.D Washington Substation Feeder 220.0 927.8 550 150 0 0
Addition
8 HP.D 196 Reliability Imps. Back yard 22.0 949.8 100 0 0 0
Construction
9 HP.D 293 North Main St. Rebuild 42.5 992.3 0 0 0 0
10 HP.D R270 Main St. Rebuild, Brockton 46.8 1,039.1 0 0 0 0
11 HP.D 197 Conversion - Senes St. Light 60.0 1,099.1 250 420 0 0
Circuits
12 HP.D Condenmed Pole Replacement 580.0 1,679.1 7,600 0 0 0
- 1999
13 HP.D Condemned Pole Replacement 220.0 1,899.1 2,850 0 0 0
- 1999
14 MP.C 278 Storm Proofing 618.4 7,447.4 5,719 0 0 0
15 MP.C Modern Furniture Vault 147.0 7,594.4 0 1,200 0 0
16 MP.C Distribution Automation 325.0 7,919.4 700 0 640 0
17 MP.C Distribution Automation 650.0 8,569.4 1,400 0 1,280 0
18 MP.C 269 Condemned Poles Easton 166.1 8,735.5 1,789 0 0 0
19 MP.C R274 Belmont St Rebuild, Brockton 199.1 8,934.6 558 200 0 0
20 MP.C 261 #6 CU Replacement-Scituate 232.0 9,166.6 2,167 0 0 0
21 MP.C 262 #6 CU Replacement-Brockton 432.0 9,598.6 3,728 0 0 0
22 LP.A 181 Install Neutral Wire, 51.0 9,649.6 450 0 0 0
Portsmouth
23 LP.A 679 Cable Removal-Fall River 46.0 9,695.6 0 4,380 0 0
24 LP.A 675 23kV Cable Removal-Fall 32.3 9,727.9 0 4,000 0 0
River
25 LP.B 178 Remove 23kV Cable 13.5 9,741.4 0 270 0 0
Distribution Subtotal $4,811.5 30,138 11,718 2,140 0
Total dollars/Manhours $26,365.8 92,615 29,436 22,895 23,498
Budgeted
Total Available Manhours 78,235 19,673 21,206 4,121
Surplus/Deficit Manhours (14,380) (9,763) (1,689) 19,377
<PAGE>
EUASC MH Requirements 0 0 0 0
Surplus (Deficit) Manhours (14,380) (9,763) (1,689) 19,377
including EUASC
* Note There is an estimated contribution of $128,000 from EMI on this project
** Note There are 250 Electrical Maintenance manhours associated with this job
*** Note There are 3,500 Electrical Maintenance manhours associated with this job
</TABLE>
<PAGE>
Inventory
55
1
DDRL (12/17/98)
55. Details of how materials are stocked, ordered and distributed including:
- value of T&D inventory
- degree of centralization
- quantities of materials in field locations
- use of vendors to provide materials in emergencies
Value of T&D inventory / Quantities of materials stored in field locations
Inventory Value
6/30/98
Lincoln $906,287
Brockton $941,766
Hanover $244,522
Fall River $725,489
Newport $776,757
--------
System Total $3,594,821
Input
Degree of centralization
This is answered in ADDRL (12/19/98) #39.
Use of vendors to provide materials in emergencies
In addition to maintaining a safety stock, we make an assessment of our critical
material needs prior to a forecasted storm and contact vendors for immediate
re-supply where appropriate. Our vendors have been responsive in the past and we
have not experienced a shortage of critical materials in any storm or other
emergency in at least the last ten years. EUA does not have alliances with any
vendors to maintain inventory on our behalf.
<PAGE>
Inventory 39R
1
ADDRL (12/19/98)
39. High-level overview of central stores, e.g. value of inventory, annual
receipts and issues, square footage, expandability.
EUA operates on a "main stocking" philosophy. A number of stock items are
stocked at one of the retail company stockrooms in quantity sufficient to
provide for the needs of the other retail locations. The daily courier or
scheduled trips by the stockroom stake-body vehicle are used to deliver
this material where needed. We are presently studying a central warehouse
concept.
The year-to-date monthly average inventory value as of 6/30/98 (excluding
Somerset plant) is $3,552,719.
The year-to-date receipts as of 6/30/98 annualized are $4,391,220.
The year-to-date issues as of 6/30/98 annualized are $4,613,724.
The Inventory Turns Ratio as of 6/30/98 is 1.30.
Inventory Turns Ratio is defined as Total Inventory Issues for the last 12
months divided by the 12 month rolling average Inventory level. All items
in inventory are included. This includes safety stock, scrap, emergency
spares and obsolete items. Inventory at Somerset Station excluded.
The Carrying Cost for inventory is approximately 53% as of 10/31/98.
Carrying Cost (or Stores Clearing Rate) is defined as the 12 month rolling
average of the sum of storeroom expenses, storeroom overheads, related
EUASC expenses, inventory over/short, lobby stock, storeroom electric use,
misc. journal entries applied to all stock items issued by the storeroom.
We maintain stockrooms at all operating centers. The square footage is not
readily available. The Lincoln and Newport stockrooms provide for some
level of expandability.
<PAGE>
ADDRL (12/19/98)
39
1
39. High-level overview of central stores, e.g. value of inventory, annual
receipts and issues, square footage, expandability.
EUA operates on a "main stocking" philosophy. A number of stock items are
stocked at one of the retail company stockrooms in quantity sufficient to
provide for the needs of the other retail locations. The daily courier or
scheduled trips by the stockroom stake-body vehicle are used to deliver
this material where needed. We are presently studying a central warehouse
concept.
Total value of inventory (excluding Somerset plant) is $3,600,000.
Annual receipts are $730,000.
Annual issues are $760,000.
Inventory Turns Ratio (no exclusions) as of 10/31/98 is 1.30.
We maintain stockrooms at all operating centers. The square footage is not
readily available. The Lincoln and Newport stockrooms provide for some
level of expandability.
<PAGE>
DDRL (12/17/98)
56
1
56. Details of how the Company manages distribution transformer inventory.
Transformers are pre-capitalized. The inventory level of transformers is
managed by the Materials Management Department. Similar to regular
inventory items, minimums and maximums are established for the most
frequently used distribution transformers. All purchases are coordinated by
Materials Management. Engineering provides input on planned requirements. A
goal of 4% in-stock to in-service units has been established for Materials
Management. Transformer refurbishing is performed by an outside firm.
Refurbishing and junking are coordinated by Materials Management.
<PAGE>
DDRL (12/17/98)
58
1
58. List of the ten largest contracts the Company and its utility subsidiaries
have with suppliers of O&M related equipment and services.
Contract Services
DESCRIPTION 1998
VENDOR NAME OF SERVICE PROJECTED INPUTS
Asplundh Tree Expert Co. Vegetation Control $936,240 $000
Barnes Tree Service Vegetation Control 540,220
R.A. Gill Tree Service Vegetation Control 319,604
Northern Tree Service Vegetation Control 418,796 2,383
New England Tree Vegetation Control 99,253
Vegetation, Inc. Vegetation Control 69,150
Collins Crane Rigging 1,325
Clean Harbors Environmental 60,973
Environ. Protect. Serv. Transformer Refurbishin 75,833 198
QSC Tower Painting 60,000
<PAGE>
ADDRL #38
N38 38
BLACKSTONE VALLEY ELECTRIC 2
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
Asplundh Tree Trimming 56,222
Barnes Tree Services Tree Trimming 140,399
Blackstone Valley Security Security Services 0
Clean Harbor Environmental 19,603
Coopers & Lybrand Accounting 34,145
Credit Bureau Collection Fees 20,959
Dickstein, Shapiro & Moris Legal
Financial Collection Collection Fees 1,149
Isaacson, Rosenbaum Legal 743,588
McDermott, Will & Emery Legal 32,576
Northern Tree Service Tree Trimming 491,290
Ocean State Janitorial Cleaning 40,408
Osmose Wood Press Pole Treatment/Inspection 448
Stanley Bleeker, Esq. Legal 0
Tillinghast, Collins & Graham Legal 1,911
(A) Colflax Packing Conservation 1,214
(A) Delta Electric Motor Conservation 639
(A) RISE Conservation 7,690
(A) Slater Dye Works Conservation 17,313
-------
1,609,534
=========
(A) These vendors participated in Eastern Edison's conservation, load,
management programs. management programs.
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16.
Prepared by Michelle Uzzo 12/22/98
<PAGE>
<TABLE>
<CAPTION>
EASTERN EDISON COMPANY 38
PROFESSIONAL SERVICES 3
VENDOR NAME DESCRIPTION OF SERVICE 1997
<S> <C> <C> <C>
American Staffing Assoc. Employment 118,240
Asplundh Tree Trimming 919,253
Barnes Tree Service Tree Trimming 140,782
Clean Harbors Environmental
Coopers and Lybrand Accounting 62,883
Duff & Phelps Consulting 40,000
Environmental Protection Service Maintenance 44,555
First Financial Resources Collection Fees 33,933
First Security Services Security
Hanson Police Dept. Police Detail 31,478
J. D. Payroll Services Temp Services
MASS Save Consulting 342,286
McDermott,Will & Emery Legal 1,209,449
Misc. Contract Services* 1,605,966
Misc. Engineering* 38,605
Misc. Legal* 12,155
Miscellaneous* 314,463
Osmose Wood Press Pole Treatment/Inspection
Pembroke Police Dept. Police Detail
R.A. Gill Tree Service Tree Trimming 227,341
R.E. Tilgren Tree Trimming 46,695
Read, Adami, Kaiser Legal 72,599
Rockland Police Dept Police Detail 26,218
Service Master Maintenance 29,796
State Street Bank & Trust Trustee/Administrative Fee
Suburban Contract Cleaning
Town of Bridgewater Police Detail
Town of Easton Police Detail 56,526
Town of Norwell Police Detail 42,745
Town of Scituate Police Detail
Town of Stoughton Police Detail
(A) Conservation Services Group Conservation 361,903
(A) Demand Mgmt Conservation
(A) Energie Innovation Inc. Conservation 84,095
(A) Energy Conservation Conservation 123,124
(A) Energy Federation Conservation 306,904
(A) Fall Realty & Harris Energy Conservation 38,353
(A) Fleet Bank Conservation 28,182
(A) Harris Energy Systems Conservation 489,801
(A) J&R Industrial Wiring Conservation 206,124
(A) Main Street Textiles Conservation 133,990
(A) MUPAC Corp & Harris Energy Conservation 26,114
(A) National Resource Mgmt. Conservation 375,923
(A) Relocation Resources, Inc. Conservation 61,985
(A) Shaws Supermarkets Inc. Conservation 168,265
(A) Star Market & Harris Energy Conservation 31,080
(A) Stop & Shop Supermarket Co. Conservation 49,799
(A) Ware Rite & Harris Energy Conservation 32,759
(A) Whaling Mfg. Co., Inc. Conservation 29,235
-------
7,963,604
=========
</TABLE>
* Aggregate amounts to any one entity less than $25,000 have been accumulated
in this description.
(A) These vendors participated in Eastern Edison's conservation, load,
management programs. management programs.
Note: The source for this information was based on O&M codes 9, 10, 11 &
16.
<PAGE>
NEWPORT ELECTRIC CORPORATION 38
PROFESSIONAL SERVICES 4
VENDOR NAME DESCRIPTION OF SERVICE 1997
Barnes Tree Services Tree Trimming 187,206
Clean Harbor Environmental 11,989
Coopers & Lybrand Accounting 30,982
Credit Info Collection Fees 12,118
McDermott, Will & Emery Legal 16,803
Morgan, Brown & Joy Legal 340
RISE Conservation 141,057
Tillinghast, Collins & Graham Legal 45,587
------
446,062
=======
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19.
<PAGE>
EUA Service Corp. 38
PROFESSIONAL SERVICES 5
(Account # 923)
<TABLE>
<CAPTION>
VENDOR NAME DESCRIPTION OF SERVICE 1997
<S> <C>
McDermott, Will & Emery Legal 359,773
First Security Services Security 124,975
Contract Cleaning Collaborative Cleaning
Eastern Edison Company Arborist/Technical Trainers 351,846
Salomon Brothers Inc. Investment Services 107,956
Media Concepts Printing Services 114,897
Norfolk Date Data Processing Time Cards
Cambridge Reports, Inc. Customer Services 70,560
J. Flanagan & Co. Legislative Activity 48,000
DRI McGraw-Hill
Newport Electric Corp. Arborist/Technical Trainers
Twenty First Century
AUC Management Consultants Consulting
Misc Legal * 82,677
Misc Accounting 68,988
Misc EDP * 41,871
Misc Building & Maintenance 182,203
Other * 421,494
Misc Engineering 788
---
1,956,038
</TABLE>
* Payments made to payee is less than $100,000
Amounts in Bold print are estimates based on the average of 1996 & 1997.
Prepared by Michelle Uzzo 12/22108 o:\profsvs
<PAGE>
VEHICLES
56
DDRL (12/17/98) 1
54. Details of vehicles including:
- types and numbers of vehicles
- age of vehicles
- maintenance programs and replacement criteria
- fuel management programs
- criteria for assigning vehicles to non-physical workers
12/15/98
TYPE OF FLEET VEHICLE COUNT
BUCKET TRUCK, MATERIAL HANDLER 51
BUCKET TRUCK, LIGHT-DUTY 15
DIGGER -DERRICK TRUCK 8
VAN, LARGE STEP TYPE 25
VAN, SMALL 68
DUMPTRUCK 8
STAKE-BODY TRUCK 2
EFFER CRANE TRUCK 3
PICKUP TRUCK 110
SEDAN 52
TRAILER 62
MOBILE SUBSTATION, XFMR OR REGUL. 6
TRACTOR 5
FORKLIFT 11
TRACK VEHICLE 1
CRANE TRUCK 2
TANKER TRUCK 1
SPECIAL EQUIPMENT* 24
TOTAL 454
* Includes powered reel trailers, puller-tensioners, woodchippers, generator
trailer, cement mixer, tank trailer, test equipment trailers, waterpump
trailer, compressors.
AVERAGE AGE OF VEHICLES MONTHS
All Vehicles (excl. trailers, spec. equip.) 93
All Units 120
<PAGE>
DDRL (12/17/98) 54
2
54. Cont'd
MAINTENANCE PROGRAMS AND REPLACEMENT CRITERIA
EUA adheres to a preventative maintenance program based on manufacturers'
recommendations, generally accepted automotive industry practices and experience
related specifically to a particular vehicle or class of vehicles. A
computerized maintenance management system (FleetTracker) is used to track
vehicle usage in terms of miles and/or hours and scheduled maintenance periods
to determine when "A", "B" or "C" level maintenance procedures are due.
The replacement of a vehicle is considered based on the following criteria:
Aerial devices are considered for replacement based on age and condition of
the boom and chassis (particularly with respect to fiberglass strength and
metal fatigue). These vehicles are usually replaced at the 12-14 year
point.
Other large vehicles (e.g. step vans, stakebody trucks, etc.) are
considered for replacement based on condition of chassis and body. These
vehicles are usually replaced at the 12-14 year point.
Small vehicles (e.g. panel vans, pickups, etc.) are considered for
replacement based on condition of body and engine maintenance needs and are
typically replaced at a point above 130,000 miles.
FUEL MANAGEMENT PROGRAMS
PetroVend fuel management systems and VeederRoot leak detection systems are
installed at all EUA gasoline fueling stations.
<PAGE>
DDRL (12/17/98) 54
3
54. Cont'd
CRITERIA FOR ASSIGNING VEHICLES TO NON-PHYSICAL WORKERS
Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis
to firstline supervisors who are in the field most of the workday, who must be
visible to customers and within the communities, and who have on-call and
emergency responsibilities.
Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis
to certain management personnel in Operations due to their emergency
responsibilities.
Vehicles are provided to certain executives as part of their compensation
package.
Other non-physical workers, such as engineers and distribution service
coordinators, have access to company vehicles during the workday.
<PAGE>
NEES Supply Chain in $000
Overall Purchases
1997 T&D purchase order spending 217,528
incl supplies, materials, services
1998 estimate 211,979
1997 po and non-po spending
Cable 16,047
Transformers 13,908
Wood poles 3,288
Meters and accessories (po only) 3,585
Contractor Services
1997 veg. mgt 17,609
Inventory
8/98 RBU inventory 14,211
9/98 distribution transformers 14,123
12/97 meters 2,762
Vehicles
Passenger 35
Trucks 1504 (incl. 318 aerial)
<PAGE>
<TABLE>
<CAPTION>
Exhibit DJH-2
Facilities
FACILITIES
in $000
Prelim DDRL #33
BOSTON W. BRIDGEWATER
<S> <C> <C> <C>
Miscellaneous 413 Note: WB excludes internal labor
M&S, Stores 170 of $1.1 million
Outside Svcs 111
IS 9
Rents 346 34
Contract Services 6 467
Overheads 31
Sub-total 383 1,204 1,587
Ownership cost for WB 2,470
(levelized)
Total 4,057
Escalate to 2000 1.03
- ---------------------------------------------------------------------------
Total savings in 2000 4,179
- ---------------------------------------------------------------------------
BOSTON lease exp 1999; assume no change in cost per sq ft
WEST BRIDGEWATER WESTBOROUGH room for 300-350
Levelized cost 2,470 additional people
60,000 sq. ft.
structures and improvements 18,860
life 40 year
carrying cost 10.50% Annual Westborough cost incl.lease ($3.6)
property tax 2.50% $5 million
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PDDRL 12/17/98
33. List of all facilities owned or leased, including the following:
(a) Address:
(b) Occupied space in square feet; space available for expansion;
(c) Description of the lease, including monthly cost, terms, and a description of assignability or change of control provisions;
(d) Number of employees using the facility, including detail as to department/function.
(e) If owned, estimate of the current market value;
(f) Whether or not the facility is known to have experienced any instances of oil or hazardous material releases which would
subject the facility to response actions under the Massachusetts or Rhode Island waste site cleanup regulations. If such releases
have occurred, provide a summary of the status of the remedial response, any future costs expected to be incurred in addressing
the release(s)and the duration of the response action(s).
(g) Provide a statement of the presence and condition of asbestos, lead or other hazardous substances that may be present in the
facility and, if present, the plan and costs for maintaining or removing the substances
Note 1 Note 3
Company (a) (b) (c) (d) (e) (f) (g)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
Eastern Edison 161 Mulberry St. $23,000 N/A 102 $750,000 None None
Brockton Mass
82 Hartwell St $20,250 N/A 67 $550,000 None None
60 Hartwell St. $18,500 $250,000 Note 5
River St. $11,200 $215,000 Note 6
Fall River Mass
10 Phillips Lane $14,400 N/A 21 $1,500,000 None None
Hanover Mass
Blackstone Valley 642 Washington Highway $60,000 N/A 94 $2,000,000 Note None
Electric Lincoln, Rhode Island 4
Newport Electric 12 Turner Road Note 7 $35,000 N/A 49 $1,500,000 None None
Middletown, Rhode Island
EUA Service EUA Corporate Offices $12,800 Note 2 20 N/A None None
Corporation One Liberty Square
Boston, Mass
EUA System Operating $133,000 N/A 542 $20,000,000 None None
Center
750 West Center Street
West Bridgewater Mass
Note 1: Available for expansion: Lincoln 12000 sq. Ft., Fall River 8500 sq. ft.
Note 2: Boston Office lease and overheads are $382,450 and expires 1999
Note 3: Detail of employees by company, department/function is attached.
Note 4: See second page attachment
Note 5: Lead Paint
Note 6: Asbestos in boiler room
Note 7: Leased space to Bank of Newport - $140,000 annual net income.
</TABLE>
<PAGE>
PDRL OF 12/17/98
continued
33. List of all facilities, owned or leased, indicating the following:
a) address;
b) occupied space in square feet; space available for expansion;
c) description of the lease, including monthly cost, terms, and a
description of assighnability or change of control provisions;
d) number of employees using the facility; including detail as to
department/function;
e) if owned, estimate of current market value;
f) whether or not the facility is known to have experienced any instances
of oil or hazardous material releases which would subject the facility
to response actions under the Massachusetts or Rhode Island waste site
cleanup regulations. If such releases have occurred, provide a summary
of the status of the remedial response, any future costs expected to
be incurred in addressing the release(s) and the duration of the
response actions(s)
g) provide a statement of the presence and condition of asbestos, lead or
other hazardous substances that may be present in the facility and, if
present, the plan and costs for maintaining or removing the
substances.
Note 4: Blackstone Valley Electric experienced a release of gasoline in
1989 from an underground storage tank at its Lincoln Operations
facility. The release was detected during an annual tightness testing,
and was estimated at approximately 100 gallons. Soil and groundwater
were impacted. A removal action was performed in 1989, and a
groundwater treatment system has been in operation since that time.
The zone of contamination has been reduced to a small area and levels
of contamination greatly reduced. BVE expects to resolve this matter
in 1999 and complete this response action with little additional
expense. The costs to complete are not expected to be material.
<PAGE>
<TABLE>
<CAPTION>
PDDRL 12/17/98
Facility Expense
33d cont.
Company EUA Service Corporation Eastern Edison Blackstone Valley Newport
Location Boston W. Bridgewater Brockton Fall River Lincoln Middletown
<S> <C> <C> <C> <C> <C>
Miscellaneous 413,400
Payroll 1,051,400 90,900 94,300 92,200 84,800
Employee Expense 10,800 500 500 500 500
Education & Training 5,300 500 500 500 500
Materials & Supplies 151,500 19,000 44,500 23,600 12,000
Stores 18,800 10,000 8,900 11,000 9,000
Outside Services 111,000
Information Systems - Hardware 9,400
Rents 345,600 33,500 25,500 500 26,400 8,500
Contract Services 5,850 467,400 104,500 69,900 128,600 59,100
Office Overheads 31,000 33,000 22,000 90,000 28,000
Totals $382,450 $2,272,500 $283,900 $241,100 $372,800 $202,400
System Total $3,755,150
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
33d
Meter OH Property
Company Address Union Reading Lines Trouble Meter Garage Stores Maint.
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Eastern Edison 161 Mulberry St. None X X X X X X X
Brockton Mass.
82 Hartwell St. IBEW X X X X X X X
Fall River Mass.
10 Phillips Lane None X X X
Hanover Mass.
Blackstone Valley 642 Washington Highway None X X X X X X X
Electric Lincoln, Rhode Island
Newport Electric 12 Turner Road BUW X X X X X X X
Middletown, Rhode Island
</TABLE>
<TABLE>
<CAPTION>
33d
UG Substation Radio & System Consumer
Company Address Union Lines Maint. Microwave Operations Service
<S> <C> <C> <C> <C> <C> <C> <C>
Eastern Edison 161 Mulberry St. None X X X
Brockton Mass.
82 Hartwell St. IBEW X X
Fall River Mass.
10 Phillips Lane None
Havoner Mass.
Blackstone Valley 642 Washington Highway None X X X X
Electric Lincoln, Rhode Island
Newport Electric 12 Turner Road BUW X X X
Middletown, Rhode Island
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PDDRL 12/17/98
33d cont.
Company Address Union Function Performed
==================================================================================================================================
<S> <C> <C> <C>
EUA Service Corporation EUA Corporate Offices None Corporate Executive Offices
One Liberty Square Treasury
Boston Mass.
EUA System Operating Center None Executive - Admin. & Support
750 West Center Street Facilities Management
West Bridgewater Mass. Internal Audit
Consumer Services
Marketing
Information Services
Human Resources
Corporate Communications
Corporate Benefits
Risk Management
Office Services
Safety
Transmission Services
Load Forecasting
Power Supply
Special Projects
Purchasing
Material Management
Rates
Accounting
Customer Service
Security
Real Estate
Engineering
Transmission and
Distribution
Somerset Station None Transmission Crews
1606 Riverside Avenue
Somerset Mass.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
(ALL FROM U13-60) ACC DEPN
12/31/97 @ 12/31/97 NET
<S> <C> <C> <C> <C>
WB BUILDING 18142620 4015211 14127409
LAND & LAND RIGHTS 717080 0 717080
18859700 4015211 14844489
DEPRECIATION 452158
YEARS 40
COST % OF TOTAL TAX(B)
<S> <C> <C> <C> <C> <C>
C EUASC COMMON EQUITY 2895346 11.00% 19.50% 0.
EUASC LTD 6800000 10.20% 45.81%
9695346
A SHORT TERM 5149143 6.50% 34.69%
14844489 100.00%
A - ASSUMED REMAINING BALANCE FINANCED BY EUA SHORT TERM BORROWINGS
B - COMBINED TAX RATES (FED AND STATE) OF 40%
C - USED RETURN ON COMMON EQUITY OF RETAILS
REVENUE REQUIREMENTS
<S> <C>
DEPRECIATION (% OF UNDEPRECIATED) 3.05%
CARRYING COSTS 10.50%
COUNTY TAXES 2.50%
TOTAL 16.05%
</TABLE>
<PAGE>
Exhibit DJH-2
Administrative and
General Savings
--------------------------------------------------------------------
Mercer Management Consulting
<PAGE>
<TABLE>
<CAPTION>
A&G Overheads
in $000
This savings component reflects miscellaneous overheads, such as office supplies
and personal computers; but excludes facilities and benefits related overheads
EE BVE NE Total
<S> <C> <C> <C> <C>
FERC Acct #921 730 394 201 1,325
Office supplies and expenses
employees 881
per employee (000) 1.5
(higher for service co only)
EUA PC costs configured prices of 1.9-3.4 per unit (in 000)
Annualized cost for pc, cell phones, and pagers 640
Savings per employee 3
reduced in $000 in 2000
Savings in 2000 486
162 reductions x 3
Savings in 2001 690
225 cumulative red. X 3 x I.022
Savings in 2002 733
234 cumulative red. X 3 x 1.044
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
48 Summary of other miscellaneous A&G overheads.
See attached.
<PAGE>
<TABLE>
<CAPTION>
Summary - Other Miscellaneous and A&G
Company 1997
- ------- ----
<S> <C>
Blackstone Valley Electric Company $344,714.00
Eastern Edison Company $632,170.00
Newport Electric Corporation $238,947.00
Total $1,215,831.00
=============
Blackstone Valley Electric Company
Description 1997
- ----------- ----
Industrial Association Dues $49,591.00
Other Experimental & General Research $339.00
Publishing and Distribution Information and reports
as well as other expenses of servicing Outstanding
Securities of Respondent. $37,084.00
EUA Service Corporation General and Administrative $161,923.00
R.I. Industrial Revenue Bonds Fee $8,125.00
Employee Training and Seminars $85,298.00
Citicorp Remarketing - R.I. Industrial Bonds $22,344.00
Miscellaneous $10.00
-------------
Total $344,714.00
=============
Eastern Edison Company
Description 1997
- ----------- ----
Industrial Association Dues $103,047.00
Other Experimental & General Research $701.00
Publishing and Distribution information and reports
as well as other expenses of servicing Outstanding
Securities of Respondent. $68,824.00
EUA Service Corporation General and Administrative $314,908.00
Employee Training and Seminars $138,456.00
Service Anniversary Expense $4,864.00
Miscellaneous $1,370.00
-------------
Total $632,170.00
=============
Newport Electric Corporation
Description 1997
- ----------- ----
Industrial Association Dues $24,190.00
Other Experimental & General Research $131.00
Publishing and Distribution Information and reports
as well as other expenses of servicing Outstanding
Securities of Respondent. $18,200.00
EUA Service Corporation General and Administrative $85,579.00
Employee Training and Seminars $41,155.00
Settlement Agreement $58,481.00
Remarketing Expenses $10,146.00
Miscellaneous $1,085.00
-------------
Total $236,447.00
=============
</TABLE>
<PAGE>
GP6-350 Page 1 of 2
For the Enthusiast Customize It & Buy It!
GP6-350
============================================================
Processor: Intel 350MHz Pentium II Processor w/
512K Cache
Memory: 64MB 100MHz SDRAM expandable to
256MB
Monitor: EV700 l7inch color monitor (15.9inch
viewable area)
Graphics Accelerator: Integrated nVidia 8MB
AGP Graphics Accelerator
Hard Drive: 10GB Ultra ATA hard drive added:
US$60
Floppy Drive: 3.5inch 1.44MB diskette drive
(IOMEGA Internal ZIP Drive Deleted) subtracted:
US$50
CD-ROM: 13X min./32X max. CD-ROM drive
Multimedia Package: Boston Acoustics BA635
Speakers added: US$30
Sound System: Integrated Sound Blaster AudioPCI
64D
Case: Mid Tower Case
Network Adapter: 3COM PCI 10/100 twisted pair
Ethernet
Keyboard: 104+ Keyboard
Mouse: MS IntelliMouse Mouse; Gateway mouse
pad
Additional Software: McAfee Anti Virus Software
Application Software: MS Office 97, Small
Business Edition, on CD w/Bookshelf
Operating System: Microsoft Windows 98
Service Program: Gateway Gold Service for PCs
(1 yr. Onsite)
Tape Backup Unit: TR5 IDE TBU and tape added:
US$249
============================================================
Base Price: US $1599
Configured Price: US $1888
Quantity: 1
Total Price: US $1888
============================================================
<PAGE>
============================================================
Many Gateway products are custom engineered to
Gateway specifications, which may vary from the
retail versions of the software and/or hardware in
functionality, performance or compatibility.
Prices and configurations are subject to change
without notice or obligation. The price above does
not include shipping and handling or any
applicable taxes. After your system has been
built (lead times vary), it may be shipped
via second-day shipping in the continental
U.S.
Second-day shipping within the continental U.S. is
US$95 for desktops and US$25 for portables.
Five-day shipping for Destination (R) Digital
Media Computers is US$149. All prices quoted are
in U.S. dollars.
o I would like to order this system via
the World Wide Web.
Clicking "Continue" below takes you to
our secure server. Gateway uses Secure
Sockets Layer (SSL) encryption to assure
that all information entered on the next
screen --including your credit card
number -- can only be understood by us.
After thousands of online transactions
worth millions of dollars, no Gateway
client has ever reported misappropriation
of a credit card number protected by SSL
technology. Check our article on how SSL
works and why we think it's extremely
safe to learn more.
o Please have a sales representative
contact me about this system or other Gateway
products.
Copyright (C) 1997, 1998 Gateway 2000 Inc.
All rights reserved.
Please see our ______________________. Please
send feedback to ___________________________.
<PAGE>
GP6-450 Page 1 of 2
For the Enthusiast Customize It & Buy It!
GP6-450
============================================================
Processor: Intel 450MHz Pentium II Processor w/
512K Cache
Memory: 128MB 100Mhz SDRAM expandable to
384
Monitor: VX900T 19inch color monitor (18.0 inch
viewable area) added: US$60
Graphics Accelerator: 16MB AGP Graphics
Accelerator
Hard Drive: 16.8GB 5400RPM Ultra ATA hard
drive
Floppy Drive: 3.5inch 1.44MB diskette drive &
SuperDisk LS-120 w/5 Disks added:US$60
CD-ROM: 13X min./32X max. CD-ROM drive
Multimedia Package: Boston Acoustics BA635
Speakers added: US$30
Sound System: Integrated Sound Blaster AudioPCI
64D
Fax/Modem: TelePath(R) 56K Modem added:
US$129
Case: Tower added: US$50
Network Adapter: 3COM PCI 10/100 twisted pair
Ethernet
Keyboard: 104+ Keyboard
Mouse: MS IntelliMouse Mouse; Gateway mouse
pad
Additional Software: McAfee Anti Virus Software
Application Software: MS Office 97, Professional
Edition, on CD added: US$199
Operating System: Microsoft Windows 98
Service Program: Gateway Gold Service for PCs
(lyr. Onsite)
Tape Backup Unit: TR5 IDE TBU and tape added:
US$249
============================================================
Base Price: US $2599
Configured Price: US $3376
Quantity: 1
Total Price: US $3376
============================================================
<PAGE>
Many Gateway products are custom engineered to
Gateway specifications, which may vary from the
retail versions of the software and/or hardware
in functionality, performance or compatibility.
Prices and configurations are subject to change
without notice or obligation. The price above
does not include shipping and handling or any
applicable taxes. After your system has been
built (lead times vary), it may be shipped
via second-day shipping in the continental
U.S.
Second-day shipping within the continental U.S. is
US$95 for desktops and US$25 for portables.
Five-day shipping for Destination (R) Digital
Media Computers is US$149. All prices quoted are
in U.S. dollars.
o I would like to order this system via
the World Wide Web.
Clicking "Continue" below takes you to
our secure server. Gateway uses Secure
Sockets Layer (SSL) encryption to assure
that all information entered on the next
screen --including your credit card
number -- can only be understood by us.
After thousands of online transactions
worth millions of dollars, no Gateway
client has ever reported misappropriation
of a credit card number protected by SSL
technology. Check our article on how SSL
works and why we think it's extremely
safe to learn more.
o Please have a sales representative
contact me about this system or other Gateway
products.
Copyright (C) 1997, 1998 Gateway 2000 Inc.
All rights reserved.
Please see our ______________________. Please send
feedback to ___________________________.
<PAGE>
Privileged and Confidential
ADDRL #34
34. Estimate of "personal tools" costs per employee, e.g. PC, pager, cellular
phone. (This information is needed to estimate merger savings.).
1. Workstation replacement program ended in 1997. There are about 50
workstations currently in use. They will be phased out through
attrition.
2. Replacement of PCs is a department head decision. Expected
replacements are identified in the O&M budget. A PC Replacement form
is used as a control document.
3. New PCs are identified in the O&M budget (unless they are related to a
capital project). A PC Acquisition form is used as a control document.
4. Average replacement costs and base-line specifications for the two
classes of recommended PCs is attached - #1.
5. Divisional breakdown of PCs is attached - #2.
6. Average life expectance for a PC is three years. However, older useful
PCs are recirculated to low-end users identified by department heads.
7. Department heads on an as needed basis distributes pagers and cell
phones.
8. Company annualized cost for PC's - $450,000; pagers and cell phones -
$90,000.
<PAGE>
1998 Inventory
Number of PCs by Department
Total Configurations as of 12/14/98: 584
Accounting 48
Bldg & Facil 11
CIS 78
Engineering 70
Executive 31
Garage 10
Gen. Office Svcs 2
HR 30
Info Services 62
Internal Audit 4
Meter 11
Meter Reading 11
Power Supply 15
Purchasing 6
Rates 23
Real Estate 5
Records 1
Retail Bus Svcs. 65
Safety & Risk Mgmt 7
SCADA 5
Special Projects 5
Stores Mgmt & Supp 14
Sub & Comm 13
System Operations 3
Telecommunications 3
Trans & Dist 32
Trans Svcs 7
<PAGE>
<TABLE>
<CAPTION>
Advertising
in $000
1997 1998 annualized
EUA NEES
<S> <C> <C> <C>
Addit. data req #47 825 Customer 4,318 dsm,choice related
Normalized 500 Image 50 FERC #
930.1
4,368
Savings 50%
Savings in 1997 250
Escalation to 2000 1.09
Savings in 2000 273
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
47 Summary of advertising costs.
See attached.
<PAGE>
<TABLE>
<CAPTION>
Advertising Costs - 1997 1997
------------------------ ----
Company Advertising Costs
------- -----------------
<S> <C> <C>
Co 01 Blackstone Valley Electric $215,091.17
Co 08 Eastern Edison Company $519,027.05
Co 14 Newport Electric Corporatio $90,729.57
------------
Total $824,847.79
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Association Dues
in $000
Addit data req # 45, 48
EUA 1997 Savings% Savings
<S> <C> <C>
EEI 136 25% 34
Other 41 100% 41
177 42% 75
Escalation to 2000 1.09
Savings in 2000 82
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
45 Summary of associations dues.
1997 Blackstone Newport Eastern Total
- ---- ---------- ------- ------- -----
<S> <C> <C> <C> <C>
Utility Air Regulatory Group 225 562 787
Electric Council of New England 6,983 2,745 13,665 23,393
EEI 38,842 17,780 78,980 135,602
Utility Water Act Group 2,847 2,788 5,752 11,387
Associated Industries of MA 720 720
NU College of Business 2,500 2,500
Administration
Miscellaneous 696 315 1,431 2,442
49,593 24,190 103,048 176,831
</TABLE>
<PAGE>
Benefits Administration
in $000
Expect no savings in HMO ( self insured) and group life
Minimal savings in retirement and thrift plan administration
Per conversation with NEES
Savings in 2000 50
<PAGE>
12/19/98
ADDITIONAL DUE DILIGENCE (List
#3)
REQUEST LIST
PRIVILEGED AND CONFIDENTIAL
ATTORNEY-CLIENT COMMUNICATION
ATTORNEY WORK PRODUCT
ADDRL #
46 Cost to administer benefits.
<PAGE>
<TABLE>
<CAPTION>
EASTERN UTILITIES ASSOCIATES
Responsibility Center 220 - Corporate Benefits
O&M Budget 1999
"ADDRL"12/19/98
Question #46
OTHER EXPENSES: O&M EUASC
<S> <C> <C>
XX Payroll 01 $220,000
20 Miscellaneous (NEEBC Dues) 00 $400
20 Retiree Organizations Support (700 rets @ $10.00) 00 $7,000
01 Employee Expense 05 $1,800
XX Ed. & Training 06 $3,500
20 Materials & Supplies 07 $2,000
07 Materials & Supplies - WSJ,CCH 07 $1,600
XX General Consulting - Pension & ESP* 11 $36,000*
20 Financial Education/ Retirement Planning Program 11 $23,500
20 FSA Admin. Fees-Estimated FICA tax offset is $10,000 11 $9,000
20 Executive Annual Physicals 11 $16,800
20 Split $ Consulting Fee - Vinings Management 11 $16,900
25 Cyborg Maintenance Contract 22 $12,500
Total Other Expenses: $351,000
========
* not payable from the pension trusts.
</TABLE>
<TABLE>
<CAPTION>
<PAGE>
TOTAL
BVE EECO NEWPORT EUASC TOTAL EUASC
<S> <C> <C> <C> <C> <C> <C>
Group Health 452,022 978,362 211,337 171,001 1,812,722 204,034
Dental Insurance 49,016 105,728 33,918 3,130,326 3,318,988 3,735,027
Group Life 7,154 65,696 35,153 570,642 678,645 680,876
Pension (854,720) (1,351,822) (74,320) 4,329,463 2,048,601 5,165,807
Post Retirement Benefits 1,319,782 2,284,618 588,458 356,773 4,549,631 425,693
Employee Thrift Plan 113,012 218,567 94,990 0 426,569
1,086,266 2,301,149 889,536 8,558,205 12,835,156 10,211,437
----------
12,835,156
BVE 2,367,906 0.276698653 0.2319
EECO 4,621,878 0.540083693 0.4526
NWPT 1,231,339 0.143886557 0.1206
MECO TRANS 336,584 0.039331097 0.033
8,557,707 1 0.8381
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Corporate Governance
Shareholder Services
in $000
ADDRL #43
EUA 1999 budget Million Million
Shares Price Mkt Cap
<S> <C> <C> <C> <C> <C>
Annual rpt 112 NEES 59.8 48.06 2,874
Transfer agent 87 EUA 20.4 27.81 567
NYSE 33 EUA equiv 11.8
Other 61 % increase 11.8/59.8
293 20%
Savings 80%
Savings in 1999 234
Savings in 2000 241
Trustees
ADDRL #40
1999 1998
EUA NEES
<S> <C> <C>
Outside directors 9 11
Fees 550
Other expenses 100
Total 530 650
Savings in 1999 530
Escalate to 2000 1.03
Savings in 2000 546
Total Corp Governance 787
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
43 Summary of shareholder services expenses, including the production of
the annual report, the annual meeting, mailings and other fees.
Budget for 1999
Annual Report Production 112,000
Mailing of AR and Proxy, etc. 28,000
10K printing 5,700
Proxy printing 7,000
Transfer agent fees 87,000
NYSE listing fee 33,000
Quarterly dividend enclosure 11,000
Postage and miscellaneous 9,700
---------
293,400
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE (List # 3) ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
40 Directors' fees and related expenses.
See attached summary of EUA Parent 1999 Budget for details of
information requested.
<PAGE>
<TABLE>
<CAPTION>
EUA PARENT
1999 BUDGET
1999
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC TOTAL
--- --- --- --- --- --- --- --- --- --- --- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
9200 DO AMORT RESTR STK PLAN 500 500 500 500 500 500 500 500 500 500 500 500 6,000
9302 07 MISCELLANEOUS
FIDUCIARY/DIRECTORS LIB INS 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800
TOTAL 9302 07 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800
9302 09 CORP & FISCAL
MISCELLANEOUS 200 200
9302 06 DIRECTORS FEES
ANNUAL TRUSTEE FEE 36,000 36,000 36,000 36,000 144,000
REGULARLY SCHEDULED MTGS
FULL BOARD 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 84,190
FINANCE COMM 4,250 4,250 4,250 4,250 17,000
AUDIT COMM 4,250 4,250 4,250 12,750
PENSION TRUST COMM 3,400 3,400 3,400 3,400 3,400 3,400 20,400
COMPENSATION 3,400 3,400 3,400 10,200
RETIREMENT BENEFIT 36,130 12,130 12,130 38,130 12,130 12,130 36,130 12,130 12,130 36,130 12,130 12,130 241,560
TOTAL 9302 05 84,030 26,580 24,030 87,430 19,780 27,430 84,030 15,530 27,430 90,830 19,780 23,220 530,100
TOTAL DO 92,263 34,813 32,263 95,853 28,013 35,883 92,263 23,763 35,663 99,063 28,013 31,457 629,100
9230 10 OUTSIDE LEGAL 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700
TOTAL 09 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700
9210 02 OFFICE SUPPLIES & EXP
BANK CHARGES 400 400 400 400 400 400 400 400 400 400 400 400 4,800
9230 20 OUTSIDE ACCOUNTING
C&L AUDIT FEE 4,700 2,800 1,030 1,700 10,000
9302 10 TRANSFER AGENT FEES
COMON STOCK EXPENSE 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 18,000
TOTAL 11 1,400 5,100 5,500 1,400 1,400 2,900 1,400 1,400 2,900 2,400 1,400 4,600 32,800
TOTAL 000 121,963 58,013 52,283 130,483 53,413 46,363 100,563 33,063 40,363 114,383 34,413 42,257 845,600
</TABLE>
<PAGE>
YAHOO! FINANCE Home - Yahoo! - Help Market
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<TABLE>
<CAPTION>
New England Electric Sys. NYSE : NES
<S> <C>
Financial Links
Address: 25 Research Drive o Company News
Westborough, MA 01582 o Research Report: Basic / Detailed
Phone: (508) 389-2000 o Upgrade/Downgrade History
Fax: (508) 836-0276 o Free Annual Report
Industry: Electric Utilities o Latest Stock Price
Sector: Utilities o Insider Trades
Employees: 4,665 o SEC Filings (raw filings)
Officers: Richard P. Sergel, Pres./CEO o Message Board
Joan T. Bok, Chmn.
Cheryl A. Lafleur, Sr. VP/Secy./Counsel
Michael E. Jesanis, Sr. VP/CFO Company's Web Presence
John G. Cochrane, Treas./CAO. o Home Page
o Search Yahoo! for related links...
</TABLE>
Business Summary
NES is a public utility holding company, whose subsidiaries are engaged in the
transmission, distribution, sale and generation of electricity. For the nine
months ended 9/30/98, revenues fell 1% to $1.82 billion. Net income applicable
to Common fell 3% to $157.5 million. Revenues reflect decreases in
generation-related, fuel cost-related, and oil and gas-related revenues.
Earnings also reflect monthly contractual payments to USGen and increased
transmission wheeling costs.
<TABLE>
<CAPTION>
More from Market Guide: Highlights - Performance
Statistics at a Glance - NES Last Updated: Dec 23, 1998
<S> <C> <C> <C> <C> <C>
Price and Volume Per-Share Data Management Effectiveness
(updated Dec 23, 1998) Book Value (mrq) $26.79 Return on Assets (ttm) 4.34%
52-Week Low $38.938 Earnings (ttm) $3.39 Return on Equity (ttm) 12.66%
Recent Price $48.063 Sales (ttm) $38.91 Financial Strength
52-Week High $49.125 Cash (mrq) $8.26 Current Ratio (mrq) 1.23
Beta 0.32 Valuation Ratios Long-Term Debt/Equity (mrq) 0.63
Daily Volume (3- 148.9K Price/Book (mrq) 1.79 Total Cash (mrq) $494.3M
month avg)
Share-Related Items Price/Earnings (ttm) 14.19 Short Interest
Market Capitalization $2.88B Price/Sales (ttm) 1.24 Shares Short 23
as of Dec 8, 1998
<PAGE>
Shares Outstanding 59.8M Income Statements
Float 54.5M After-Tax Income (ttm) $231.8M Short Ratio 5.81
Dividend Information Sales (ttm) $2.48B Stock Performance
Annual Dividend $2.36 Profitability NES 24-Dec-1998 (C) Yahoo!
(indicated) Profit Margin (ttm) 9.3% _____________________________________
50|| |
45|| |
40 | |
35 | |
------------------------------------|
Jan Mar May Jul Sep Nov
big chart [ld | 5d | 3mo | 1yr | 2yr | 5 yr |
max]
Dividend Yield 4.91%
See the Profile FAQ for a description of each item above; K = thousands; M = millions; B = billions;
mrq = most-recent quarter (Sep 30, 1998); ttm = trailing twelve months through Sep 30, 1998
Market Guide offers more in-depth Company Research, Stock Screening, and Hottest Stocks and Industries on over
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Company information Copyright (C) Market Guide
Historical chart data and daily updates provided by Commodity Systems, Inc. (CSI).
Data and information is provided for informational purposes only, and is not intended for trading purposes. Neither Yahoo
nor any of its data or content providers (such as Market Guide, CSI, Reuters, Zacks, etc.) shall be liable for any errors or
delays in the content, or for any actions taken in reliance thereon.
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</TABLE>
<PAGE>
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<TABLE>
<CAPTION>
Eastern Utilities Assoc. NYSE : EUA
Financial Links
<S> <C>
Address: One Liberty Square o Company News
Boston MA 02109 o Research Report: Basic / Detailed
Phone: (617) 357-9590 o Latest Stock Price
Fax: (617) 357-7320 o Insider Trades
Industry: Electric Utilities o SEC Filings (raw filings)
Sector: Utilities o Message Board
Employees: 1,180
Officers: Donald G. Pardus, Chmn./CEO
John R. Stevens, Pres./COO Company's Web Presence
Richard M. Burns, Contr./CAO o Home Page
Clifford J. Herbert, Jr., Treas./Secy.
o Search Yahoo! for related links...
</TABLE>
Business Summary
EUA is a holding company for Blackstone, Eastern Edison, and Newport, which
provide retail electric utility services in MA and RI. EUA also operates various
service subsidiaries. For the nine months ended 9/98, revenues fell 4% to $405.4
million. Net income applicable to Common fell 4% to $26.2 million. Results
suffered from a decrease in core electric business revenues due to customer rate
reductions and the termination of the power marketing joint venture.
More from Market Guide: Highlights - Performance
<TABLE>
<CAPTION>
Statistics at a Glance - EUA Last Updated: Dec 23, 1998
Price and Volume Per-Share Data Management Effectiveness
(updated Dec 23, 1998) Book Value (mrq) $18.27 Return on Assets (ttm) 3.05%
<S> <C> <C> <C>
52-Week Low $23.563 Earnings (ttm) $1.80 Return on Equity (ttm) 9.85%
Recent Price $27.813 Sales (ttm) $26.98 Financial Strength
52-Week High $28.00 Cash (mrq) $0.33 Current Ratio (mrq) 0.71
Beta 0.50 Valuation Ratios Long-Term Debt/Equity (mrq) 0.77
Daily Volume (3- 73.9K Price/Book (mrq) 1.52 Total Cash (mrq) $6.64M
month avg) Price/Earnings (ttm) 15.45 Short Interest
Share-Related Items Price/Sales (ttm) 1.03 Shares Short
as of Dec 8, 1998 137.9
Market Capitalization $568.4M
Shares Outstanding 20.4M Income Statements Short Ratio
Float 20.2M After-Tax Income (ttm) $39.1M
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Financing Costs and Fees
in $000
Includes savings associated with lines of credit
Lines of Credit
1998 est
NEES x NEP EUA
<S> <C> <C>
Commitment fees 567 256
Lines of credit 637,000 165,000
% fee 0.089% 0.155%
Savings 100%
Savings in 1998 256
Escalation to 2000 1.06
Savings in 2000 272
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE (List #3) ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
41 Summary of any lines of credit.
See attached summary of EUA System lines of credit.
<PAGE>
<TABLE>
<CAPTION>
EUA SYSTEM
Short-Term Credit Facility Fees (1)
For 1998/1999
LINE FACILITY ANNUAL
BANK OF CREDIT FEE FEE EUA BVE EECO
<S> <C> <C> <C> <C> <C> <C>
REVOLVING CREDIT FACILITY:
BANK OF NEW YORK $100,000,000 $20,000,000 $75,000,000
(Availability: All Companies) 29% 6% 21%
$75,000,000 0.1250% $93,750 $26,786 $5,357 $20,089
OTHER CREDIT FACILITIES: $20,000,000 $75,000,000
BANK OF NEW YORK 16% 60%
(Availability: BVE,EECO, MECO) $10,000,000 0.1250% $12,500 $2,000 $7,500
STATE STREET BANK $100,000,000 $75,000,000
(Availability: EUA, EECO) 57% 43%
$15,000,000 0.2500% $37,500 $21,429 $16,071
UNION BANK OF CALIFORNIA (2) $100,000,000 $20,000,000 $75,000,000
(Availability: EUA, BVE, EECO, MECO, NECO) 8% 30%
$20,000,000 0.1875%(2) $0 40% $0 $0
$0
NATIONS BANK, N.A. $75,000,000
(Availability: EECO) $45,000,000 0.2500% $112,500 100%
$112,500
ANNUAL FACILITY FEE TOTALS $165,000,000 $256,250 $48,214 $7,357 $156,161
MONTHLY ACCRUAL $4,018 $613 $13,013
BANK MECO COGENEX EUA OS SERVICE NECO TOTAL
REVOLVING CREDIT FACILITY: $30,000,000 $75,000,000 $10,000,000 $15,000,000 $25,000,000 $350,000,000
BANK OF NEW YORK 9% 21% 3% 4% 7% 100%
(Availability: All Companies) $8,036 $20,089 $2,679 $4,018 $6,696 $93,750
OTHER CREDIT FACILITIES: $30,000,000 $125,000,000
BANK OF NEW YORK 24% 100%
(Availability: BVE,EECO, MECO) $3,000 $12,500
STATE STREET BANK $175,000,000
(Availability: EUA, EECO) 100%
$37,500
$30,000,000 $25,000,000 $250,000,000
UNION BANK OF CALIFORNIA (2) 12% 10% 100%
(Availability: EUA, BVE, EECO, MECO, NECO) $0 $0 $0
$75,000,000
NATIONS BANK, N.A. 100%
(Availability: EECO) $112,500
ANNUAL FACILITY FEE TOTALS $11,036 $20,089 $2,679 $4,018 $6,696 $256,250
$920 $1,674 $223 $335 $558 $21,354
MONTHLY ACCRUAL
(1) Allocation Percentages Based on March 20, 1998 SEC Order Authorizing Company Short-Term Borrowing Limitations.
(2) Facility Fee based on .1875% of the average daily unused amount of the Facility during such period. For allocation of Fee,
assumption will be credit line will be fully drawn, hence, zero fee.
September 22, 1998
JWH/d:/1231997/comfee/feebad98
</TABLE>
<PAGE>
Insurance Premiums
in $000
Data Response #102
Major Coverages 1999 EUA % Savings Savings
excl MTP
Property 90 5% 5
Property 68 5% 3
Boiler 95 5% 5
Marine Cable
Liability
General 285 50% 143
Excess 343 50% 172
Auto 94 50% 47
Pollution 191 25% 48
D&O adjusted 100 75% 75
Brokerage Fees 175 75% 131
(per phone conversation)
Total 1,441 44% 628
Escalate to 2000 1.03
Savings in 2000 646
<PAGE>
<TABLE>
<CAPTION>
INSURANCE COSTS - 1999
TYPE EECO NPT EUA BVE MTP EUA
TOTAL
<S> <C> <C> <C> <C> <C> <C>
PROPERTY 27000 21300 8200 33500 110000 200000
BOILER 13500 17800 4500 32400 141800 210000
OFFICE CONTENTS 1100 1100
EDP 10000 10000
CONT EQUIP 3178 2794 1377 2651 10000
MICROWAVE 2191 716 4336 1473 1284 10000
VALUABLE PAPERS 133 133 134 400
MARINE CABLE 95000 95000
TRANSIT 722 542 586 550 2400
CRIME 2230 590 6230 1100 850 11000
GENERAL LIABILITY 120000 45000 15000 105000 15000 300000
AUTOMOBILE 42000 14000 17500 21000 5500 100000
AUTO PHYSICAL 8350 2750 3650 4200 1050 20000
WORKERS COMP 55500 15000 19500 30000 30000 150000
D&O 15000 15000 15000 15000 122000 182000
PENSION 2493 662 7046 1195 954 12350
POLLUTION 91000 31500 15000 54000 63500 25500
UNDERGROUND TANKS 1300 2550 2050 2550 2550 11000
EXCESS LIABILITY 130500 42500 100000 70000 37000 380000
LETTER OF CREDIT 25000 25000
MONTAUP EXTRA EXP 140000 140000
BOND PREMIUM 15000 15000
SMALL CLAIM EXPENSE 247500 88000 27500 126500 60500 550000
$762,597 $392,910 $299,539 $499,881 $735,323 $2,690,250
</TABLE>
<PAGE>
DDRL #102
Question: List all liability, property, casualty, and other insurance policies
held by the Company or its subsidiaries, or if self insured, the extent of self
insurance, including limits of coverage, policy dates, premiums, insurance
brokers, and cash surrender value, if any.
Answer: The person in the organization responsible for risk management is not
involved in the data request process. At this point in the process the
information we will provide will be very limited.
Attached you will find the planned 1999 expenses by category. Once the sale of
Montaup is complete, the insurance expenses will be prorated for the remainder
of the policy year.
DDRL #103
Question: Describe all claims made by the Company or its subsidiaries under the
insurance policies carried by the Company or its subsidiaries over the past two
years in which the amount claimed exceeded $1,000,000.
Answer: To the best of my knowledge, none.
DDRL 104
Question: List and describe any pending litigation relating to insurance
coverage.
Answer: To the best of my knowledge there are two cases.
1. The family of a deceased woman in Fall River has filed a claim
against the Company. The woman died as a result of a pedestrian
truck accident involving an EUA driver in a meter van. The driver
was not found to be negligent. Maximum exposure to the Company is
$350,000.
2. A civilian has placed a claim with the Company as a result of a
manhole explosion. The civilian received burns over 30% of his
body. He has nearly fully recovered and is looking for medical
expense recovery. We expect to settle for a reasonable amount.
The maximum exposure is $350,000.
In both cases the insurance will cover anything over the $350,000. Neither case
is expected to exceed the $350,000 deductible.
DDRL #105
Question: Copies of all material correspondence with insurers or insurance
brokers or agents relating to environmental impairment liability claims.
Answer: Did not have access to the information
<PAGE>
<TABLE>
<CAPTION>
Professional Services
in $000
1997
BE EE NE Service Total
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Addit. data req #38 1,610 7,964 446 1,956 11,976
incl. ops-related Savings % Savings
Accounting 34 63 31 69 197 50% 99
Legal incl dereg
McDermott 33 1,209 17 360
Isaacson 744
Other 2 73 46 83
Total 779 1,282 63 443 2,567
adj. 1,500 33% 495
Employment 118 118 33% 39
Consulting 40 40 100% 40
Invest. Svcs 108 108 100% 108
Legislative 48 48 100% 48
Prof Svcs Total 2,011 41% 828
Escalation to 2000 1.093
Savings in 2000 905
Engineering 39 1 40
Environmental 20 12 32
Conservation 27 2,548 141 - 2,716
Facilities/Cleaning 40 162 202 incl in facilities calculation
Security 125 125 incl in facilities calculation
Misc Other 314 421 735
Tree Trimming 687 1,334 187 352 2,560
Misc Contract Svcs 1,606.0 1,606
8,016
10,027
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
38 List of professional services purchased by major area, e.g.
a) Audits and accounting
b) Legal
c) Information systems
See attached.
<PAGE>
<TABLE>
<CAPTION>
BLACKSTONE VALLEY ELECTRIC
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C>
Asplundh Tree Trimming 56,222
Barnes Tree Services Tree Trimming 140,399
Blackstone Valley Security Security Services 0
Clean Harbor Environmental 19,603
Coopers & Lybrand Accounting 34,145
Credit Bureau Collection Fees 20,959
Dickstein, Shapiro & Moris Legal
Financial Collection Collection Fees 1,149
Isaacson, Rosenbaum Legal 743,568
McDermott, Will & Emery Legal 32,578
Northern Tree Service Tree Trimming 491,290
Ocean State Janitorial Cleaning 40,408
Osmose Wood Press Pole Treatment/Inspection 448
Stanley Bleeker, Esq. Legal 0
Tillinghast, Collins & Graham Legal 1,911
(A) Coflax Packing Conservation 1,214
(A) Delta Electric Motor Conservation 639
(A) RISE Conservation 7,690
(A) Slater Dye Works Conservation 17,313
---------------------
1,809,534
=====================
(A) These vendors participated in Eastern Edison's conservation, load,
management programs, management programs.
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16.
Prepared by Michelle Uzzo 12/22/98
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EASTERN EDISON COMPANY
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C> <C>
American Staffing Assoc. Employment 118,240
Asplundh Tree Trimming 919,253
Barnes Tree Service Tree Trimming 140,782
Clean Harbors Environmental
Coopers and Lybrand Accounting 62,883
Duff & Phelps Consulting 40,000
Environmental Protection Service Maintenance 44,555
First Financial Resources Collection Fees 33,933
First Security Services Security
Hanson Police Dept. Police Detail 31,478
J. D. Payroll Services Temp Services
MASS Save Consulting 342,286
McDermott, Will & Emery Legal 1,209,446
Misc. Contract Services* 1,605,966
Misc. Engineering* 38,605
Misc. Legal* 12,155
Miscellaneous* 314,463
Osmose Wood Press Pole Treatment/Inspection
Pembroke Police Dept. Police Detail
R.A. Gill Tree Service Tree Trimming 227,341
R.E. Tilgren Tree Trimming 46,695
Reed, Adami, Kaiser Legal 72,589
Rockland Police Dept. Police Detail 26,218
Service Master Maintenance 29,796
State Street Bank & Trust Trustee/Administrative Fee
Suburban Contract Cleaning
Town of Bridgewater Police Detail
Town of Easton Police Detail 56,526
Town of Norwell Police Detail 42,745
Town of Scituate Police Detail
Town of Stoughton Police Detail
(A) Conservation Services Group Conservation 361,903
(A) Demand Mgmt Conservation
(A) Energie Innovation Inc. Conservation 84,095
(A) Energy Conservation Conservation 123,124
(A) Energy Federation Conservation 306,904
(A) Fall Realty & Harris Energy Conservation 38,353
(A) Fleet Bank Conservation 28,182
(A) Harris Energy Systems Conservation 489,801
(A) J&R Industrial Wiring Conservation 206,124
(A) Main Street Textiles Conservation 133,990
(A) MUPAC Corp & Harris Energy Conservation 26,114
(A) National Resource Mgmt. Conservation 375,923
(A) Relocation Resources, Inc. Conservation 61,985
(A) Shews Supermarkets Inc. Conservation 168,265
(A) Star Market & Harris Energy Conservation 31,080
(A) Stop & Shop Supermarket Co. Conservation 49,799
(A) Ware Rite & Harris Energy Conservation 32,759
(A) Whaling Mfg. Co., Inc. Conservation 29,235
-------------------
7,963,604
===================
* Aggregate amounts to any one entity less than $25,000 have been
accumulated in this description.
(A) These vendors participated in Eastern Edison's conservation, load,
management programs; management programs.
NOTE: The source for this information was found on o&m codes 9, 10, 11 & 12.
Prepared by Michelle Uzzo 12/22/98
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEWPORT ELECTRIC CORPORATION
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C>
Barnes Tree Services Tree Trimming 187,208
Clean Harbor Environmental 11,989
Coopers & Lybrand Accounting 30,982
Credit Info Collection Fees 12,118
McDermott, Will & Emery Legal 16,808
Morgan, Brown & Joy Legal 340
RISE Conservation 141,057
Tillinghast, Collins & Graham Legal 45,587
-----------------
446,062
=================
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA SERVICE CORP.
PROFESSIONAL SERVICES
(Account # 923)
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C>
McDermott, Will & Emery Legal 359,773
First Security Services Security 124,975
Contract Cleaning Collaborative Cleaning
Eastern Edison Company Arborist/Technical Trainers 351,846
Salomon Brothers Inc. Investment Services 107,986
Media Concepts Printing Services 114,897
Norfolk Data Data Processing Time Cards
Cambridge Reports, Inc. Customer Services 70,560
J. Flanagan & Co. Legislative Activity 48,000
DRI McGraw-Hill
Newport Electric Corp. Arborist/Technical Trainers
Twenty First Century
AUC Management Consultants Consulting
Misc. Legal * 82,677
Misc. Accounting * 68,988
Misc. EDP * 41,871
Misc. Building & Maintenance* 162,203
Other * 421,494
Misc. Engineering * 768
-----------------
1,956,038
=================
* Payments made to payee is less than $100,000
Amounts in Bold print are estimates based on the average of 1996 & 1997.
Prepared by Michelle Uzzo 12/22/98 a:\profsvs
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
REGULATORY EXPENSES
in $000
1997 1997
EUA NEES
<S> <C> <C> <C>
Addit. data req #42 1,002 FERC acct #928 4,008
Assessments 739
Filings and misc. 263
Total 1,002
Savings on filings and misc. 20%
Savings in 1997 53
Escalation to 2000 1.09
Savings in 2000 57
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
42 Summary of regulatory expenses.
1997 Newport Blackstone Eastern Total
---- ------- ---------- ------- -----
PUC Assessment 119,983 267,118 387,101
DTE Assessment 351,663 351,663
Tariff Filings & Misc. 57,258 144,113 61,899 263,270
------- ------- ------ -------
177,241 411,231 413,562 1,002,034
<PAGE>
<TABLE>
<CAPTION>
Cost to Achieve
in $000
Total Basis for Cost Estimate
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Transaction Costs
Bankers fees 7,500 Estimate from NEES and EUA
Legal fees 3,500 Estimate for NEES and EUA
D&O liability tail coverage 400 1.5 times EUA's current annual D&O liability premium
Total Transaction Costs 11,400
- ----------------------------------------------------------------------------------------------------------------------------------
Personnel Costs
Separation/Retention 35,150
Relocation 2,750 Cost equals 90 employees required to relocate @ $25,000 per employee; also
includes $500,000 miscellaneous
Retraining 1,950 Cost includes:
Customer service training: 100 employees x 4 weeks @ $1,000 per week ($400,000)
Meter reader training: 50 employees x 1 week @ $1,000 per week ((50,000)
Transmission and distribution training: 200 employees x 3 weeks @ $1,500 per
week ($900,000)
Administrative functions training: 100 employees x 4 weeks @ $1,500 per week
($600,000)
General reorientation 250 Cost to train 500 employees x 2 days @ $250 per day ($250,000)
Total Personnel Costs 40,100
- ----------------------------------------------------------------------------------------------------------------------------------
Transition Costs
Internal Support 810 Cost equals 15 employees x 9 months @ $6,000 per month ($810,000)
No cost shown 35 employees working on transition in addition to regular workload
Outside Support 2,000 Cost for organizational and change management consultants and other outside
support
Communications 500 Costs for both internal and external communication
Facilities Consolidation 1,000 Estimate based on other transactions
Other 250 Cost of changing corporate signage, stationary, etc.
Total Transition Costs 4,560
- ----------------------------------------------------------------------------------------------------------------------------------
Information Systems
Systems Integration and Data 6,600 Cost of application integration and data conversion; cost to close one data
center
Center Consolidation
Meter Reading Hardware 600 Cost to outfit EUA meter readers with 55 new ITRON devices
Telecommunications Costs 350 Cost to connect telecommunications networks; reconfigure and reprogram customer
service center switch
Total Information Systems Costs 7,550
- ----------------------------------------------------------------------------------------------------------------------------------
Total Cost to Achieve 63,610
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D&O Tail Coverage
Conversation with Diane Kenney
Coverage Premiums
EUA in Millions in Thousands
<S> <C> <C>
Policy #1 25 232
Policy #2 10 47
35 279
Budget for tail coverage 150%
419
Cost to achieve 400
</TABLE>
<PAGE>
Hoffman, David
- ------------------------------------------------------------------------------
From: Michael J. Hirsh [[email protected]]
Sent: Monday, April 12,1999 5:49 PM
To: [email protected]
Subject: EUA-side transaction costs
David-
Following up on our conversation today, our transaction costs include the
following:
Banker fees$4.2 million (per contract)
Legal $1.6 million actual + est.
($.535 billed through Feb, assume $.3 added through April
and $.1/mo
Thanks.
MJH
<PAGE>
<TABLE>
Exhibit DJH-2
Miscellaneous
MODEL INPUTS
- --------------------------------------
Escalation rate 3%
- --------------------------------------
- --------------------------------------
% labor capitalized
A&G 0%
Customer 0%
T&D 35%
- --------------------------------------
- --------------------------------------
Benefits adder 32.63%
for EUA
- --------------------------------------
<S> <C> <C> <C> <C> <C>
EUA (EE)
% cap % b-t cost % a-t cost wacc
- ---------------------------
Revenue equirement ltd 45.5% 7.6% 7.6% 3.5%
Rate ps 5.5% 9.8% 16.3% 0.9%
cse 49.0% 11.5% 19.2% 9.4%
Non-IS(30 yr) 13.5% 13.7%
IS (5 yr) 28.6%
- ---------------------------
NEES(MECo)
% cap % b-t cost % a-t cost wacc
ltd 44.0% 7.5% 7.5% 3.3%
- ---------------------------
Fixed Charge Rate ps 5.9% 6.3% 10.5% 0.6%
on EUA inventory 13.7% cse 50.1% 11.0% 18.3% 9.2%
- ---------------------------
13.1%
Depreciation on distribution plant x land
depr ave plant % yrs
MECo 47,760 1,466,280 3.26% 30.7
NECo 17,744 543,775 3.26% 30.6
EE 9,139 213,037 4.29% 23.3
BV 4,067 98,925 4.11% 24.3
Average 78,710 2,322,016 3.39% 29.5
NEES 2,010,055 87%
EUA 311,961 13%
2,322,016
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
ADDRL #21
N21 % of employee benefits, taxes and unproductive time, i.e.,
vacations, holidays, sick, jury duty. (Benefits & Unproductive /
Productive Wages).
<S> <C>
Blackstone Valley 54.24%
Eastern Edison 53.64%
Newport Electric 61.91%
EUA Service Corp 52.91%
<S> <C> <C>
% of payroll charged to O&M and to Capital O&M Capital
Blackstone Valley 23.7% 76.3%
Eastern Edison 26.4% 73.6%
Newport Electric 22.5% 77.5%
EUA Service Corporation wages billed to companies
Blackstone Valley 95.3% 4.7%
Eastern Edison 92.6% 7.4%
Newport Electric 94.6% 5.4%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Capital Payroll by Function
Payroll Capital Percent
Total Payroll To Capital
<S> <C> <C> <C> <C>
Total A&G 31,138,865 1,416,698 (Note 1) 4.55%
Total Retail Svcs 11,567,105 11,327 0.10%
Customer Service
Northboro
Inquiry 6,533,923 0 0.00%
Meters 1,445,504 16,713 1.16%
Collections 460,700 0 0.00%
Cust Ld Analysis 464,638 0 0.00%
--------- ------
8,904,765 16,713 0.19%
Providence
Inquiry 3,531,849 0 0.00%
Meter Read 2,648,213 0 0.00%
Meter OPs 1,378,950 302,358 21.93%
--------- -------
7,117,580 302,358 4.25%
MValley
Inquiry 975,652 0 0.00%
Meter Read 2,121,637 0 0.00%
Meter OPs 1,082,295 138,419 12.79%
--------- -------
4,179,584 138,419 3.31%
North Shore
Inquiry 362,948 0 0.00%
Meter Read 2,253,417 0 0.00%
Meter OPs 907,277 106,033 11.69%
--------- -------
3,523,642 106,033 3.01%
=========
M Valley/ N Shore 7,703,228 244,452 3.17%
West
Inquiry 222,012 0 0.00%
Meter Read 1,174,272 0 0.00%
Meter OPs 621,829 10,811 1.74%
--------- ------
2,018,113 10,811 0.54%
Central
Inquiry 468,606 0 0.00%
Meter Read 1,519,383 0 0.00%
Meter OPs 722,902 61,649 8.52%
--------- ------
2,578,891 61,649 2.39%
=========
Central/West 4,597,004 72,460 1.58%
Southeast
Inquiry 614,464 0 0.00%
Meter Read 1,453,783 0 0.00%
Meter OPs 634,979 27,813 4.38%
--------- ------
2,573,226 27,813 1.08%
Management 221,586 0 0.00%
Total Customer Service 30,373,079 663,796 2.19%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAPITAL PAYROLL BY FUNCTION
Payroll Capital Percent
Total Payroll To Capital
Operations (Note A)
<S> <C> <C> <C>
Engineering 7,133,255 1,883,343 26.40%
Dispatch 3,156,387 4,485 0.14%
Const Svcs 18,732,509 12,200,687 65.13%
T&D Svcs 6,910,541 901,301 13.04%
Env/Safety 768,947 9,269 1.21%
MValley/Gseco 15,120,701 4,519,335 29.89%
North Shore 10,961,770 3,325,721 30.34%
West 7,769,538 2,259,936 29.09%
Central 16,202,800 4,890,090 30.18%
Southeast 14,412,473 4,399,649 30.53%
Providence 18,495,146 5,927,166 32.05%
Mgmt 854,059 0 0.00%
------- -
Total Operations 120,318,126 40,320,982 33.51%
Executive 1,799,736 0 0.00%
Total Wires 149,648,046 40,996,105 27.40%
Wires plus A&G 181,215,151 40,007,432 25.44%
Note A
Detail costs excludes the following:
Stores (district level) 3,823,817 42,819 1.12%
Transportation (T&D Sv) 2,774,631 44,052 1.59%
Note 1 A&G Capital payroll includes A&G credit of $1,409,148
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
This Report Is:
Name of Respondent (1) [x] An Original Date of Report Year of Report
Massachusetts Electric Company (2) [ ] A Resubmisson (Mo, Da, Yr) Dec. 31, 1997
- ----------------------------------------------------------------------------------------------------------------------------------
GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE
- ----------------------------------------------------------------------------------------------------------------------------------
1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds
and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the
to cover, (b) the general procedure for determining the amount provisions of Electric Plant Instructions 3(17) of the
capitalized, (c) the method of distribution to constrution U.S. of A.
tion jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used,
types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computa-
different types of construction, and (f) whether the overhead tions below in a manner that clearly indicates the amount
is directly or indirectly assigned. of reduction in the gross rate for tax effects.
- ----------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
---------------------------------------------------------------------------------
For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average
rate earned during the preceding three years.
- ----------------------------------------------------------------------------------------------------------------------------------
1. Components of Formula (Derived from actual book balances and actual cost rates):
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization Cost Rate
Line Title Amount Ratio (Percent) Percentage
No. (a) (b) (c) (d)
<S> <C> <C> <C> <C> <C> <C>
(1) Average Short-Term Debt S $29,054,000
(2) Short-Term Interest s 5.63%
(3) Long-Term Debt D $375,000,000 44.01% d 7.46%
(4) Preferred Stock P $50,000,000 5.87% p 6.30%
(5) Common Equity C $427,061,000 50.12% c 11.00%
(6) Total Capitalization $852,061,000 100%
(7) Average Construction
Work in Progress Balance W $17,700,000
- ----------------------------------------------------------------------------------------------------------------------------------
2. Gross Rate for Borrowed Funds S D S
s(--) + d ( -- ) (1---) 5.63%
W D+P+C W
- ----------------------------------------------------------------------------------------------------------------------------------
3. Rate for Other Funds
S P C
[ 1 - -- ] [ p(-- -) + c(--) ] 0
W D+P+C D+P+C
- ----------------------------------------------------------------------------------------------------------------------------------
4. Weighted Average Rate Actually Used for the Year:
a. Rate for Borrowed Funds - 5.71%
b. Rate for Other Funds - 0
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
This Report Is: Date of Report
Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report
Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------------
GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE
- ---------------------------------------------------------------------------------------------------------------------------------
1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds
and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the
to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the
amount capitalized, (c) the method of distribution to construction U.S. of A.
jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used,
types of construction, (e) basis of differentiation in rates for show the appropriate tax effect adjustment to the computations
different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount
is directly or indirectly assigned. of reduction in the gross rate for tax effects.
- ---------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
---------------------------------------------------------------------------------
For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average
rate earned during the preceding three years.
- ---------------------------------------------------------------------------------------------------------------------------------
1. Components of Formula (Derived from actual book balances and actual cost rates):
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization Cost Rate
Line Title Amount Ratio (Percent) Percentage
No. (a) (b) (c) (d)
<S> <C> <C> <C> <C> <C>
(1) Average Short-Term Debt S $5,117,538
(2) Short-Term Interest s 6.58%
(3) Long-Term Debt D $223,000,000 45.48% d 7.62%
(4) Preferred Stock P $27,034,771 5.51% p 9.83%
(5) Common Equity C $240,213,303 49.0% c 11.50%
(6) Total Capitalization $490,248,074 100%
(7) Average Construction
Work in Progress Balance W $4,399,855
- ----------------------------------------------------------------------------------------------------------------------------------
2. Gross Rate for Borrowed Funds S D S
s(--) + d(--) (1---) 6.58%
W D+P+C W
- ----------------------------------------------------------------------------------------------------------------------------------
3. Rate for Other Funds
S P C
[ 1 - -- ] [ p(-- -) + c(--) ] 0
W D+P+C D+P+C
- ----------------------------------------------------------------------------------------------------------------------------------
4. Weighted Average Rate Actually Used for the Year:
a. Rate for Borrowed Funds - 6.58%
b. Rate for Other Funds -
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
This Report Is: Date of Report
Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report
Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------------
GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE
- ---------------------------------------------------------------------------------------------------------------------------------
1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds
and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the
to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the
amount capitalized, (c) the method of distribution to construction U.S. of A.
jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used,
types of construction, (e) basis of differentiation in rates for show the appropriate tax effect adjustment to the computations
different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount
is directly or indirectly assigned. of reduction in the gross rate for tax effects.
- ---------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
---------------------------------------------------------------------------------
For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average
rate earned during the preceding three years.
- ---------------------------------------------------------------------------------------------------------------------------------
1. Components of Formula (Derived from actual book balances and actual cost rates):
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization Cost Rate
Line Title Amount Ratio (Percent) Percentage
No. (a) (b) (c) (d)
<S> <C> <C> <C> <C> <C>
(1) Average Short-Term Debt S $3,501,308
(2) Short-Term Interest s 7.11%
(3) Long-Term Debt D $36,500,000 46.29% d 9.35%
(4) Preferred Stock P $6,129,500 7.77% p 4.81%
(5) Common Equity C $36,232,083 45.94% c 11.43%
(6) Total Capitalization $78,861,583 100%
(7) Average Construction
Work in Progress Balance W $1,965,253
- ----------------------------------------------------------------------------------------------------------------------------------
2. Gross Rate for Borrowed Funds S D S
s(--) + d(--) (1---) 7.11%
W D+P+C W
- ----------------------------------------------------------------------------------------------------------------------------------
3. Rate for Other Funds
S P C
[ 1 - -- ] [ p(-- -) + c(--) ] 0
W D+P+C D+P+C
- ----------------------------------------------------------------------------------------------------------------------------------
4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 7.11% b. Rate
for Other Funds - 0
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
3. Stock-based compensation
At December 31, 1997, NEES has three stock-based compensation plans and measures its compensation cost for those plans using
the method of accounting prescribed by Accounting Principles Board Opinion No. 25. Accounting for Stock Issued to Employees, and
related interpretations. The compensation cost that has been charged against income for these plans was $3.3 million, $3.7 million
and $1.6 million for 1997, 1996, and 1995, respectively. If compensation cost for stock-based compensation had been accounted for
under Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the 1997 cost figures shown
above would have been slightly smaller.
Total income taxes in the statements of consolidated income are as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Income taxes charged to operations $152,024 $139,199 $128,340
Income taxes charged to "Other income" (7,268) (3.018) 762
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Current income taxes $175,934 $166,509 $105,046
Deferred income taxes (29,260) (28,652) 25,578
Investment tax credits, net (1,918) (1,676) (1,522)
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes, as shown above, consist of federal and state components as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Federal income taxes $118,317 $111,573 $103,503
State income taxes 26,439 24,608 25,599
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
Investment tax credits of subsidiaries are deferred and amortized over the estimated lives of the property giving rise to the
credits. Although investment tax credits were generally eliminated by the 1986 tax legislation, additional carryforward amounts
continue to be recognized.
With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for
temporary book/tax differences.
Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The
reasons for the differences are as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Computed rate at statutory rate $131,989 $123,053 $119,892
Increases (reductions) in tax resulting from
Reversal of deferred taxes recorded at a higher rate (2,216) (2,175) (3,306)
Amortization of investment tax credits (4,469) (4,347) (4,443)
State income tax, net of federal income tax benefit 17,185 15,995 16,639
All other differences 2,267 3,655 320
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
Percentage of employee benefits, taxes as a percentage of total wages.
Company Percentage
<S> <C>
Blackstone Valley Electric Co. 30.45%
Eastern Edison Co. 31.74%
Newport Electric Corp. 38.16%
EUA Service Corp. 32.75%
Composite Percentage of employee benefits, taxes as a percentage of total wages for companies listed above
Composite
Description Amount Percentage
<S> <C> <C>
Taxes & Benefits $16,030,158.00
Total Labor $49,132,790.00 32.63%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Com Energy 1997 O&M in $000
Com Elec Cambr Elec Total Elec Com Gas Total
<S> <C> <C> <C>
transmission 6,667 5,612 12,279
distribution 25,239 4,085 29,324
customer accounts 15,579 2,197 17,776
csi and sales 7,639 1,760 9,399
a&g(not adj.) 40,763 12,323 53,086 30,919
Total O&M 95,887 25,977 121,864 30,919 152,783
DSM expenditures 5,500 5,500
Net O&M 116,364 147,283
customers in 000 322.3 44.9 367.2
distribution cap. additions in millions 18.4 3.5 21.9
EUA 1997 O&M in $000
Eastern Blackstone Newport
Edison Valley Electric Total
transmission 529 616 282 1,427
distribution 16,149 6,532 3,968 26,649
customer accounts 6,779 3,228 1,107 11,114
csi and sales 7,045 3,300 1,547 11,892
a&g (not adj.) 16,417 9,241 5,429 31,087
Total O&M 46,919 22,917 12,333 82,169
DSM expenditures 5,000
Net O&M 77,169
customers in 000 190.3 90.3 35.0 315.6
distribution cap. additions in millions 9.5 3.2 2.8 15.5
EUA 77,169 EUA 77,169
COM electric 116,364 COM total 147,283
% 66% % 52%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BEC Com Pre-Merger Savings Post-Merger
<S> <C> <C> <C> <C> <C> <C>
1/1/2000 Staffing 2,230 1,108 3,338 362 2,976
Customers in 000 670 370 1,040 1,040
Employees per 000 Customers 3.3 3.0 3.2 2.9
Incremental staffing to BEC 746 33%
Incremental customers to BEC 370 55%
NEES EUA Pre-Merger Savings Post-Merger
1/1/2000 Staffing 3,240 869 4,109 234 3,875
Customers in 000 1,340 320 1,660 1,660
Employees per 000 Customers 2.4 2.7 2.5 2.3
Incremental staffing to NEES 635 20%
Incremental customers to NEES 320 24%
1997 Ave. Customers (FERC #1)
Boston Edison 670 Com Elec 322
Cam Elec 45
COM Total 367
Com Gas 237 SEC 10-K
Mass Elec 960 Eastern 190
Narr Elec 331 Blackstone 90
Granite State 36 Newport 35
Nantucket 10 EUA Total 316
NEES Total 1,337
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
M.D.T.E. Docket No. 99-_____
Exhibit DJH-3
Exhibit DJH-3
Supporting Working Papers
(Confidential)
<PAGE>
AGREEMENT AND PLAN OF MERGER
and CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
Exhibit I
[Map Reflecting the NEES and EUA
Direct Retail Service Areas
and Transmission Networks]
<PAGE>
AGREEMENT AND PLAN OF MERGER
and CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
TABLE OF CONTENTS
AGREEMENT AND PLAN OF MERGER...................................................1
CONSENT AGREEMENT..............................................................2
<PAGE>
Tab 1
AGREEMENT AND PLAN OF MERGER
dated as of February 1, 1999
by and among
NEW ENGLAND ELECTRIC SYSTEM,
RESEARCH DRIVE LLC
and
EASTERN UTILITIES ASSOCIATES
<PAGE>
TABLE OF CONTENTS
Page
No.
ARTICLE I
THE MERGER......................................................... 1
1.01 The Merger......................................................... 1
1.02 Effective Time..................................................... 1
1.03 Effects of the Merger.............................................. 2
ARTICLE II
CONVERSION OF SHARES............................................... 2
2.01 Conversion of Capital Stock........................................ 2
2.02 Surrender of Shares................................................ 3
2.03 Withholding Rights................................................. 4
ARTICLE III
THE CLOSING........................................................ 4
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5
4.01 Organization and Qualification..................................... 5
4.02 Capital Stock...................................................... 6
4.03 Authority.......................................................... 7
4.04 Non-Contravention; Approvals and Consents.......................... 7
4.05 SEC Reports, Financial Statements and Utility Reports.............. 8
4.06 Absence of Certain Changes or Events............................... 9
4.07 Legal Proceedings.................................................. 9
4.08 Information Supplied............................................... 9
4.09 Compliance......................................................... 10
4.10 Taxes.............................................................. 10
4.11 Employee Benefit Plans; ERISA...................................... 12
4.12 Labor Matters...................................................... 14
4.13 Environmental Matters.............................................. 15
4.14 Regulation as a Utility............................................ 17
4.15 Insurance.......................................................... 17
4.16 Nuclear Facilities................................................. 18
4.17 Vote Required...................................................... 18
4.18 Opinion of Financial Advisor....................................... 18
-i-
<PAGE>
Page
No.
4.19 Ownership of NEES Common Shares.................................... 18
4.20 State Anti-Takeover Statutes....................................... 18
4.21 Year 2000.......................................................... 19
4.22 EUA Associates..................................................... 19
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES............................. 19
5.01 Organization and Qualification..................................... 19
5.02 Authority.......................................................... 20
5.03 Capital Stock...................................................... 20
5.04 Non-Contravention; Approvals and Consents.......................... 20
5.05 Information Supplied............................................... 21
5.06 Compliance......................................................... 21
5.07 Financing.......................................................... 22
5.08 No Vote Required................................................... 22
5.09 Ownership of EUA Shares............................................ 22
5.10 Merger with The National Grid Group plc............................ 22
ARTICLE VI
COVENANTS................................................ 22
6.01 Covenants of EUA................................................... 22
6.02 Covenants of NEES.................................................. 28
6.03 Additional Covenants by NEES and EUA............................... 29
ARTICLE VII
ADDITIONAL AGREEMENTS.................................... 30
7.01 Access to Information.............................................. 30
7.02 Proxy Statement.................................................... 31
7.03 Approval of Shareholders........................................... 31
7.04 Regulatory and Other Approvals..................................... 31
7.05 Employee Benefit Plans............................................. 32
7.06 Labor Agreements and Workforce Matters............................. 34
7.07 Post Merger Operations............................................. 34
7.08 No Solicitations................................................... 35
7.09 Directors' and Officers' Indemnification and Insurance............. 36
7.10 Expenses........................................................... 37
7.11 Brokers or Finders................................................. 37
7.12 Anti-Takeover Statutes............................................. 38
7.13 Public Announcements............................................... 38
-ii-
<PAGE>
Page
No.
7.14 Restructuring of the Merger........................................ 38
ARTICLE VIII
CONDITIONS......................................................... 39
8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39
8.03 Conditions to Obligation of EUA to Effect the Merger............... 40
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER.................................. 41
9.01 Termination........................................................ 41
9.02 Effect of Termination.............................................. 43
9.03 Termination Fees................................................... 43
9.04 Amendment.......................................................... 44
9.05 Waiver............................................................. 44
ARTICLE X
GENERAL PROVISIONS................................................. 44
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements......................................................... 44
10.02 Notices............................................................ 44
10.03 Entire Agreement; Incorporation of Exhibits........................ 46
10.04 No Third Party Beneficiary......................................... 46
10.05 No Assignment; Binding Effect...................................... 46
10.06 Headings........................................................... 47
10.07 Invalid Provisions................................................. 47
10.08 Governing Law...................................................... 47
10.09 Enforcement of Agreement........................................... 47
10.10 Certain Definitions................................................ 47
10.11 Counterparts....................................................... 48
10.12 WAIVER OF JURY TRIAL............................................... 48
-iii-
<PAGE>
GLOSSARY OF DEFINED TERMS
The following terms, when used in this Agreement, have the meanings
ascribed to them in the corresponding Sections of this Agreement listed below:
"1935 Act" -- Section 4.05(b)
"Adjustment Date" -- Section 2.01(c)
"Affected Employees" -- Section 7.05(a)
"affiliate" -- Section 10.11(a)
"Agreement" -- Preamble
"Alternative Proposal" -- Section 7.08
"beneficially" -- Section 10.10(b)
"business day" -- Section 10.10(c)
"Canceled Shares" -- Section 2.02(b)
"Certificates" -- Section 2.02(b)
"Closing" -- Article III
"Closing Agreement" -- Section 4.10(j)
"Closing Date" -- Article III
"Code" -- Section 2.03
"Confidentiality Agreement" -- Section 7.01
"Constituent Entities" -- Section 1.01
"Contracts" -- Section 4.04(a)
"control," "controlling,"
"controlled by" and
"under common control with" -- Section 10.10(a)
"DOE" -- Section 4.05(b)
"Effective Time" -- Section 1.02
"Environmental Claim" -- Section 4.13(f)(i)
"Environmental Laws" -- Section 4.13(f)(ii)
"Environmental Permits" -- Section 4.13(b)
"ERISA" -- Section 4.11(a)
"ERISA Affiliate" -- Section 4.11(c)
"EUA" -- Preamble
"EUA Associates" -- Section 4.01(b)
"EUA Employee Agreements" -- Section 7.05(d)(ii)
"EUA Executives" -- Section 7.05(d)(ii)
"EUA Shares" -- Preamble
"EUA Disclosure Letter" -- Section 4.01(a)
"EUA Employee Benefit Plans" -- Section 4.11(a)
"EUA Financial Statements" -- Section 4.05(a)
"EUA Nuclear Facilities" -- Section 4.16
"EUA Material Adverse Effect" -- Section 4.01(a)
"EUA Required Consents" -- Section 4.04(a)
"EUA Required Statutory Approvals" -- Section 4.04(b)
"EUA SEC Reports" -- Section 4.05(a)
-iv-
<PAGE>
"EUA Shareholders' Approval" -- Section 7.03
"EUA Shareholders' Meeting" -- Section 7.03
"EUA Significant Subsidiary" -- Section 7.08
"EUA Shares" -- Preamble
"EUA Trust Agreement" -- Section 1.03
"EUA Voting Debt -- Section 4.02(d)
"Evaluation Material" -- Section 7.01(a)
"Exchange Act" -- Section 4.05(a)
"Exchange Fund" -- Section 2.02(a)
"Extended Termination Date" -- Section 9.01(b)
"FCC" -- Section 4.05(b)
"FERC" -- Section 4.05(b)
"Final Order" -- Section 8.01(d)
"Governmental Authority" -- Section 4.04(a)
"Hazardous Materials" -- Section 4.13(f)(iii)
"HSR Act" -- Section 7.04(a)
"Indemnified Liabilities" -- Section 7.09(a)
"Indemnified Party" -- Section 7.09(a)
"Indemnified Parties" -- Section 7.09(a)
"Information Systems" -- Section 4.21
"Initial Termination Date" -- Section 9.01(b)
"IRS" -- Section 4.10(m)
"knowledge" -- Section 10.11(d)
"laws" -- Section 4.04(a)
"Lien" -- Section 4.02(b)
"LLC" -- Preamble
"Massachusetts Secretary" -- Section 1.02
"Merger" -- Preamble
"Merger Consideration" -- Section 2.01(b)(ii)
"MGL" -- Section 1.01
"National Grid Group" -- Section 5.10
"National Grid Merger Agreement" -- Section 5.10
"NEES" -- Preamble
"NEES Disclosure Letter" -- Section 5.03
"NEES Material Adverse Effect" -- Section 5.01
"NEES-EUA Regulatory Approvals" -- Section 7.04(b)
"NEES-EUA Regulatory Proceedings" -- Section 7.04(c)
"NEES Required Consents" -- Section 5.04(a)
"NEES Required Statutory Approvals" -- Section 5.04(b)
"NEES-NGG Regulatory Approvals" -- Section 7.04(c)
"NEES-NGG Regulatory Proceedings" -- Section 7.04(c)
"NEES-NGG Required Statutory Approvals"-- Section 7.04
"NEES-NGG Transactions" -- Section 7.04
"NEES Shares" -- Section 5.03
-v-
<PAGE>
"NEES Trust Agreement" -- Section 5.01
"NGG Circular" -- Section 7.02
"NRC" -- Section 4.05(b)
"Options" -- Section 4.02(a)
"orders" -- Section 4.04(a)
"Out-of-Pocket Expenses" -- Section 9.03(a)
"Paying Agent" -- Section 2.02(a)
"PBGC" -- Section 4.11(g)
"person" -- Section 10.11(e)
"Per Share Amount" -- Section 2.01(b)(ii)
"Post Closing Plans" -- Section 7.05(b)
"Proxy Statement" -- Section 4.08(a)
"Release" -- Section 4.13(f)(iv)
"Representatives" -- Section 10.11(f)
"SEC" -- Section 4.05(a)
"Securities Act" -- Section 4.05(a)
"Subsidiary" -- Section 10.11(g)
"Surviving Entity" -- Section 1.01
"Tax Ruling" -- Section 4.10(j)
"Taxes" -- Section 4.10
"Tax Return" -- Section 4.10
"US GAAP" -- Section 4.05(a)
"Yankee Companies" -- Section 4.16
"Y2K Consultant" -- Section 6.01(o)
-vi-
<PAGE>
This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this
"Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM,
a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a
Massachusetts limited liability company which is directly and indirectly wholly
owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust
("EUA").
WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA
and the members of LLC have each determined that it is advisable and in the best
interests of their respective shareholders and members to consummate, and have
approved, the business combination transaction provided for herein in which LLC
would merge with and into EUA, with EUA being the surviving entity (the
"Merger"), pursuant to the terms and conditions of this Agreement, as a result
of which NEES will own, directly or indirectly, all of the issued and
outstanding common shares of EUA (the "EUA Shares");
WHEREAS, NEES, LLC and EUA desire to make certain representations,
warranties and agreements in connection with the Merger and also to prescribe
various conditions to the Merger;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements set forth in this Agreement, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereto hereby agree as follows:
ARTICLE I
THE MERGER
1.01 The Merger. Upon the terms and subject to the conditions of this
Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be
merged with and into EUA in accordance with Section 2 of Chapter 182 and Section
59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective
Time, the separate existence of LLC shall cease and EUA shall continue as the
surviving entity in the Merger. EUA, after the Effective Time, is sometimes
referred to herein as the "Surviving Entity" and EUA and LLC are sometimes
referred to herein as the "Constituent Entities". The effect and consequences of
the Merger shall be as set forth in Article II.
1.02 Effective Time. Subject to the provisions of this Agreement, on
the Closing Date (as defined in Article III), a certificate of merger shall be
executed and filed by EUA and LLC with the Secretary of the Commonwealth of
Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective
at the time of the filing of the certificate of merger relating to the Merger
with the Massachusetts Secretary, or at such later time as is specified in the
certificate of merger (such date and time being referred to herein as the
"Effective Time").
<PAGE>
1.03 Effects of the Merger. At the Effective Time, the Agreement and
Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately
prior to the Effective Time shall be the agreement and declaration of trust of
the Surviving Entity, until thereafter amended as provided by law and such
agreement and declaration of trust. Subject to the foregoing, the additional
effects of the Merger shall be as provided in the applicable provisions of
Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability
Company Act of Massachusetts.
ARTICLE II
CONVERSION OF SHARES
2.01 Conversion of Capital Stock. At the Effective Time, by virtue of
the Merger and without any action on the part of the holder thereof:
(a) Membership Interests of LLC. Each one percent of the issued
and outstanding membership interests in LLC shall be converted into one
transferable certificate of participation or share of the Surviving Entity.
(b) Conversion of EUA Shares.
(i) Cancellation of Treasury Shares and Shares Owned by
NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares
and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as
defined in Section 10.11) of NEES shall be canceled and retired and shall cease
to exist and no cash or other consideration shall be delivered in exchange
therefor.
(ii) Conversion of EUA Shares. Each EUA Share issued and
outstanding immediately prior to the Effective Time (other than shares to be
canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted
in accordance with the provisions of this Section 2.01 into the right to receive
cash in the amount (the "Per Share Amount") of $31.00 as such amount may
hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger
Consideration"), payable, without interest, to the holder of such EUA Share,
upon surrender, in the manner provided in Section 2.02 hereof, of the
certificate formerly evidencing such share.
(c) Adjustment in Amount of Merger Consideration. In the event
that the Closing Date shall not have occurred on or prior to the date that is
the six (6) month anniversary of the date on which EUA Shareholders' Approval is
obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for
each day after the Adjustment Date up to and including the day which is one day
prior to the earlier of the Closing Date and the Extended Termination Date, by
an amount equal to $0.003.
-2-
<PAGE>
2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the
Effective Time, NEES shall designate a bank or trust company reasonably
acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the
holders of EUA Shares in connection with the Merger to receive the funds to
which holders of EUA Shares shall become entitled pursuant to Section
2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or
after the Effective Time, NEES or LLC shall make or cause to be made available
to the Paying Agent immediately available funds in amounts and at the times
necessary for the payment of the Merger Consideration upon surrender of
Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b),
it being understood that any and all interest or other income earned on funds
made available to the Paying Agent pursuant to this Section 2.02(a) shall belong
to and shall be paid (at the time provided for in Section 2.02(e)) as directed
by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be
invested by the Paying Agent as directed by NEES or LLC.
(b) Exchange Procedure. As soon as practicable after the
Effective Time, the Paying Agent shall mail to each holder of record of a
certificate or certificates (the "Certificates") which immediately prior to the
Effective Time represented outstanding EUA Shares (the "Canceled Shares") that
were canceled and became instead the right to receive the Merger Consideration
pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as
NEES and EUA may reasonably agree (which shall specify that delivery shall be
effected, and risk of loss and title to the Certificates shall pass, only upon
actual delivery of the Certificates to the Paying Agent) and (ii) instructions
for effecting the surrender of the Certificates in exchange for the Merger
Consideration. Upon surrender of a Certificate or Certificates to the Paying
Agent for cancellation (or to such other agent or agents as may be appointed by
NEES and are reasonably acceptable to EUA), together with a duly executed letter
of transmittal and such other documents as the Paying Agent shall require, the
holder of such Certificate shall be entitled to receive the Merger Consideration
in exchange for each EUA Share formerly evidenced by such Certificate which such
holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of
a transfer of ownership of Canceled Shares which is not registered in the
transfer records of EUA, the Merger Consideration in respect of such Canceled
Shares may be given to the transferee thereof if the Certificate or Certificates
representing such Canceled Shares is presented to the Paying Agent, accompanied
by all documents required to evidence and effect such transfer and by evidence
satisfactory to the Paying Agent that any applicable stock transfer taxes have
been paid. At any time after the Effective Time, each Certificate shall be
deemed to represent only the right to receive the Merger Consideration subject
to and upon the surrender of such Certificate as contemplated by this Section
2.02. No interest shall be paid or will accrue on the Merger Consideration
payable to holders of Certificates pursuant to Section 2.01(b)(ii).
(c) No Further Ownership Rights in EUA Shares. The Merger
Consideration paid upon the surrender of Certificates in accordance with the
terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective
Time in full satisfaction of all rights pertaining to EUA Shares represented
thereby. From and after the Effective Time, the share transfer books of EUA
shall be closed and there shall be no further registration of transfers thereon
of EUA Shares which were outstanding immediately prior to the Effective Time.
-3-
<PAGE>
If, after the Effective Time, Certificates are presented to NEES for any reason,
they shall be canceled and exchanged as provided in this Section 2.02.
(d) Lost, Stolen or Destroyed Certificates. In the event any
owner of any Certificate shall claim that such Certificate shall have been lost,
stolen or destroyed, upon the making of an affidavit of that fact by the owner
of such Certificate and delivery of that affidavit to the Paying Agent and, if
required by NEES or LLC, the posting by such person of a bond in customary
amount as indemnity against any claim that may be made against NEES, EUA or the
Surviving Entity with respect to such Certificate, the Paying Agent will issue
in exchange for such lost, stolen or destroyed Certificate the Merger
Consideration payable upon due surrender of, and deliverable pursuant to this
Section 2.02 in respect of, EUA Shares to which such Certificate relates.
(e) Termination of Exchange Fund. Any portion of the Exchange
Fund which remains undistributed to the shareholders of EUA for one (1) year
after the Effective Time shall be delivered to the Surviving Entity, upon
demand, and any Shareholders of EUA who have not theretofore complied with this
Article II shall thereafter look only to the Surviving Entity (subject to
abandoned property, escheat and other similar laws) as general creditors for
payment of their claim for the Merger Consideration payable upon due surrender
of the Certificates held by them. None of NEES, LLC or the Surviving Entity
shall be liable to any former holder of EUA Shares for the Merger Consideration
delivered to a public official pursuant to any applicable abandoned property,
escheat or similar law.
2.03 Withholding Rights. Each of the Surviving Entity and NEES shall
be entitled to deduct and withhold from the consideration otherwise payable
pursuant to this Agreement to any holder of EUA Shares such amounts as it is
required to deduct and withhold with respect to the making of such payment under
the Internal Revenue Code of 1986, as amended (the "Code"), or any other
provision of state, local or foreign tax law. To the extent that amounts are so
withheld by the Surviving Entity or NEES, as the case may be, such withheld
amounts shall be treated for all purposes of this Agreement as having been paid
to the holder of EUA Shares in respect of which such deduction and withholding
was made by the Surviving Entity or NEES, as the case may be.
ARTICLE III
THE CLOSING
The closing of the Merger and other transactions contemplated hereby
(the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher
& Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local
time, on the second business day following satisfaction or waiver (where
applicable) of the conditions set forth in Article VIII (other than those
conditions that by their nature are to be fulfilled at the Closing, but subject
to the fulfillment or waiver of such conditions), unless another date, time or
place is agreed to in writing by the parties hereto (the "Closing Date").
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA
EUA represents and warrants to NEES and LLC as follows:
4.01 Organization and Qualification. (a) EUA is a voluntary
association duly organized, validly existing and in good standing under the laws
of the Commonwealth of Massachusetts and has full power, authority and legal
right to own its property and assets and to transact the business in which it is
engaged. Each of EUA's Subsidiaries is a corporation duly organized or
incorporated, validly existing and in good standing under the laws of its
jurisdiction of organization or incorporation and has full corporate power and
authority to conduct its business as and to the extent now conducted and to own,
use and lease its assets and properties, except where failure to be so organized
or incorporated, existing and in good standing or to have such power and
authority, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA
Material Adverse Effect" means a material adverse effect on the business,
assets, results of operations, condition (financial or otherwise) or prospects
of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries
is duly qualified, licensed or admitted to do business and is in good standing
in each jurisdiction in which the ownership, use or leasing of its assets and
properties, or the conduct or nature of its business, makes such qualification,
licensing or admission necessary, except where failure to be so qualified,
licensed or admitted and in good standing, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect. Section
4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA
concurrently with the execution and delivery of this Agreement (the "EUA
Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or
organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized
capital stock, (iii) the number of issued and outstanding shares of capital
stock of such Subsidiary and (iv) the number of shares of such Subsidiary held
of record by EUA. EUA has previously delivered to NEES correct and complete
copies of the EUA Trust Agreement and the certificate or articles of
organization or incorporation and bylaws (or other comparable charter documents)
of its Subsidiaries.
(b) Section 4.01 of the EUA Disclosure Letter sets forth a
description as of the date hereof, of all EUA Associates, including (i) the name
of each such entity and EUA's interest therein and (ii) a brief description of
the principal line or lines of business conducted by each such entity. For
purposes of this Agreement "EUA Associates" shall mean any corporation or other
entity (including partnerships and other business associations) that is not a
Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly
or indirectly, owns an equity interest (other than short-term investments in the
ordinary course of business) if such corporation or other entity (including
partnerships and other business associations) contributes five percent or more
of EUA's consolidated revenues, assets, income or costs.
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4.02 Capital Stock. (a) The authorized equity securities of EUA
consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and
outstanding as of the close of business on January 29, 1999. As of the close of
business on January 29, 1999, no EUA Shares were held in the treasury of EUA.
Since such date there has been no change in the sum of the issued and
outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly
authorized, validly issued, fully paid and nonassessable. Except pursuant to
this Agreement and except as described in Section 4.02 of the EUA Disclosure
Letter, on the date hereof there are no outstanding subscriptions, options,
warrants, rights (including share appreciation rights), preemptive rights or
other contracts, commitments, understandings or arrangements, including any
right of conversion or exchange under any outstanding security, instrument or
agreement (together, "Options"), obligating EUA or any of its Subsidiaries to
issue or sell any shares of equity securities of EUA or to grant, extend or
enter into any Option with respect thereto. The EUA Disclosure Letter sets forth
all capital stock authorized, issued and outstanding at subsidiary levels as of
the close of business on January 29, 1999.
(b) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the
outstanding shares of capital stock of each Subsidiary of EUA are duly
authorized, validly issued, fully paid and nonassessable and are owned,
beneficially and of record, by EUA or a Subsidiary, which is wholly owned,
directly or indirectly, by EUA, free and clear of any liens, claims, mortgages,
encumbrances, pledges, security interests, equities and charges of any kind
(each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date
of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i)
outstanding Options obligating EUA or any of its Subsidiaries to issue or sell
any shares of capital stock of any Subsidiary of EUA or to grant, extend or
enter into any such Option or (ii) voting trusts, proxies or other commitments,
understandings, restrictions or arrangements in favor of any person other than
EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with
respect to the voting of, or the right to participate in, dividends or other
earnings on any capital stock of any Subsidiary of EUA.
(c) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are
no outstanding contractual obligations of EUA or any Subsidiary of EUA to
repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of
any Subsidiary of EUA or to provide funds to, or make any investment (in the
form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or
any other person.
(d) As of the date of this Agreement, no bonds, debentures,
notes or other indebtedness of EUA or any Subsidiary of EUA having the right to
vote (or which are convertible into or exercisable for securities having the
right to vote) (together "EUA Voting Debt") on any matters on which Shareholders
may vote are issued or outstanding nor are there any outstanding Options
obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt
or to grant, extend or enter into any Option with respect thereto.
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4.03 Authority. EUA has full power and authority to enter into this
Agreement, to perform its obligations hereunder and, subject to obtaining EUA
Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required
Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger
and other transactions contemplated hereby. The execution, delivery and
performance of this Agreement by EUA and the consummation by EUA of the Merger
and other transactions contemplated hereby have been duly authorized by all
necessary action on the part of EUA, subject to obtaining EUA Shareholders'
Approval with respect to the consummation of the Merger and the other
transactions contemplated hereby. This Agreement has been duly and validly
executed and delivered by EUA and constitutes a legal, valid and binding
obligation of EUA enforceable against EUA in accordance with its terms, except
as enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
4.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by EUA do not, and the performance by EUA of its
obligations hereunder and the consummation of the Merger and other transactions
contemplated hereby will not, conflict with, result in a violation or breach of,
constitute (with or without notice or lapse of time or both) a default under,
result in or give to any person any right of payment or reimbursement,
termination, cancellation, modification or acceleration of, or result in the
creation or imposition of any Lien upon any of the assets or properties of EUA
or any of its Subsidiaries or any of the terms, conditions or provisions of (i)
the EUA Trust Agreement or the certificates or articles of incorporation or
organization or bylaws (or other comparable charter documents) of EUA's
Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval,
EUA Required Consents, EUA Required Statutory Approvals and the taking of any
other actions described in this Section 4.04, (x) any statute, law, rule,
regulation or ordinance (together, "laws"), or any judgment, decree, order,
writ, permit or license (together, "orders"), of any court, tribunal,
arbitrator, authority, agency, commission, official or other instrumentality of
the United States, any foreign country or any domestic or foreign state, county,
city or other political subdivision (a "Governmental Authority") applicable to
EUA or any of its Subsidiaries or any of their respective assets or properties,
or (y) subject to obtaining the third-party consents set forth in Section 4.04
of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond,
mortgage, security agreement, indenture, license, franchise, permit, concession,
contract, lease or other instrument, obligation or agreement of any kind
(together, "Contracts") to which EUA or any of its Subsidiaries is a party or by
which EUA or any of its Subsidiaries or any of their respective assets or
properties is bound, excluding from the foregoing clauses (x) and (y) such
conflicts, violations, breaches, defaults, payments or reimbursements,
terminations, cancellations, modifications, accelerations and creations and
impositions of Liens which, individually or in the aggregate, could not
reasonably be expected to have an EUA Material Adverse Effect.
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(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by EUA or the consummation by
EUA of the Merger and other transactions contemplated hereby except as described
in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain
could not reasonably be expected to result in an EUA Material Adverse Effect
(the "EUA Required Statutory Approvals," it being understood that references in
this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean
making such declarations, filings or registrations; giving such notices;
obtaining such authorizations, consents or approvals; and having such waiting
periods expire as are necessary to avoid a violation of law).
4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA
delivered to NEES prior to the execution of this Agreement a true and complete
copy of each form, report, schedule, registration statement, registration
exemption, if applicable, definitive proxy statement and other document
(together with all amendments thereof and supplements thereto) filed by EUA or
any of its Subsidiaries with the Securities and Exchange Commission (the "SEC")
under the Securities Act of 1933, as amended, and the rules and regulations
thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as
amended, and the rules and regulations thereunder (the "Exchange Act") since
December 31, 1995 (as such documents have since the time of their filing been
amended or supplemented, the "EUA SEC Reports"), which are all the documents
(other than preliminary materials) that EUA and its Subsidiaries were required
to file with the SEC under the Securities Act and the Exchange Act since such
date. As of their respective dates, EUA SEC Reports (i) complied as to form in
all material respects with the requirements of the Securities Act or the
Exchange Act, as the case may be, and (ii) did not contain any untrue statement
of a material fact or omit to state a material fact required to be stated
therein or necessary in order to make the statements therein, in light of the
circumstances under which they were made, not misleading. Each of the audited
consolidated financial statements and unaudited interim consolidated financial
statements (including, in each case, the notes, if any, thereto) included in EUA
SEC Reports (the "EUA Financial Statements") complied as to form in all material
respects with the published rules and regulations of the SEC with respect
thereto, were prepared in accordance with U.S. generally accepted accounting
principles ("US GAAP") applied on a consistent basis during the periods involved
(except as may be indicated therein or in the notes thereto and except with
respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly
present (subject, in the case of the unaudited interim financial statements, to
normal, recurring year-end audit adjustments (which are not expected to be,
individually or in the aggregate, materially adverse to EUA and its Subsidiaries
taken as a whole)) the consolidated financial position of EUA and its
consolidated subsidiaries as at the respective dates thereof and the
consolidated results of their operations and cash flows for the respective
periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure
Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in
EUA Financial Statements for all periods covered thereby.
(b) All filings (other than immaterial filings) required to be
made by EUA or any of its Subsidiaries since December 31, 1995, under the Public
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Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the
Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state
laws and regulations, have been filed with the SEC, the Federal Energy
Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the
Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission
(the "FCC") or any appropriate state public utility commissions (including,
without limitation, to the extent required, the state public utility regulatory
agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and
Connecticut as the case may be, including all forms, statements, reports,
agreements (oral or written) and all documents, exhibits, amendments and
supplements appertaining thereto, including but not limited to all rates,
tariffs, franchises, service agreements and related documents and all such
filings complied, as of their respective dates, in all material respects with
all applicable requirements of the appropriate statutes and the rules and
regulations thereunder.
4.06 Absence of Certain Changes or Events. Except as set forth in
Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports
filed prior to the date of this Agreement since December 31, 1997, EUA and each
of EUA's Subsidiaries have conducted its business only in the ordinary course of
business consistent with past practice and there has not been, and no fact or
condition exists which, individually or in the aggregate, has or could
reasonably be expected to have an EUA Material Adverse Effect.
4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed
prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure
Letter and except for environmental matters which are governed by Section 4.13,
(i) there are no actions, claims, hearings, suits, arbitrations or proceedings
pending or, to the knowledge of EUA or any of its Subsidiaries, threatened
against, specifically relating to or affecting, and, to the knowledge of EUA or
any of its Subsidiaries, there are no Governmental Authority investigations or
audits pending or threatened against, specifically relating to or affecting, EUA
or any of its Subsidiaries or any of their respective assets and properties
which, individually or in the aggregate, could reasonably be expected to have an
EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is
subject to any order of any Governmental Authority which, individually or in the
aggregate, could reasonably be expected to have an EUA Material Adverse Effect.
4.08 Information Supplied. (a) The proxy statement relating to EUA
Shareholders' Meeting, as amended or supplemented from time to time (as so
amended and supplemented, the "Proxy Statement"), and any other documents to be
filed by EUA with the SEC (including, without limitation, under the 1935 Act) or
any other Governmental Authority in connection with the Merger and other
transactions contemplated hereby will comply as to form in all material respects
with the requirements of the Exchange Act, the Securities Act and the 1935 Act,
as applicable, and will not, on the date of their respective filings or, in the
case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and
at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain
any untrue statement of a material fact or omit to state any material fact
necessary in order to make the statements therein, in light of the circumstances
under which they are made, not misleading.
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(b) Notwithstanding the foregoing provisions of this Section
4.08, no representation or warranty is made by EUA with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by NEES or LLC for inclusion or incorporation by reference therein.
4.09 Compliance. Except as set forth in Section 4.09 of the EUA
Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date
hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the
knowledge of EUA, under investigation with respect to any violation of, or has
been given notice or been charged with any violation of, any law, statute,
order, rule, regulation, ordinance or judgment (including, without limitation,
any applicable environmental law, ordinance or regulation) of any Governmental
Authority, except for possible violations which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as
disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's
Subsidiaries have all permits, licenses, franchises and other governmental
authorizations, consents and approvals necessary to conduct their businesses as
presently conducted except for such failures which could not reasonably be
expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's
Subsidiaries is in breach or violation of, or in default in the performance or
observance of any term or provision of, (i) the EUA Trust Agreement, in the case
of EUA, or articles of incorporation or organization or by-laws, in the case of
EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture,
mortgage, loan agreement, note, lease, bond, license, approval or other
instrument to which it is a party or by which EUA or any Subsidiary of EUA is
bound or to which any of their respective property is subject, except for
possible violations, breaches or defaults which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure
Letter:
(a) Filing of Timely Tax Returns. EUA and each of its
Subsidiaries have timely filed all Tax Returns required to be filed by each of
them under applicable law. All Tax Returns were (and, as to Tax Returns not
filed as of the date hereof, will be) true, complete and correct;
(b) Payment of Taxes. EUA and each of its Subsidiaries have,
within the time and in the manner prescribed by law, paid (and until the Closing
Date will pay within the time and in the manner prescribed by law) all Taxes
that are currently due and payable except for those contested in good faith and
for which adequate reserves have been taken;
(c) Tax Reserves. EUA and its Subsidiaries have established (and
until the Closing Date will maintain) on their books and records adequate
reserves for all Taxes and for any liability for deferred income taxes in
accordance with GAAP;
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(d) Extensions of Time for Filing Tax Returns. Neither EUA nor
any of its Subsidiaries has requested any extension of time within which to file
any Tax Return, which Tax Return has not since been filed;
(e) Waivers of Statute of Limitations. Neither EUA nor any of
its Subsidiaries has in effect any extension, outstanding waivers or comparable
consents regarding the application of the statute of limitations with respect to
any Taxes or Tax Returns;
(f) Expiration of Statute of Limitations. The Tax Returns of
EUA, each of its Subsidiaries and any affiliated, consolidated, combined or
unitary group that includes EUA or any of its Subsidiaries either have been
examined and settled with the appropriate Tax authority or closed by virtue of
the expiration of the applicable statute of limitations for all years through
and including 1993;
(g) Audit, Administrative and Court Proceedings. No audits or
other administrative proceedings or court proceedings are presently pending or
threatened with regard to any Taxes or Tax Returns of EUA or any of its
Subsidiaries (other than those being contested in good faith and for which
adequate reserves have been established) and no issues have been raised in
writing by any Tax authority in connection with any Tax or Tax Return;
(h) Tax Liens. There are no Tax liens upon any asset of EUA or
any of its Subsidiaries except liens for Taxes not yet due.
(i) Powers of Attorney. No power of attorney currently in force
has been granted by EUA or any of its Subsidiaries concerning any Tax matter;
(j) Tax Rulings. Neither EUA nor any of its Subsidiaries has,
during the five year period prior to the date of this Agreement, received a Tax
Ruling (as defined below) or entered into a Closing Agreement (as defined below)
with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a
written ruling of a taxing authority relating to Taxes. "Closing Agreement", as
used in this Agreement, shall mean a written and legally binding agreement with
a taxing authority relating to Taxes;
(k) Availability of Tax Returns. EUA and its Subsidiaries have
made available to NEES complete and accurate copies, covering all years ending
on or after December 31, 1993, of (i) all Tax Returns, and any amendments
thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports
received from any taxing authority relating to any Tax Return filed by EUA or
any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or
any of its Subsidiaries with any taxing authority.
(l) Tax Sharing Agreements. No agreements relating to the
allocation or sharing of Taxes exist between or among EUA and any of its
Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member
of an affiliated group filing a consolidated federal income tax return (other
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than a group the common parent of which was EUA) or (ii) has any liability for
Taxes of any Person (other than EUA or its Subsidiaries) under United States
Treasury Regulation Section 1.1502-6 (or any provision of state, local), or
foreign law, as a transferee or successor, by contract or otherwise;
(m) Code Section 481 Adjustments. Neither EUA nor any of its
Subsidiaries is required to include in income any adjustment pursuant to Code
Section 481(a) by reason of a voluntary change in accounting method initiated by
EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has
not proposed any such adjustment or change in accounting method;
(n) Code Sections 6661 and 6662. All transactions that could
give rise to an understatement of federal income tax, and within the meaning of
Code Section 6662 have been adequately disclosed (or, with respect to Tax
Returns filed following the Closing, will be adequately disclosed) on the Tax
Returns of EUA and its Subsidiaries in accordance with Code Section
6662(d)(2)(B);
(o) Intercompany Transactions. Neither EUA nor any of its
Subsidiaries has engaged in any intercompany transactions within the meaning of
Treasury Regulations ss. 1.1502-13 for which any income or gain will remain
unrecognized as of the close of the last taxable year prior to the Closing Date;
and
(p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries
is required to file a foreign tax return.
"Taxes" as used in this Agreement, shall mean any federal, state,
county, local or foreign taxes, charges, fees, levies, or other assessments,
including all net income, gross income, premiums, sales and use, ad valorem,
transfer, gains, profits, windfall profits, excise, franchise, real and personal
property, gross receipts, capital stock, production, business and occupation,
employment, disability, payroll, license, estimated, stamp, custom duties,
severance or withholding taxes, other taxes or similar charges of any kind
whatsoever imposed by any governmental entity, whether imposed directly on a
Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar
provision of state, local or foreign law), as a transferee or successor, by
contract or otherwise and includes any interest and penalties on or additions to
any such taxes or in respect of a failure to comply with any requirement
relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a
report, return or other information required to be supplied to a governmental
entity with respect to Taxes including, where permitted or required, combined,
unitary or consolidated returns for any group of entities.
4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan"
(as defined in Section 3(3) of the Employee Retirement Income Security Act of
1974, as amended ("ERISA")), bonus, deferred compensation, share option or other
written agreement relating to employment or fringe benefits for employees,
former employees, officers, trustees or directors of EUA or any of its
Subsidiaries effective as of the date hereof or providing benefits as of the
date hereof to current employees, former employees, officers, trustees or
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directors of EUA or pursuant to which EUA or any of its subsidiaries has or
could reasonably be expected to have any liability (collectively, the "EUA
Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure
Letter, is in material compliance with applicable law, and has been administered
and operated in all material respects in accordance with its terms. Each EUA
Employee Benefit Plan which is intended to be qualified within the meaning of
Section 401(a) of the Code has received a favorable determination letter from
the IRS as to such qualification and, to the knowledge of EUA, no event has
occurred and no condition exists which could reasonably be expected to result in
the revocation of, or have any adverse effect on, any such determination.
(b) Complete and correct copies of the following documents have
been made available to NEES as of the date of this Agreement: (i) all EUA
Employee Benefit Plans and any related trust agreements or insurance contracts,
(ii) the most current summary descriptions of each EUA Employee Benefit Plan
subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto
for each EUA Employee Benefit Plan subject to such reporting, (iv) the most
recent determination of the IRS with respect to the qualified status of each EUA
Employee Benefit Plan that is intended to qualify under Section 401(a) of the
Code, (v) the most recent accountings with respect to each EUA Employee Benefit
Plan funded through a trust and (vi) the most recent actuarial report of the
qualified actuary of each EUA Employee Benefit Plan with respect to which
actuarial valuations are conducted.
(c) Except as set forth in Section 4.11(c) of the EUA Disclosure
Letter, neither EUA nor any Subsidiary maintains or is obligated to provide
benefits under any EUA Employee Benefit Plan (other than as an incidental
benefit under a Plan qualified under Section 401(a) of the Code) which provides
health or welfare benefits to retirees or other terminated employees other than
benefit continuations as required pursuant to Section 601 of ERISA. Each EUA
Employee Benefit Plan subject to the requirements of Section 601 of ERISA has
been operated in material compliance therewith. EUA has not contributed to a
nonconforming group health plan (as defined in Code Section 5000(c)) and no
person under common control with EUA within the meaning of Section 414 of the
Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a)
that is or could reasonably be expected to be a liability of EUA's.
(d) Except as set forth in Section 4.11(d) of the EUA Disclosure
Letter, each EUA Employee Benefit Plan covers only employees who are employed by
EUA or a Subsidiary (or former employees or beneficiaries with respect to
service with EUA or a Subsidiary).
(e) Except as set forth in Section 4.11(e) of the EUA Disclosure
Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other
corporation or organization controlled by or under common control with any of
the foregoing within the meaning of Section 4001 of ERISA has, within the
five-year period preceding the date of this Agreement, at any time contributed
to any "multiemployer plan," as that term is defined in Section 4001 of ERISA.
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(f) No event has occurred, and there exists no condition or set
of circumstances in connection with any EUA Employee Benefit Plan, under which
EUA or any Subsidiary, directly or indirectly (through any indemnification
agreement or otherwise), could be subject to any liability under Section 409 of
ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code
except for instances of non-compliance which, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect.
(g) Neither EUA nor any ERISA Affiliate has incurred any
liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section
302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been
satisfied in full and no event or condition exists or has existed which could
reasonably be expected to result in any such material liability. As of the date
of this Agreement, no "reportable event" within the meaning of Section 4043 of
ERISA has occurred with respect to any EUA Employee Benefit Plan that is a
defined benefit plan under Section 3(35) of ERISA.
(h) Except as set forth in Section 4.11(h) of the EUA Disclosure
Letter, no employer securities, employer real property or other employer
property is included in the assets of any EUA Employee Benefit Plan.
(i) Full payment has been made of all material amounts which EUA
or any affiliate thereof was required under the terms of EUA Employee Benefit
Plans to have paid as contributions to such plans on or prior to the Effective
Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which
is subject to Part III of Subtitle B of Title I of ERISA has incurred any
"accumulated funding deficiency" within the meaning of Section 302 of ERISA or
Section 412 of the Code, whether or not waived.
(j) Except as set forth in Section 4.11(j) of the EUA Disclosure
Letter, no amounts payable under any EUA Employee Benefit Plan or other
agreement, contract, or arrangement will fail to be deductible for federal
income tax purposes by virtue of Section 280G or Section 162(m) of the Code.
4.12 Labor Matters. As of the date hereof, except as set forth in
Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries is a party to any material collective bargaining agreement or other
labor agreement with any union or labor organization. To the knowledge of EUA,
as of the date hereof, there is no current union representation question
involving employees of EUA or any of its Subsidiaries, nor does EUA know of any
activity or proceeding of any labor organization (or representative thereof) or
employee group to organize any such employees. Except as set forth in Section
4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice,
employment discrimination or other employment-related complaint or proceeding
against EUA or any of its Subsidiaries pending or, to the knowledge of EUA,
threatened, which has or could reasonably be expected to have an EUA Material
Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or
lockout pending, or, to the knowledge of EUA, threatened, against or involving
EUA or any of its Subsidiaries which has or could reasonably be expected to
have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim,
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suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries,
threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any
Governmental Authority investigation pending or threatened, in respect of which
any trustee, director, officer, employee or agent of EUA or any of its
Subsidiaries is or may be entitled to claim indemnification from EUA or any of
its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and
their respective articles of incorporation and by-laws, in the case of EUA's
Subsidiaries, or as provided in the indemnification agreements listed in Section
4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the
EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all
federal, state and local laws with respect to employment practices and labor
relations, including, without limitation, any provisions relating to affirmative
action, employment discrimination, wages, hours, collective bargaining, and the
payment of social security and similar taxes, safety and health regulations and
mass layoffs and plant closings except for such instances of noncompliance
which, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect.
4.13 Environmental Matters. Except as disclosed in EUA SEC Reports
filed prior to the date of this Agreement or in Section 4.13 of the EUA
Disclosure Letter:
(a) (i) Each of EUA and its Subsidiaries is in compliance with
all applicable Environmental Laws (as hereinafter defined), except where the
failure to be in compliance, in the aggregate could not reasonably be expected
to result in an EUA Material Adverse Effect; and
(ii) Neither EUA nor any of its Subsidiaries has received
any written communication from any person or Governmental Authority that alleges
that EUA or any of its Subsidiaries is not in such compliance (including the
materiality qualifier set forth in clause (i) above) with applicable
Environmental Laws.
(b) Each of EUA and its Subsidiaries has obtained all
environmental, health and safety permits and governmental authorizations
(collectively, the "Environmental Permits") necessary for the construction of
their facilities and the conduct of their operations, as applicable, and all
such Environmental Permits are in good standing or, where applicable, a renewal
application has been timely filed and agency approval is expected in the
ordinary course of business, and EUA and its Subsidiaries are in compliance with
all terms and conditions of the Environmental Permits, except where the failure
have such Environmental Permits, file a renewal application for such
Environmental Permits, or to be in compliance with such Environmental Permits,
in the aggregate could not reasonably be expected to result in an EUA Material
Adverse Effect.
(c) There is no Environmental Claim (as hereinafter defined)
that could, individually or in the aggregate, reasonably be expected to have an
EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries;
(ii) against any person or entity whose liability for any Environmental Claim
EUA or any of its Subsidiaries has or may have retained or assumed either
contractually or by operation of law; or (iii) against any real or personal
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property or operations which EUA or any of its Subsidiaries owns, leases or
manages, in whole or in part.
(d) To the knowledge of EUA there have not been any material
Releases (as hereinafter defined) of any Hazardous Material (as hereinafter
defined) that would be reasonably likely to form the basis of any material
Environmental Claim against EUA or any of its Subsidiaries, or against any
person or entity whose liability for any material Environmental Claim EUA or any
of its Subsidiaries has or may have retained or assumed either contractually or
by operation of law, except for any Environmental Claim that, individually or in
the aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
(e) To the knowledge of EUA with respect to any predecessor of
EUA or any of its Subsidiaries, there is no material Environmental Claim pending
or threatened, and there has been no Release of Hazardous Materials that could
reasonably be expected to form the basis of any material Environmental Claim
except for any Environmental Claim that, individually or in the aggregate, could
not be reasonably be expected to have an EUA Material Adverse Effect.
(f) As used in this Section 4.13:
(i) "Environmental Claim" means any and all written
administrative, regulatory or judicial actions, suits, demands, demand letters,
directives, claims, liens, investigations, proceedings or notices or
noncompliance, liability or violation by any person or entity (including any
Governmental Authority) alleging potential liability (including, without
limitation, potential responsibility or liability for enforcement, investigatory
costs, cleanup costs, governmental response costs, removal costs, remedial
costs, natural resources damages, property damages, personal injuries or
penalties) arising out of, based on or resulting from
(A) the presence, or Release or threatened Release into the
environment, of any Hazardous Materials at any
location, whether or not owned, operated, leased or
managed by EUA or any of its Subsidiaries; or
(B) circumstances forming the basis of any violation, or
alleged violation, of any Environmental Law; or
(C) any and all claims by any third party seeking damages,
contribution, indemnification, cost recovery,
compensation or injunctive relief resulting from the
presence or Release of any Hazardous Materials;
(ii) "Environmental Laws" means all federal, state and local
laws, rules and regulations and binding interpretation thereof, relating to
pollution, the environment (including, without limitation, ambient air, surface
water, groundwater, land surface or subsurface strata) or protection of human
health as it relates to the environment including, without limitation, laws and
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regulations relating to Releases or threatened Releases of Hazardous
Materials, or otherwise relating to the manufacture, generation, processing,
distribution, use, treatment, storage, disposal, transport or handling of
Hazardous Materials;
(iii) "Hazardous Materials" means (A) any petroleum or
petroleum products, radioactive materials, asbestos in any form that is or could
become friable, urea formaldehyde foam insulation, and transformers or other
equipment that contain dielectric fluid containing polychlorinated biphenyls;
and (B) any chemicals, materials or substances which are now defined as or
included in the definition of "hazardous substances", "hazardous wastes",
"hazardous materials", "extremely hazardous wastes", "restricted hazardous
wastes", "toxic substances", "toxic pollutants", or words of similar import,
under any Environmental Law; and (c) any other chemical, material, substance or
waste, exposure to which is now prohibited, limited or regulated under any
Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x)
operates or (y) stores, treats or disposes of Hazardous Materials; and
(iv) "Release" means any release, spill, emission, leaking,
injection, deposit, disposal, discharge, dispersal, leaching or migration into
the atmosphere, soil, surface water, groundwater or property.
4.14 Regulation as a Utility. (a) EUA is a public utility holding
company registered under Section 5, and subject to the provisions, of the 1935
Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA
that are "public utility companies" within the meaning of Section 2(a)(5) of the
1935 Act and lists the jurisdictions where each such Subsidiary is subject to
regulation as a public utility company or public service company. Except as set
forth above and as set forth in Section 4.14 of the EUA Disclosure Letter,
neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to
regulation as a public utility or public service company (or similar
designation) by the federal government of the United States, any state in the
United States or any political subdivision thereof, or any foreign country.
(b) As used in this Section 4.14, the terms "subsidiary company"
and "affiliate" shall have the respective meanings ascribed to them in Section
2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act.
4.15 Insurance. Except as set forth in Section 4.15 of the EUA
Disclosure Letter, each of EUA and its Subsidiaries is, and has been
continuously since January 1, 1994, insured with financially responsible
insurers in such amounts and against such risks and losses as are customary in
all material respects for companies in the United States conducting the business
conducted by EUA and its Subsidiaries during such time period. Except as set
forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries has received any notice of cancellation or termination with respect
to any material insurance policy of EUA or any of its Subsidiaries. The
insurance policies of EUA and each of its Subsidiaries are valid and enforceable
policies.
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4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of
EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power
Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a
minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described
in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities").
With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric
Company holds the required operating licenses from the NRC. With respect to the
Yankee Companies, each Yankee Company holds its own operating license from the
NRC. Because it is a minority stockholder or a minority joint owner, Montaup
Electric Company does not have responsibility for the operation of EUA Nuclear
Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or
as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge
of EUA, neither EUA nor any of its Subsidiaries is in violation of any
applicable health, safety, regulatory and other legal requirement, including NRC
laws and regulations and Environmental Laws, applicable to EUA Nuclear
Facilities except for such failure to comply as could not reasonably be expected
to have a material adverse effect with respect to EUA Nuclear Facilities and the
ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear
Facilities maintains emergency plans designed to respond to an unplanned release
therefrom of radioactive materials into the environment and insurance coverages
consistent with industry practice. EUA has funded, or has caused the funding of,
its portion of the decommissioning cost of each of the EUA Nuclear Facilities
and the storage of spent nuclear fuel consistent with the most recently approved
plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as
set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA,
no EUA Nuclear Facility is as of the date of this Agreement on the List of
Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the
NRC.
4.17 Vote Required. The affirmative vote of two-thirds of the
outstanding EUA Shares voting as a single class (with each EUA Share having one
vote per share) with respect to the approval of the Merger and other
transactions contemplated hereby is the only vote of the holders of any class or
series of equity securities of EUA or its Subsidiaries required to approve this
Agreement and approve the Merger and other transactions contemplated hereby.
4.18 Opinion of Financial Advisor. EUA has received the opinion of
Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that,
as of such date, the Merger Consideration is fair from a financial point of view
to the holders of EUA Shares. A true and complete copy of the written opinion
will be delivered to NEES promptly after receipt thereof by EUA.
4.19 Ownership of NEES Common Shares. Neither EUA nor any of its
Subsidiaries or other affiliates beneficially owns any NEES Common Shares.
4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions
so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply
to this Agreement, the Merger or other transactions contemplated hereby or
thereby.
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4.21 Year 2000. The Information Systems operated by EUA and its
Subsidiaries which is used in the conduct of their business is capable of
providing or being adapted to provide uninterrupted millennium functionality to
record, store, process and present calendar dates falling on or after January 1,
2000 in substantially the same manner and with the same functionality as such
Information Systems record, store, process and present such calendar dates
falling on or before December 31, 1999 other than such interruptions in
millennium functionality that could not, individually or in the aggregate,
reasonably be expected to result in a EUA Material Adverse Effect. EUA
reasonably believes as of the date hereof that the remaining cost of adaptations
referred to in the foregoing sentence will not exceed the amounts reflected in
the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding
the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o)
hereof and of the implementation of any recommendations by such Y2K Consultant
actually made by EUA that are not already part of EUA's compliance plan as of
the date hereof). "Information Systems" means mainframe and midrange hardware,
operating system software and applications programs; network and desktop (PC)
hardware, operating system software and applications programs; EDI (Electronic
Date Interchange) and FTP (File Transfer Protocol) software; and embedded
systems hardware and applications software.
4.22 EUA Associates. The representations and warranties set forth in
Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all
material respects with regard to EUA Associates.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES
NEES represents and warrants to EUA as follows:
5.01 Organization and Qualification. NEES is a voluntary association
duly organized, validly existing and in good standing under the laws of the
Commonwealth of Massachusetts and has full power, authority and legal right to
own its property and assets and to transact the business in which it is engaged.
Each of the NEES Subsidiaries is a corporation duly organized or incorporated,
validly existing and in good standing under the laws of its jurisdiction of
organization or incorporation and has full corporate power and authority to
conduct its business as and to the extent now conducted and to own, use and
lease its assets and properties, except where failure to be so organized or
incorporated, existing and in good standing or to have such power and authority,
individually or in the aggregate, could not reasonably be expected to have a
NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material
Adverse Effect" means a material adverse effect on the business, assets, results
of operations, condition (financial or otherwise) or prospects of NEES and its
Subsidiaries taken as a whole. LLC is a limited liability company validly
existing under the laws of the Commonwealth of Massachusetts. LLC was formed
solely for the purpose of engaging in the Merger and other transactions
contemplated hereby, has engaged in no other business activities (other than in
connection with the formation and capitalization of LLC pursuant to or in
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accordance with the LLC Agreement (as defined below)) and has conducted its
operations only as contemplated hereby and by the LLC Agreement. Each of NEES
and its Subsidiaries is duly qualified, licensed or admitted to do business and
is in good standing in each jurisdiction in which the ownership, use or leasing
of its assets and properties, or the conduct or nature of its business, makes
such qualification, licensing or admission necessary, except where failure to be
so qualified, licensed or admitted and in good standing, individually or in the
aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect. NEES has previously delivered to EUA correct and complete copies of its
Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles
of association of LLC.
5.02 Authority. Each of NEES and LLC has full power and authority to
enter into this Agreement, and to perform its obligations hereunder, and to
consummate the Merger and other transactions contemplated hereby. The execution,
delivery and performance of this Agreement by each of NEES and LLC and the
consummation by each of NEES and LLC of the Merger and other transactions
contemplated hereby have been duly authorized by all necessary corporate action
on the part of NEES and all necessary action on the part of LLC. This Agreement
has been duly and validly executed and delivered by each of NEES and LLC and
constitutes a legal, valid and binding obligation of each of NEES and LLC
enforceable against each of NEES and LLC in accordance with its terms, except as
enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
5.03 Capital Stock. The authorized equity securities of NEES consists
of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986
shares were issued and outstanding as of the close of business on January 29,
1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares
were held in the treasury of NEES. All of the issued and outstanding NEES Shares
are duly authorized, validly issued, fully paid and nonassessable. Except as may
be provided by the New England Electric System Companies' Incentive Share Plan,
the New England Electric System Companies Incentive Thrift Plan I, the New
England Electric System Companies Incentive Thrift Plan II, the New England
Electric Companies Long-Term Performance Share Award Plan, and the New England
Electric System Directors' annual retainer shares, and except as set forth in
Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES
and LLC concurrently with the execution and delivery of this Agreement (the
"NEES Disclosure Letter"), on the date hereof there are no outstanding Options
obligating NEES or any of its Subsidiaries to issue or sell any shares of equity
securities of NEES or to grant, extend or enter into any Option with respect
thereto.
5.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by each of NEES and LLC do not, and the performance
by each of NEES and LLC of its obligations hereunder and the consummation of the
Merger and other transactions contemplated hereby will not, conflict with,
result in a violation or breach of, constitute (with or without notice or lapse
of time or both) a default under, result in or give to any person any right of
payment or reimbursement, termination, cancellation, modification or
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acceleration of, or result in the creation or imposition of any Lien upon any of
the assets or properties of NEES, or LLC under, any of the terms, conditions or
provisions of (i) the NEES Agreement and Declaration of Trust or the articles of
organization of LLC, (ii) subject to the actions described in paragraph (b) of
this Section, (x) any laws or orders of any Governmental Authority applicable to
NEES or LLC or any of their respective assets or properties, or (y) subject to
obtaining the third-party consents (the "NEES Required Consents") set forth in
Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a
party or by which NEES or any of its Subsidiaries or any of their respective
assets or properties is bound, excluding from the foregoing clauses (x) and (y)
conflicts, violations, breaches, defaults, terminations, modifications,
accelerations and creations and impositions of Liens which, individually or in
the aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect.
(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by NEES or LLC or the
consummation by NEES or LLC of the Merger and other transactions contemplated
hereby except as described in Section 5.04 of the NEES Disclosure Letter or the
failure of which to obtain could not reasonably be expected to result in a NEES
Material Adverse Effect (the "NEES Required Statutory Approvals," it being
understood that references in this Agreement to "obtaining" such NEES Required
Statutory Approvals shall mean making such declarations, filings or
registrations; giving such notices; obtaining such authorizations, consents or
approvals; and having such waiting periods expire as are necessary to avoid a
violation of law).
5.05 Information Supplied. (a) The information supplied by NEES or LLC
and included in the Proxy Statement with the written consent of NEES or LLC, as
the case may be, will not, at the date mailed to EUA's Shareholders or at the
time of EUA Shareholder's Meeting, contain any untrue statements of a material
fact or omit to state any material fact required to be stated therein or
necessary in order to make the statements therein, in light of the circumstances
under which they were made, not misleading.
(b) Notwithstanding the foregoing provisions of this Section
5.05, no representation or warranty is made by NEES with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by EUA for inclusion or incorporation by reference therein or based on
information which is not made in or incorporated by reference in such documents
but which should have been disclosed pursuant to this Section 5.05.
5.06 Compliance. Except as set forth in Section 5.06 of the NEES
Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date
hereof, NEES is not in violation of, is, to the knowledge of NEES, under
investigation with respect to any violation of, or has been given notice or been
charged with any violation of, any law, statute, order, rule, regulation,
ordinance or judgment (including, without limitation, any applicable
environmental law, ordinance or regulation) of any Governmental Authority,
except for possible violations which, individually or in the aggregate, could
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not reasonably be expected to have a NEES Material Adverse Effect. Except as set
forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES
Reports filed prior to the date hereof, NEES and its Subsidiaries have all
material permits, licenses and other governmental authorizations, consents and
approvals necessary to conduct their businesses as presently conducted which are
material to the operation of the businesses of NEES. NEES is not in breach or
violation of, or in default in the performance or observance of, any term or
provision of, and no event has occurred which, with lapse of time or action by a
third party, could result in a default by NEES under (i) the NEES Agreement and
Declaration of Trust or by-laws or (ii) any contract, commitment, agreement,
indenture, mortgage, loan agreement, note, lease, bond, license, approval or
other instrument to which it is a party or by which NEES is bound or to which
any of their respective property is subject, except for possible violations,
breaches or defaults which, individually or in the aggregate, could not
reasonably be expected to have a NEES Material Adverse Effect.
5.07 Financing. NEES has or will have available, prior to the
Effective Time, sufficient cash in immediately available funds to pay or to
cause LLC to pay the Merger Consideration pursuant to Article II hereof and to
consummate the Merger and other transactions contemplated hereby.
5.08 No Vote Required. No vote of the NEES Shares or of any class or
series of equity securities of NEES or its Subsidiaries is necessary for the
approval of the Merger and other transactions contemplated hereby.
5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries
or other affiliates beneficially owns any EUA Shares.
5.10 Merger with The National Grid Group plc. NEES has entered into an
Agreement and Plan of Merger dated as of December 11, 1998 by and among The
National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly
known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to
Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of
this Agreement to National Grid Group, and National Grid Group has given NEES
its written consent to enter into this Agreement and consummate the Merger on
the terms set forth in this Agreement. Prior to the execution of this Agreement,
NEES has provided EUA with a copy of such written consent.
ARTICLE VI
COVENANTS
6.01 Covenants of EUA. At all times from and after the date hereof
until the Effective Time, EUA covenants and agrees as to itself and its
Subsidiaries that (except as expressly contemplated or permitted by this
Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to
the extent that NEES shall otherwise previously consent in writing):
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(a) Ordinary Course. EUA and each of its Subsidiaries shall
conduct their businesses only in, and EUA and each of its Subsidiaries shall not
take any action except in, the ordinary course consistent with good utility
practice. Without limiting the generality of the foregoing, EUA and its
Subsidiaries shall use all commercially reasonable efforts to preserve intact in
all material respects their present business organizations and reputation, to
maintain in effect all existing permits, to keep available the services of their
key officers and employees, to maintain their assets and properties in good
working order and condition, ordinary wear and tear excepted, to maintain
insurance on their tangible assets and businesses in such amounts and against
such risks and losses as are currently in effect, to preserve their
relationships with customers and suppliers and others having significant
business dealings with them and to comply in all material respects with all laws
and orders of all Governmental Authorities applicable to them.
(b) Charter Documents. EUA shall not, nor shall it permit any of
its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the
case of EUA, and its certificate or articles of incorporation or organization or
bylaws (or other comparable charter documents), in the case of EUA's
Subsidiaries.
(c) Dividends. EUA shall not, nor shall it permit any of its
Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other
distributions in respect of, any of its capital stock or share capital, except:
(A) that EUA may continue the declaration and payment of
regular quarterly dividends on EUA Shares with usual
record and payment dates not, in any fiscal year, in
excess of the dividend for the comparable period in the
prior fiscal year;
(B) that the Subsidiaries of EUA set forth in Section
6.01(c) of the EUA Disclosure Letter may continue the
declaration and payment of dividends on preferred stock
in accordance with the terms of such stock, with the
record and payment dates and in the amounts set forth
in Section 6.01(c) of the EUA Disclosure Letter;
(C) if the Effective Time does not occur between a record
date and payment date of a regular quarterly dividend,
for a special dividend on EUA Shares with respect to
the quarter in which the Effective Time occurs with a
record date on or prior to the date on which the
Effective Time occurs, which does not exceed an amount
equal to the product of (x) the number of days between
the last payment date of a regular quarterly dividend
and the record date of such special dividend,
multiplied by (y) $.0045; and
(D) for dividends and distributions (including liquidating
distributions) by a direct or indirect Subsidiary of
EUA to its parent.
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(ii) split, combine, subdivide, reclassify or take similar action with respect
to any of its capital stock or share capital or issue or authorize or propose
the issuance of any other securities in respect of, in lieu of or in
substitution for shares of its capital stock or comprised in its share capital,
(iii) adopt a plan of complete or partial liquidation or resolutions providing
for or authorizing such liquidation or a dissolution, merger, consolidation,
restructuring, recapitalization or other reorganization or (iv) directly or
indirectly redeem, repurchase or otherwise acquire any shares of its capital
stock or any Option with respect thereto except:
(A) in connection with intercompany purchases of capital
stock or share capital,
(B) for the purpose of funding EUA's dividend reinvestment
and share purchase plan in accordance with past
practice, or
(C) subject to EUA's obligations under the Securities Act
and the Exchange Act, pursuant to EUA's previously
announced share repurchase program provided that the
number of EUA Shares repurchased does not exceed
3,000,000 and the price paid per share does not exceed
95% of the Per Share Amount.
(d) Share Issuances. EUA shall not, nor shall it permit any of
its Subsidiaries to, issue, deliver or sell, or authorize or propose the
issuance, delivery or sale of, any shares of its capital stock or any Option
with respect thereto (other than the issuance by a wholly owned Subsidiary of
its capital stock to its direct or indirect parent corporation, or modify or
amend any right of any holder of outstanding shares of capital stock or Options
with respect thereto).
(e) Acquisitions. EUA shall not, nor shall it permit any of its
Subsidiaries to acquire or agree to acquire (by merging or consolidating with,
or by purchasing a substantial equity interest in or substantial portion of the
assets of, or by any other manner) any business or any corporation, partnership,
association or other business organization or division thereof.
(f) Dispositions. EUA shall not, nor shall it permit any of its
Subsidiaries to sell, lease, securitize, grant any security interest in or
otherwise dispose of or encumber any of its assets or properties, other than
dispositions in the ordinary course of its business consistent with past
practice and having an aggregate value of less than $1,000,000 for each
disposition and $5,000,000 in the aggregate.
(g) Indebtedness. EUA shall not, nor shall it permit any of its
Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed
or guaranteed or otherwise assumed, including, without limitation, the issuance
of debt securities or warrants or rights to acquire debt) or enter into any
"keep well" or other agreement to maintain any financial condition of another
Person or enter into any arrangement having the economic effect of any of the
foregoing other than (i) short-term indebtedness in the ordinary course of
business consistent with past practice (such as the issuance of commercial paper
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or the use of existing credit facilities) in amounts not exceeding the amounts
set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term
indebtedness in connection with the refinancing of existing indebtedness either
at its stated maturity or at a lower cost of funds (calculating such cost on an
aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in
favor of wholly owned Subsidiaries of EUA in connection with the conduct of the
business of such wholly owned Subsidiaries of EUA not aggregating more than
$1,000,000.
(h) Capital Expenditures. Except (i) as required by law or (ii)
as reasonably deemed necessary by EUA after consulting with NEES following a
catastrophic event, such as a major storm, EUA shall not, nor shall it permit
any of its Subsidiaries to make any capital expenditures or commitments during
any fiscal year that is in excess of 110% of (i) the aggregate amount set forth
in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its
Subsidiaries that are public utility companies within the meaning of Section
2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the
EUA Disclosure Letter with respect to each of EUA's other Subsidiaries.
(i) Employee Benefits. EUA shall not, nor shall it permit any of
its Subsidiaries to enter into, adopt, amend (except as may be required by
applicable law) or terminate any EUA Employee Benefit Plan, or other agreement,
arrangement, plan or policy between EUA or one of its Subsidiaries and one or
more of its trustees, directors, officers, employees or former employees, or,
except for normal increases in the ordinary course of business, (a) increase in
any manner the compensation or fringe benefits of any trustee, director or
executive officer, (b) increase in any manner the compensation or fringe
benefits of any employee, (c) pay any benefit not required by any plan or
arrangement in effect as of the date hereof or, (d) cause any trustee, director,
officer, employee or former employee of EUA to accrue or receive additional
benefits, accelerate vesting or accelerate the payment of any benefits under any
EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA,
prior to the Closing Date, shall take all necessary action and make all
necessary amendments to its stock-based plans so that all such plans will be in
a form that allows the plans to function after the Effective Time and after any
merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to
the Closing Date, shall take all necessary actions, in a manner satisfactory to
NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity
nor their affiliates' stock or securities will be required to be held in, or
distributed pursuant to, any EUA Employee Benefit Plan.
(j) Labor Matters. Notwithstanding any other provision of this
Agreement to the contrary, EUA or its Subsidiaries may negotiate successor
collective bargaining agreements to those referenced in Section 4.12 hereof, and
may negotiate other collective bargaining agreements or arrangements as required
by law or for the purpose of implementing the agreements referenced in Section
4.12 hereof. EUA will keep NEES informed as to the status of, and will consult
with NEES as to the strategy for, all negotiations with collective bargaining
representatives. EUA and its Subsidiaries shall act prudently and reasonably and
consistent with their obligation under applicable law in such negotiations.
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(k) Discharge of Liabilities. EUA shall not, nor shall it permit
its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities
or obligations (absolute, accrued, asserted or unasserted, contingent or
otherwise), other than the payment, discharge or satisfaction, in the ordinary
course of business consistent with past practice (which includes the payment of
final and unappealable judgments) or in accordance with their terms, of
liabilities reflected or reserved against in, or contemplated by, the most
recent consolidated financial statements (or the notes thereto) of such party
included in EUA SEC Reports, or incurred in the ordinary course of business
consistent with past practice.
(l) Contracts. EUA shall not, nor shall it permit its
Subsidiaries, except in the ordinary course of business consistent with past
practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to
modify, amend, terminate or fail to use commercially reasonable efforts to renew
any material Contract to which EUA or any of its Subsidiaries is a party or
waive, release or assign any material rights or claims or (ii) to enter into any
new material Contracts except as expressly permitted by Sections 6.01 (f), (g)
or (i) and 7.06 hereof.
(m) Equity Investments. EUA shall not, nor shall it permit its
Subsidiaries or affiliates to, make equity contributions to non-affiliates or to
its non-utility Subsidiaries.
(n) Loans. EUA shall not, nor shall it permit its Subsidiaries
or affiliates to, loan money to non-affiliates or to its non-utility
Subsidiaries.
(o) Year 2000. EUA, within 15 days of the date of this
Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a
detailed assessment of the adequacy and state of completion of its Year 2000
Program, including but not limited to assessment and testing of its customer,
accounting, and operational systems. The Y2K Consultant and scope of work of the
Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be
completed as soon thereafter as practicable. EUA shall have such assessment
updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA
shall allow designated NEES personnel and representatives access to the Y2K
Consultant's personnel, reports and recommendations and access to EUA's
personnel, documents, and information related to the Y2K issue. EUA and the
third party shall meet with such designated NEES personnel and representatives
on a periodic basis (but not less frequently than monthly) to update NEES on
EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section
9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K
Consultant.
(p) Insurance. EUA shall, and shall cause its Subsidiaries to,
maintain with financially responsible insurance companies (or through
self-insurance, consistent with past practice) insurance in such amounts and
against such risks and losses as are customary for companies engaged in their
respective businesses.
(q) 1935 Act. EUA shall not, nor shall it permit any of its
Subsidiaries to, engage in any activities which would cause a change in its
status, or that of its Subsidiaries, under the 1935 Act.
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(r) Regulatory Matters. Subject to applicable law and except for
non-material filings in the ordinary course of business consistent with past
practice, EUA shall consult with NEES prior to implementing any changes in its
or any of its Subsidiaries' rates or charges, standards of service or accounting
or executing any agreement with respect thereto that is otherwise permitted
under this Agreement and shall, and shall cause its Subsidiaries to, deliver to
NEES a copy of each such filing or agreement at least four (4) business days
prior to the filing or execution thereof so that NEES may comment thereon. EUA
shall, and shall cause its Subsidiaries to, make all such filings (i) only in
the ordinary course of business consistent with past practice or (ii) as
required by a Governmental Authority or regulatory agency with appropriate
jurisdiction.
(s) Accounting. EUA shall not, nor shall it permit any of its
Subsidiaries to make any changes in their accounting methods, policies or
procedures, except as required by law, rule, regulation or applicable generally
accepted accounting principles;
(t) Tax Status. Neither EUA nor any of its Subsidiaries shall
(i) make or rescind any material express or deemed election relating to Taxes,
(ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii)
settle or compromise any material claim, action, suit, litigation, proceeding,
arbitration, investigation, audit, or controversy relating to Taxes or (iv)
change in any material respect any of its methods of reporting income,
deductions or accounting for federal income tax purposes from those employed in
the preparation of its federal income Tax Return for the taxable year ending
December 31, 1997, except as may be required by applicable law.
(u) No Breach. EUA shall not, nor shall it permit any of its
Subsidiaries to willfully take or fail to take any action that would or is
reasonably likely to result in (i) a material breach of any provision of this
Agreement or (ii) its representations and warranties set forth in this Agreement
being untrue in any material respect on and as of the Closing Date.
(v) Advice of Changes. EUA shall confer with NEES on a regular
and frequent basis with respect to EUA's business and operations and other
matters relevant to the Merger to the extent permitted by law, and shall
promptly advise NEES, orally and in writing, of any material change or event,
including, without limitation, any complaint, investigation or hearing by any
Governmental Authority (or communication indicating the same may be
contemplated) or the institution or threat of material litigation; provided that
EUA shall not be required to make any disclosure to the extent such disclosure
would constitute a violation of any applicable law or regulation.
(w) Notice and Cure. EUA will notify NEES in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to EUA, that causes or will or may be likely to cause any covenant or agreement
of EUA under this Agreement to be breached or that renders or will render untrue
in any material respect any representation or warranty of EUA contained in this
Agreement. EUA also will notify NEES in writing of, and will use all
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commercially reasonable efforts to cure, before the Closing, any material
violation or breach, as soon as practical after it becomes known to EUA, of any
representation, warranty, covenant or agreement made by EUA. No notice given
pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(x) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, EUA will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to the other's obligations contained in
this Agreement and to consummate and make effective the Merger and other
transactions contemplated by this Agreement, and EUA will not, nor will it
permit any of its Subsidiaries to, take or fail to take any action that could be
reasonably expected to result in the nonfulfillment of any such condition.
(y) Third Party Standstill Agreements. Except as provided in
Section 7.08 hereto, during the period from the date of this Agreement through
the Effective Time, neither EUA nor any of its Subsidiaries shall terminate,
amend, modify or waive any provision of any confidentiality or standstill
agreement to which it is a party. During such period, EUA shall take all steps
necessary to enforce, to the fullest extent permitted under applicable law, the
provisions of any such agreement.
6.02 Covenants of NEES. At all times from and after the date hereof
until the Effective Time, NEES covenants and agrees that (except as expressly
contemplated or permitted by this Agreement or to the extent that EUA shall
otherwise previously consent in writing):
(a) No Breach. NEES shall not, nor shall it permit any of its
Subsidiaries to, except as otherwise expressly provided for in this Agreement,
willfully take or fail to take any action that would or is reasonably likely to
result in (i) a material breach of any of its covenants or agreements contained
in this Agreement or (ii) any of its representations and warranties set forth in
Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this
Agreement being untrue in any material respect on and as of the Closing Date.
(b) Advice of Changes. NEES shall confer with EUA on a regular
and frequent basis with respect to any matter having, or which, insofar as can
be reasonably foreseen, could reasonably be expected to have, a NEES Material
Adverse Effect or materially impair the ability of NEES to consummate the Merger
and other transactions contemplated hereby; provided that NEES shall not be
required to make any disclosure to the extent such disclosure would constitute a
violation of any applicable law or regulation.
(c) Notice and Cure. NEES will notify EUA in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to NEES, that causes or will or may be likely to cause any covenant or agreement
of NEES under this Agreement to be breached or that renders or will render
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untrue in any material respect any representation or warranty of NEES contained
in this Agreement. NEES also will notify EUA in writing of, and will use all
commercially reasonable efforts to cure before the Closing, any material
violation or breach, as soon as practical after it becomes known to such party,
of any representation, warranty, covenant or agreement made by NEES. No notice
given pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(d) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, NEES will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to its obligations contained in this
Agreement and to consummate and make effective the Merger and other transactions
contemplated by this Agreement, and NEES will not, nor will it permit any of its
Subsidiaries to, take or fail to take any action that could be reasonably
expected to result in the nonfulfillment of any such condition.
(e) Conduct of Business of LLC. Prior to the Effective Time,
except as may be required by applicable law and subject to the other provisions
of this Agreement, NEES shall cause LLC to (i) perform its obligations under
this Agreement in accordance with its terms, and (ii) not engage directly or
indirectly in any business or activities of any type or kind and not enter into
any agreements or arrangements with any person, or be subject to or bound by any
obligation or undertaking, which is inconsistent with this Agreement.
(f) Certain Mergers. NEES shall not, and shall not permit any of
its Subsidiaries to, acquire or agree to acquire by merging or consolidating
with, or by purchasing a substantial portion of the assets of or equity in, or
by any other manner, any business or any corporation, partnership, association
or other business organization or division thereof, or otherwise acquire or
agree to acquire any assets if the entering into of a definitive agreement
relating to or the consummation of such acquisition, merger or consolidation
could reasonably be expected to (i) impose any material delay in the obtaining
of, or significantly increase the risk of not obtaining, any authorizations,
consents, orders, declarations or approvals of any Governmental Authority
necessary to consummate the Merger or the expiration or termination of any
applicable waiting period, (ii) significantly increase the risk of any
Governmental Authority entering an order prohibiting the consummation of the
Merger, (iii) significantly increase the risk of not being able to remove any
such order on appeal or otherwise or (iv) materially delay the consummation of
the Merger.
6.03 Additional Covenants by NEES and EUA.
(a) Control of Other Party's Business. Nothing contained in this
Agreement shall give NEES, directly or indirectly, the right to control or
direct EUA's operations prior to the Effective Time. Nothing contained in this
Agreement shall give EUA, directly or indirectly, the right to control or direct
NEES' operations prior to the Effective Time. Prior to the Effective Time, each
of EUA and NEES shall exercise, consistent with the terms and conditions of this
Agreement, complete control and supervision over its respective operations.
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(b) Transition Steering Team. As soon as reasonably practicable
after the date hereof, NEES and EUA shall create a special transition steering
team, with representation from EUA and NEES, that will develop recommendations
concerning the future structure and operations of EUA after the Effective Time,
subject to applicable law. The members of the transition steering team shall be
appointed by the Chief Executive Officers of NEES and EUA. The functions of the
transition steering team shall include (i) to direct the exchange of information
and documents between the parties and their Subsidiaries as contemplated by
Section 7.01 and (ii) the development of regulatory plans and proposals,
corporate organizational and management plans, workforce combination proposals,
and such other matters as they deem appropriate.
ARTICLE VII
ADDITIONAL AGREEMENTS
7.01 Access to Information. EUA shall, and shall cause each of its
Subsidiaries to, and shall use commercially reasonable efforts to cause EUA
Associates to, throughout the period from the date hereof to the Effective Time
to the extent permitted by law, (i) provide NEES and its Representatives with
full access, upon reasonable prior notice and during normal business hours, to
all facilities, operations, officers (including EUA's environmental, health and
safety personnel), employees, agents and accountants of EUA and its Subsidiaries
and Associates and their respective assets, properties, books and records, to
the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal
obligation not to provide access or to the extent that such access would not
constitute a waiver of the attorney client privilege and does not unreasonably
interfere with the business and operations of EUA and its Subsidiaries and
Associates and (ii) furnish promptly to such persons (x) a copy of each report,
statement, schedule and other document filed or received by EUA or any of its
Subsidiaries pursuant to the requirements of federal or state securities laws
and each material report, statement, schedule and other document filed with any
other Governmental Authority, and (y) all other information and data (including,
without limitation, copies of Contracts, EUA Employee Benefit Plans, and other
books and records) concerning the business and operations of EUA and its
Subsidiaries as NEES or any of its Representatives reasonably may request. No
review pursuant to this Section 7.01 or otherwise shall affect any
representation or warranty contained in this Agreement or any condition to the
obligations of the parties hereto. Any such information or material obtained
pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such
term is defined in the letter agreement dated as of December 18, 1998 between
EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms
of the Confidentiality Agreement. NEES may provide information or materials that
it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01
to National Grid Group; the treatment by National Grid Group of such information
or material shall be governed by the terms of the letter agreement dated as of
December 21, 1998 between EUA and National Grid Group.
7.02 Proxy Statement. As soon as reasonably practicable after the
date of this Agreement, EUA shall prepare and file the Proxy Statement with the
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SEC. NEES and EUA shall cooperate with each other in the preparation of the
Proxy Statement and any amendment or supplement thereto, and EUA shall promptly
notify NEES of the receipt of any comments of the SEC with respect to the Proxy
Statement and of any requests by the SEC for any amendment or supplement thereto
or for additional information, and shall promptly provide to NEES copies of all
correspondence between EUA or any of its Representatives and the SEC with
respect to the Proxy Statement (except reports from financial advisors other
than with the consent of such financial advisors). Each of the parties hereto
shall furnish all information concerning itself which is required or customary
for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the
Proxy Statement and have due regard to any comments NEES may make in relation to
the Proxy Statement. EUA shall give NEES and its counsel the opportunity to
review the Proxy Statement and all responses to requests for additional
information by and replies to comments of the SEC before their being filed with,
or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best
efforts, after consultation with the other parties hereto, to respond promptly
to all such comments of and requests by the SEC. After obtaining the consent of
EUA, which consent shall not be unreasonably withheld, NEES may provide
information supplied to NEES by EUA to National Grid Group for inclusion of such
information in the Super Class 1 circular ("NGG Circular") to be issued to
shareholders of National Grid Group in connection with approval by such
shareholders of the National Grid Merger Agreement. NEES shall use its best
efforts to provide EUA with a draft of any portion of the NGG Circular with
information relating to EUA prior to the issuance of the NGG Circular.
7.03 Approval of Shareholders. EUA shall, through its Board of
Trustees, duly call, give notice of, convene and hold a meeting of its
shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the
approval of the Merger and other transactions contemplated hereby (the "EUA
Shareholders' Approval") as soon as reasonably practicable after the date
hereof; provided, however, subject to the fiduciary duties of its Board of
Trustees and the requirements of applicable law, EUA shall include in the Proxy
Statement the recommendation of the Board of Trustees of EUA that the
Shareholders of EUA approve the Merger and the other transactions contemplated
hereby, and shall use its reasonable best efforts to obtain such approval.
7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party
hereto shall file or cause to be filed with the Federal Trade Commission and the
Department of Justice any notifications required to be filed by its respective
"ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated
thereunder with respect to the Merger and other transactions contemplated
hereby. Such parties will use all commercially reasonable efforts to make such
filings in a timely manner and to respond on a timely basis to any requests for
additional information made by either of such agencies.
(b) Other Regulatory Approvals. Each party shall cooperate and
use its best efforts to promptly prepare and file all necessary applications,
notices, petitions, filings and other documents with, and to use all
commercially reasonable efforts to obtain all necessary permits, consents,
approvals and authorizations of, all Governmental Authorities necessary or
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advisable to obtain the EUA Required Statutory Approvals, the NEES Required
Statutory Approvals and the approvals of the state utility commissions referred
to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The
parties agree that they will consult with each other with respect to obtaining
the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have
primary responsibility for the preparation and filing of any related
applications, filings or other material with the SEC, the FERC, the NRC and
state utility commissions. EUA shall have the right to review and approve in
advance drafts of and final applications, filings and other material (including
material with respect to proposed settlements) submitted to or filed with the
SEC, the FERC, the NRC and state utility commissions or parties to such
proceedings before such Governmental Authority, which approval shall not be
unreasonably withheld or delayed.
(c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge
that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA
Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the
regulatory approvals (the "NEES-NGG Regulatory Approvals") required to
consummate the transactions contemplated by the National Grid Merger Agreement.
NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA
Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the
prosecution by National Grid Group and NEES of the proceedings relating to the
NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but
recognize that one or more of the NEES-EUA Regulatory Proceedings may be
consolidated with one or more of the NEES-NGG Regulatory Proceedings by the
relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA
reasonably apprised of the status of the NEES-NGG Regulatory Proceedings.
7.05 Employee Benefit Plans.
(a) For a period of twelve (12) months immediately following the
Closing Date, the compensation, benefits and coverage provided to those
non-union individuals who continue to be employees of the Surviving Entity (the
"Affected Employees") pursuant to employee benefit plans or arrangements
maintained by NEES or the Surviving Entity shall be, in the aggregate, not less
favorable (as determined by NEES and the Surviving Entity using reasonable
assumptions and benefit valuation methods) than those provided, in the
aggregate, to such Affected Employees immediately prior to the Closing Date. In
addition to the foregoing, NEES shall, or shall cause the Surviving Entity to,
pay any Affected Employee whose employment is terminated by NEES or the
Surviving Entity within twelve (12) months of the Closing Date a severance
benefit package equivalent to the severance benefit package that would be
provided under the NEES Standard Severance Plan as in effect on the date hereof.
(b) NEES shall, or shall cause the Surviving Entity to, give the
Affected Employees full credit for purposes of eligibility, vesting, benefit
accrual (including, without limitation, benefit accrual under any defined
benefit pension plans) and determination of the level of benefits under any
employee benefit plans or arrangements maintained by NEES or the Surviving
Entity in effect as of the Closing Date for such Affected Employees' service
with EUA or any Subsidiary of EUA (or any prior employer) to the same extent
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recognized by EUA or such Subsidiary immediately prior to the Closing Date. With
respect to any employee benefit plan or arrangement established by NEES, EUA or
the Surviving Entity after the Closing Date (the "Post Closing Plans"), service
shall be credited in accordance with the terms of such Post Closing Plans.
(c) NEES shall, or shall cause the Surviving Entity to, (i)
waive all limitations as to preexisting conditions, exclusions and waiting
periods with respect to participation and coverage requirements applicable to
the Affected Employees under any welfare benefit plan established to replace any
EUA welfare benefit plans in which such Affected Employees may be eligible to
participate after the Closing Date, other than limitations or waiting periods
that are already in effect with respect to such Affected Employees and that have
not been satisfied as of the Closing Date under any welfare plan maintained for
the Affected Employees immediately prior to the Closing Date, and (ii) provide
each Affected Employee with credit for any co-payments and deductibles paid
prior to the Closing Date in satisfying any applicable deductible or
out-of-pocket requirements under any welfare plans that such Affected Employees
are eligible to participate in after the Closing Date.
(d)(i) NEES shall, or shall cause the Surviving Entity and its
Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect
on the date hereof; provided, however, that this Section 7.05(d)(i) is not
intended to prevent NEES or the Surviving Entity from exercising their rights
with respect to all EUA Employee Benefit Plans solely in accordance with their
terms, including but not limited to the right to alter, terminate or otherwise
amend such EUA Employee Benefit Plans.
(ii) NEES shall, or shall cause the Surviving Entity and
its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, (A) all employment severance, consulting and
retention agreements or arrangements as in effect on the date hereof, as set
forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in
accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or
arrangements, the "EUA Employee Agreements" and the individuals who are parties
to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee
Benefit Plans in which such EUA Executives participate; provided, however, that
this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity
from exercising their rights with respect to the EUA Employee Agreements and the
EUA Employee Benefit Plans in which such EUA Executives participate, in each
case solely in accordance with their terms, including but not limited to the
right to alter, terminate or otherwise amend such EUA Employee Agreements and
EUA Employee Benefit Plans.
(e) Notwithstanding the foregoing, NEES and the Surviving Entity
and its subsidiaries shall neither be required to or prevented from merging
EUA's benefit plans, agreements, or arrangements into NEES or the Surviving
Entity and its subsidiaries benefit plans, agreements, or arrangements or from
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replacing EUA's benefit plans, agreements or arrangements with NEES or the
Surviving Entity and its subsidiaries benefit plans, agreements or arrangements.
7.06 Labor Agreements and Workforce Matters.
(a) Labor Agreements. NEES shall honor, or shall cause the
appropriate subsidiaries of the Surviving Entity to honor, all collective
bargaining agreements of EUA or its subsidiaries in effect as of the Effective
Time until their expiration; provided, however, that this undertaking is not
intended to prevent NEES or the Surviving Entity and its subsidiaries from
exercising their rights with respect to such collective bargaining agreements
and in accordance with their terms, including any right to amend, modify,
suspend, revoke or terminate any such contract, agreement, collective bargaining
agreement or commitment or portion thereof.
(b) Workforce Matters. Subject to applicable law and obligations
under applicable collective bargaining agreements, for a period of 2 years
following the Effective Time, any reductions in workforce in respect of
employees of the Surviving Entity and its Subsidiaries shall be made on a fair
and equitable basis as determined by the Surviving Entity, with due
consideration to prior experience and skills, and any employee whose employment
is terminated or job is eliminated during such period shall be entitled to
participate on a fair and equitable basis as determined by NEES or the Surviving
Entity in the job opportunity and employment placement programs offered by NEES
or the Surviving Entity or any of their Subsidiaries for which they are
eligible. Any workforce reductions carried out following the Effective Time by
the Surviving Entity and its Subsidiaries shall be done in accordance with all
applicable collective bargaining agreements and all laws and regulations
governing the employment relationship and termination thereof including, without
limitation, the Worker Adjustment and Retraining Notification Act, and the
regulations promulgated thereunder, and any comparable state or local law.
7.07 Post Merger Operations.
(a) NEES Advisory Board. If the Merger is consummated, then,
promptly following the closing of the merger contemplated by the National Grid
Merger Agreement, NEES shall take such action as is necessary to cause all of
the members of the Board of Directors of EUA to be appointed to serve on the
advisory board to be formed pursuant to Section 7.07(e) of the National Grid
Merger Agreement.
(b) Charities. The parties agree that provision of charitable
contribution and community support within the New England region serves a number
of important goals. After the Effective Time, NEES intends to cause the
Surviving Entity to provide charitable contributions and community support
within the New England region at annual levels substantially comparable to the
annual level of charitable contributions and community support provided,
directly or indirectly, by EUA and its public utility subsidiaries within the
New England region during 1998.
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7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a)
that neither it nor any of its Subsidiaries shall, and it shall use its best
efforts to cause its Representatives (as defined in Section 10.10) not to,
knowingly initiate, solicit or encourage, directly or indirectly, any inquiries
or any proposal or offer (including, without limitation, any proposal or offer
to its Shareholders) with respect to a merger, consolidation or other business
combination including EUA or any of its significant Subsidiaries (as defined in
Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than
EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or
similar transaction (including, without limitation, a tender or exchange offer)
involving the purchase of (i) all or any significant portion of the assets of
EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the
outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the
capital stock of any EUA Significant Subsidiary (any such proposal or offer
being hereinafter referred to as an "Alternative Proposal"), or engage in any
negotiations concerning, or provide any confidential information or data to, or
have any other discussions with, any person or group relating to an Alternative
Proposal, or otherwise knowingly facilitate any effort or attempt to make or
implement an Alternative Proposal other than from NEES and its affiliates; (b)
that it will immediately cease and cause to be terminated any existing
activities, discussions or negotiations with any parties with respect to any
Alternative Proposal; and (c) that it will notify NEES immediately if any such
inquiries, proposals or offers are received by, any such information is
requested from, or any such negotiations or discussions are sought to be
initiated or continued with, it or any of such persons; provided, however, that,
prior to receipt of the EUA Shareholders' Approval, nothing contained in this
Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing
information to (but only pursuant to a confidentiality agreement in customary
form and having terms and conditions no less favorable to EUA than the
Confidentiality Agreement (as defined in Section 7.01)) or entering into
discussions or negotiations with any person or group that makes an unsolicited
Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees
of EUA, based upon advice of outside counsel with respect to fiduciary duties,
determines in good faith that such action is necessary for the Board of Trustees
to act in a manner consistent with its fiduciary duties to Shareholders under
applicable law, (B) the Board of Trustees of EUA has reasonably concluded in
good faith (after consultation with its financial advisors) that the person or
group making such Alternative Proposal will have adequate sources of financing
to consummate such Alternative Proposal and that such Alternative Proposal is
likely to be more favorable to EUA's shareholders than the Merger, (C) prior to
furnishing such information to, or entering into discussions or negotiations
with, such person or group, EUA provides written notice to NEES to the effect
that it is furnishing information to, or entering into discussions or
negotiations with, such person or group, which notice shall identify such person
or group and the material terms of the Alternative Proposal in reasonable
detail, and (D) EUA keeps NEES promptly informed of the status and all material
information with respect to any such discussions or negotiations; and (ii) to
the extent required, complying with Rule 14e-2 promulgated under the Exchange
Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall
(x) permit EUA to terminate this Agreement (except as specifically provided in
Article IX), (y) permit EUA to enter into any agreement with respect to an
Alternative Proposal for so long as this Agreement remains in effect (it being
agreed that for so long as this Agreement remains in effect, EUA shall not enter
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into any agreement with any person or group that provides for, or in any way
knowingly facilitates, an Alternative Proposal (other than a confidentiality
agreement under the circumstances described above)), or (z) affect any other
obligation of EUA under this Agreement.
7.09 Directors' and Officers' Indemnification and Insurance.
(a) Indemnification. To the extent, if any, not provided by an
existing right of indemnification or other agreement or policy, from and after
the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the
fullest extent permitted by applicable law, indemnify, defend and hold harmless
each person who is now, or has been at any time prior to the date hereof, or who
becomes prior to the Effective Time, (x) an officer, trustee or director or (y)
an employee covered as of the date hereof (to the extent of the coverage
extended as of the date hereof) of EUA or any Subsidiary of EUA (each an
"Indemnified Party," and collectively, the "Indemnified Parties") against (i)
all losses, expenses (including reasonable attorney's fees and expenses),
claims, damages or liabilities or, subject to the first proviso of the next
succeeding sentence, amounts paid in settlement, arising out of actions or
omissions occurring at or prior to the Effective Time (and whether asserted or
claimed prior to, at or after the Effective Time) that are, in whole or in part,
based on or arising out of the fact that such person is or was a director,
trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified
Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based
on or arise out of or pertain to the transactions contemplated by this
Agreement, in each case, to the extent permitted by the EUA Trust Agreement or
the indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter. In the event of any such loss, expense, claim, damage or liability
(whether or not arising before the Effective Time), (i) NEES shall, or shall
cause the Surviving Entity to, pay the reasonable fees and expenses of counsel
selected by the Indemnified Parties, which counsel shall be reasonably
satisfactory to NEES or the Surviving Entity, as appropriate, promptly after
statements therefor are received and otherwise advance to such Indemnified Party
upon request, reimbursement of documented expenses reasonably incurred, in
either case to the extent not prohibited by the EUA Trust Agreement or the
indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter upon receipt of an undertaking by or on behalf of such director, trustee
or officer to repay such amounts as and to the extent required by the EUA Trust
Agreement or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of
any such matter and (iii) any determination required to be made with respect to
whether an Indemnified Party's conduct complies with the standards set forth
under the EUA Trust Agreement or the indemnification agreements set forth in
Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation
or by-laws or similar governing documents of the Surviving Entity shall be made
by independent counsel mutually acceptable to the Surviving Entity and the
Indemnified Party; provided, however, that the Surviving Entity shall not be
liable for any settlement effected without its written consent (which consent
shall not be unreasonably withheld) and provided further that no indemnification
shall be made if such indemnification is prohibited by the EUA Trust Agreement
or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter.
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(b) Insurance. For a period of six years after the Effective
Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be
maintained in effect an extended reporting period for current policies of
directors' and officers' liability insurance for the benefit of such persons who
are currently covered by such policies of EUA on terms no less favorable than
the terms of such current insurance coverage or (ii) shall provide tail coverage
for such persons which provides such persons with coverage for a period of six
years for acts prior to the Effective Time on terms no less favorable than the
terms of such current insurance coverage.
(c) Successors. In the event the Surviving Entity or any of its
successors or assigns (i) consolidates with or merges into any other person or
entity and shall not be the continuing or surviving corporation or entity of
such consolidation or merger or (ii) transfers all or substantially all of its
properties and assets to any person or entity, then and in either such case,
proper provisions shall be made so that the successors and assigns of the
Surviving Entity, as applicable, shall assume the obligations set forth in this
Section 7.09.
(d) Survival of Indemnification. To the fullest extent permitted
by law, from and after the Effective Time, all rights to indemnification as of
the date hereof in favor of the employees, agents, directors, trustees and
officers of EUA and EUA's Subsidiaries with respect to their activities as such
prior to the Effective Time, as provided in the EUA Trust Agreement or the
respective certificates of incorporation and by-laws or similar governing
documents in effect on the date hereof, or otherwise in effect on the date
hereof, shall survive the Merger and shall continue in full force and effect for
a period of not less than six years from the Effective Time.
(e) Benefit. The provisions of this Section 7.09 are intended to
be for the benefit of, and shall be enforceable by, each Indemnified Party, his
or her heirs and his or her representatives.
(f) Amendment of the EUA Trust Agreement. NEES shall not, and
shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement
to in any way limit the indemnification provided to the Indemnified Parties
under this Section 7.09.
7.10 Expenses. Except as set forth in Section 9.03, whether or not
the Merger is consummated, all costs and expenses incurred in connection with
the Merger and other transactions contemplated hereby shall be paid by the party
incurring such cost or expense, except that the filing fees in connection with
the filings required under the HSR Act and the 1935 Act shall be paid by NEES.
7.11 Brokers or Finders. EUA represents, as to itself and its
affiliates, that no agent, broker, investment banker, financial advisor or other
firm or person is or will be entitled to any broker's, finder's or investment
banker's fee or any other commission or similar fee in connection with the
Merger and other transactions contemplated by this Agreement except Salomon
Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance
with EUA's agreement with such firm, and EUA shall indemnify and hold NEES
harmless from and against any and all claims, liabilities or obligations with
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respect to any other such fee or commission or expenses related thereto asserted
by any person on the basis of any act or statement alleged to have been made by
EUA or its affiliates.
7.12 Anti-Takeover Statutes. If any "fair price", "moratorium",
"business combination", "control share acquisition" or other form of
anti-takeover statute or regulation shall become applicable to the Merger or
other transactions contemplated hereby, EUA and the members of the Board of
Trustees of EUA shall grant such approvals and take such actions consistent with
their fiduciary duties and in accordance with applicable law as are reasonably
necessary so that the Merger and other transactions contemplated hereby may be
consummated as promptly as practicable on the terms contemplated hereby and
otherwise act to eliminate or minimize the effects of such statute or regulation
on the Merger and other transactions contemplated hereby.
7.13 Public Announcements. Except as otherwise required by law or the
rules of any applicable securities exchange or national market system or any
other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA
will not, and will not permit any of their respective Subsidiaries or
Representatives to, issue or cause the publication of any press release or make
any other public announcement with respect to the Merger and other transactions
contemplated by this Agreement without the consent of the other party, which
consent shall not be unreasonably withheld. NEES and EUA will cooperate with
each other in the development and distribution of all press releases and other
public announcements with respect to the Merger and other transactions
contemplated hereby, and will furnish the other with drafts of any such releases
and announcements as far in advance as practicable.
7.14 Restructuring of the Merger. It may be preferable to effectuate
a business combination between NEES and EUA by means of an alternative structure
to the Merger. Accordingly, if, prior to satisfaction of the conditions
contained in Article VIII hereto, NEES proposes the adoption of an alternative
structure that otherwise substantially preserves for NEES and EUA the economic
benefits of the Merger and will not materially delay the consummation thereof,
then the parties shall use their respective best efforts to effect a business
combination among themselves by means of a mutually agreed upon structure other
than the Merger that so preserves such benefits; provided, however, that prior
to closing any such restructured transaction, all material third party and
Governmental Authority declarations, filings, registrations, notices,
authorizations, consents or approvals necessary for the effectuation of such
alternative business combination shall have been obtained and all other
conditions to the parties' obligations to consummate the Merger and other
transactions contemplated hereby, as applied to such alternative business
combination, shall have been satisfied or waived.
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ARTICLE VIII
CONDITIONS
8.01 Conditions to Each Party's Obligation to Effect the Merger. The
respective obligation of each party to effect the Merger and other transactions
contemplated hereby is subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following conditions:
(a) Shareholder Approval. EUA Shareholders' Approval shall have
been obtained.
(b) HSR Act. Any waiting period (and any extension thereof)
applicable to the consummation of the Merger under HSR shall have expired or
been terminated.
(c) Injunctions or Restraints. No court of competent
jurisdiction or other competent Governmental Authority shall have enacted,
issued, promulgated, enforced or entered any law or order (whether temporary,
preliminary or permanent) which is then in effect and has the effect of making
illegal or otherwise restricting, preventing or prohibiting consummation of the
Merger or other transactions contemplated hereby.
(d) Governmental and Regulatory and Other Consents and
Approvals. The NEES Required Statutory Approvals and EUA Required Statutory
Approvals shall have been obtained prior to the Effective Time, and shall have
become Final Orders (as hereinafter defined). The Final Orders shall not,
individually or in the aggregate, impose terms and conditions that (i) could
reasonably be expected to have an EUA Material Adverse Effect; (ii) could
reasonably be expected to have a NEES Material Adverse Effect; or (iii)
materially impair the ability of the parties to complete the Merger. The parties
shall have received Final Orders from the Massachusetts Department of
Telecommunications and Energy and the Rhode Island Public Utilities Commission
pertaining to the recovery of costs (including, without limitation, transaction
premium and integration costs) associated with the Merger that are materially
consistent with existing policy and previous orders of such agencies. "Final
Order" for all purposes of this Agreement means action by the relevant
regulatory authority which has not been reversed, stayed, enjoined, set aside,
annulled or suspended with respect to which any waiting period prescribed by law
before the Merger and other transactions contemplated hereby may be consummated
has expired, and as to which all conditions to be satisfied before the
consummation of such transactions prescribed by law, regulation or order have
been satisfied.
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger.
The obligation of NEES and LLC to effect the Merger and other transactions
contemplated hereby is further subject to the satisfaction or waiver at or prior
to the Closing, of each of the following additional conditions (all or any of
which may be waived in whole or in part by NEES and LLC in the sole discretion):
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(a) Representations and Warranties. The representations and
warranties made by EUA in this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "EUA Material Adverse Effect", shall be true and correct as so
made as of the Closing Date as though so made on and as of the Closing Date,
except to the extent expressly given as of a specified date, except where the
failure of such representations and warranties to be true and correct as so made
does not have and could not reasonably be expected to have, individually or in
the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to
NEES a certificate, dated the Closing Date and executed in the name and on
behalf of EUA by its Chairman of the Board, President or any Executive or Senior
Vice President, to such effect.
(b) Performance of Obligations. EUA shall have performed and
complied with, in all material respects, each agreement, covenant and obligation
required by this Agreement to be so performed or complied with by EUA at or
prior to the Closing, and EUA shall have delivered to NEES a certificate, dated
the Closing Date and executed in the name and on behalf of EUA by its Chairman
of the Board, President or any Executive or Senior Vice President, to such
effect.
(c) Material Adverse Effect. No EUA Material Adverse Effect
shall have occurred and there shall exist no facts or circumstances which in the
aggregate could reasonably be expected to have an EUA Material Adverse Effect.
(d) EUA Required Consents. All EUA Required Consents shall have
been obtained by EUA, except where the failure to receive such EUA Required
Consents could not reasonably be expected to (i) have an EUA Material Adverse
Effect, or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
8.03 Conditions to Obligation of EUA to Effect the Merger. The
obligation of EUA to effect the Merger and other transactions contemplated
hereby is further subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following additional conditions (all or any of which may
be waived in whole or in part by EUA in its sole discretion):
(a) Representations and Warranties. The representations and
warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07,
5.08 and 5.09 of this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "NEES Material Adverse Effect," shall be true and correct as so
made as of the Closing Date, except to the extent expressly given as of a
specified date and except where the failure of such representations and
warranties to be so true and correct as so made does not have and could not
reasonably be expected to have, individually or in the aggregate, a NEES
Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC
shall each have delivered to EUA a certificate, dated the Closing Date and
executed in the name and on behalf of NEES by any director of NEES and in the
name and on behalf of LLC by a member of its management committee its Chairman
of the Board, President or any Executive or Senior Vice President to such
effect.
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(b) NEES Required Consents. All NEES Required Consents shall
have been obtained by NEES, except where the failure to receive such NEES
Required Consents could not reasonably be expected to (i) have a NEES Material
Adverse Effect or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
(c) Performance of Obligations. NEES and LLC shall have
performed and complied with, in all material respects, each agreement, covenant
and obligation required by this Agreement to be so performed or complied with by
NEES or LLC at or prior to the Closing, and NEES and LLC shall each have
delivered to EUA a certificate, dated the Closing Date and executed in the name
and on behalf of NEES by its Chairman of the Board, President or any Executive
or Senior Vice President, or on behalf of LLC by a member of its management
committee to such effect.
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER
9.01 Termination. This Agreement may be terminated, and the Merger
and other transactions contemplated hereby may be abandoned, at any time prior
to the Effective Time, whether prior to or after EUA Shareholders' Approval
(except as otherwise provided in Section 9.01(c) below):
(a) By mutual written agreement of the Board of Directors of
NEES and Board of Trustees of EUA, respectively;
(b) By EUA or NEES, by written notice to the other, if the
Closing Date shall not have occurred on or before December 31, 1999 (the
"Initial Termination Date"); provided, however, that the right to terminate the
Agreement under this Section 9.01(b) shall not be available to any party whose
failure to fulfill any obligation under this Agreement has been the cause of, or
resulted in, the failure of the Effective Time to occur on or before such date;
and provided, further, that if on the Initial Termination Date the conditions to
the Closing set forth in Section 8.01(d) shall not have been fulfilled but all
other conditions to the Closing shall be fulfilled or shall be capable of being
fulfilled, then the Initial Termination Date shall be extended for four (4)
months beyond the Initial Termination Date (the "Extended Termination Date");
(c) By NEES, by written notice to EUA, if EUA Shareholders'
Approval shall not have been obtained at a duly held meeting of such
Shareholders, including any adjournments thereof;
(d) By EUA or NEES, if any applicable state or federal law or
applicable law of a foreign jurisdiction or any order, rule or regulation is
adopted or issued that has the effect, as supported by the written opinion of
outside counsel for such party, of prohibiting the Merger or other transactions
contemplated hereby, or if any court of competent jurisdiction or any
Governmental Authority shall have issued a nonappealable final order, judgment
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or ruling or taken any other action having the effect of permanently
restraining, enjoining or otherwise prohibiting the Merger or other transactions
contemplated hereby (provided that the right to terminate this Agreement under
this Section 9.01(d) shall not be available to any party that has not defended
such lawsuit or other legal proceeding (including seeking to have any stay or
temporary restraining order entered by any court or other Governmental Authority
vacated or reversed)).
(e) By EUA upon ten (10) days' prior notice to NEES if the Board
of Trustees of EUA determines in good faith, that termination of this Agreement
is necessary for the Board of Trustees of EUA to act in a manner consistent with
its fiduciary duties to Shareholders under applicable law by reason of an
unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B)
of Section 7.08 having been made; provided that
(A) The Board of Trustees of EUA shall determine based
on advice of outside counsel with respect to the Board of
Trustees' fiduciary duties that notwithstanding a binding
commitment to consummate an agreement of the nature of this
Agreement entered into in the proper exercise of its applicable
fiduciary duties, and notwithstanding all concessions which may
be offered by NEES in negotiation entered into pursuant to clause
(B) below, it is necessary pursuant to such fiduciary duties that
the trustees reconsider such commitment as a result of such
Alternative Proposal, and
(B) prior to any such termination, EUA shall, and
shall cause its respective financial and legal advisors to,
negotiate with NEES to make such adjustments in the terms and
conditions of this Agreement as would enable EUA to proceed with
the Merger or other transactions contemplated hereby on such
adjusted terms;
and provided further that EUA's ability to terminate this Agreement pursuant to
this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES
of any amounts owed by it pursuant to Section 9.03(a);
(f) By EUA, by written notice to NEES, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of NEES hereunder (other than a breach
described in clause (ii)), and such breach shall not have been remedied within
twenty (20) days after receipt by NEES of notice in writing from EUA, specifying
the nature of such breach and requesting that it be remedied; or (ii) NEES shall
fail to deliver or cause to be delivered the amount of cash to the Paying Agent
required pursuant to Section 2.02(a) at a time when all conditions to NEES's
obligation to close have been satisfied or otherwise waived in writing by NEES.
(g) By NEES, by written notice to EUA, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of EUA hereunder, and such breach shall not
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have been remedied within twenty (20) days after receipt by EUA of notice in
writing from NEES, specifying the nature of such breach and requesting that it
be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify
in any manner adverse to NEES its approval of the Merger and other transactions
contemplated hereby or its recommendation to its shareholders regarding the
approval of this Agreement, the Merger and other transactions contemplated
hereby, (B) shall approve or recommend or take no position with respect to an
Alternative Proposal or (C) shall resolve to take any of the actions specified
in clause (A) or (B).
9.02 Effect of Termination. If this Agreement is validly terminated
by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith
become null and void and there shall be no liability or obligation on the part
of either EUA or NEES (or any of their respective Representatives or
affiliates), except that the provisions of this Section 9.02, Sections 7.10,
7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply
following any such termination.
9.03 Termination Fees. (a) In the event that (i) this Agreement is
terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall
have made an Alternative Proposal that has not been withdrawn and this Agreement
is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B)
by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a
definitive agreement with respect to such Alternative Proposal is executed
within two years after such termination, then EUA shall pay to NEES, by wire
transfer of same day funds, either on the date contemplated in Section 9.01(e)
if applicable, or otherwise, within five (5) business days after such
termination, a termination fee of $20 million, plus an amount equal to all
documented out-of-pocket expenses and fees incurred by NEES arising out of, or
in connection with or related to, the Merger and other transactions contemplated
hereby, not in excess of $5 million in the aggregate.
(b) In the event that this Agreement is terminated by either
NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i)
the conditions to the Closing set forth in Section 8.01(d) shall not have been
fulfilled, (ii) if the date of termination is any date other than a date which
is on or after the Extended Termination Date, all conditions contained in
Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or
are capable of being fulfilled as of such date, and (iii) the merger
contemplated by the National Grid Merger Agreement has not yet been consummated,
then NEES shall pay to EUA, by wire transfer of same day funds, within five (5)
business days after such termination, a termination fee of $10 million, plus an
amount equal to all documented out-of-pocket expenses and fees incurred by EUA
arising out of, or in connection with or related to, the Merger and other
transactions contemplated hereby, not in excess of $5 million in the aggregate.
(c) Nature of Fees. The parties agree that the agreements
contained in this Section 9.03 are an integral part of the Merger and the other
transactions contemplated hereby and constitute liquidated damages and not a
penalty. The parties further agree that if any party is or becomes obligated to
pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive
such termination fee shall be the sole remedy of the other party with respect to
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the facts and circumstances giving rise to such payment obligation. If this
Agreement is terminated by a party as a result of a willful breach of a
representation, warranty, covenant or agreement by the other party, including a
termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue
any remedies available to it at law or in equity and shall be entitled to
recover any additional amounts thereunder. Notwithstanding anything to the
contrary contained in this Section 9.03, if one party fails to promptly pay to
the other any fee or expense due under this Section 9.03, in addition to any
amounts paid or payable pursuant to such Section, the defaulting party shall pay
the costs and expenses (including legal fees and expenses) in connection with
any action, including the filing of any lawsuit or other legal action, taken to
collect payment, together with interest on the amount of any unpaid fee at the
publicly announced prime rate of Citibank, N.A. from the date such fee was
required to be paid.
9.04 Amendment. This Agreement may be amended, supplemented or
modified by action taken by or on behalf of the Board of Directors of NEES or
the Board of Trustees of EUA at any time prior to the Effective Time, whether
prior to or after EUA Shareholders' Approval shall have been obtained, but after
such adoption and approval only to the extent permitted by applicable law. No
such amendment, supplement or modification shall be effective unless set forth
in a written instrument duly executed and delivered by or on behalf of each
party hereto.
9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by
action taken by or on behalf of its Board of Directors or Board of Trustees,
respectively, may to the extent permitted by applicable law (i) extend the time
for the performance of any of the obligations or other acts of the other parties
hereto, (ii) waive any inaccuracies in the representations and warranties of the
other parties hereto contained herein or in any document delivered pursuant
hereto or (iii) waive compliance with any of the covenants, agreements or
conditions of the other parties hereto contained herein. No such extension or
waiver shall be effective unless set forth in a written instrument duly executed
by or on behalf of the party extending the time of performance or waiving any
such inaccuracy or non-compliance. No waiver by any party of any term or
condition of this Agreement, in any one or more instances, shall be deemed to be
or construed as a waiver of the same or any other term or condition of this
Agreement on any future occasion.
ARTICLE X
GENERAL PROVISIONS
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements. The representations, warranties, covenants and agreements contained
in this Agreement or in any instrument delivered pursuant to this Agreement
shall not survive the Merger but shall terminate at the Effective Time, except
for the agreements contained in Article I and Article II, in Sections 7.05,
7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective
Time.
10.02 Notices. All notices, requests and other communications
hereunder must be in writing and will be deemed to have been duly given only if
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delivered personally or by facsimile transmission or sent by overnight courier
(providing proof of delivery) to the parties at the following addresses or
facsimile numbers:
If to NEES or LLC, to:
New England Electric System
25 Research Drive
Westborough, MA 01582
Attn: Richard P. Sergel
President and Chief Executive Officer
Telephone: (508) 389-2764
Facsimile: (508) 366-5498
with a copy to:
Skadden, Arps, Slate, Meagher & Flom LLP
919 Third Avenue
New York, NY 10022
Attn: Sheldon S. Adler, Esq.
Telephone: (212) 735-3000
Facsimile: (212) 735-2000
If to EUA, to:
Eastern Utilities Associates
One Liberty Square
Boston, MA 02109
Attn: Donald G. Pardus
Chairman and Chief Executive Officer
Telephone: (617) 357-9590
Facsimile: (617) 357-7320
with a copy to:
Winthrop, Stimson, Putnam & Roberts
1 Battery Park Plaza
New York, NY 10004
Attn: David P. Falck
Telephone: (212) 858-1000
Facsimile: (212) 858-1500
All such notices, requests and other communications will (i) if
delivered personally to the address as provided in this Section, be deemed given
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upon delivery, (ii) if delivered by facsimile transmission to the facsimile
number as provided in this Section, be deemed given when sent, provided that the
facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if
delivered by mail in the manner described above to the address as provided in
this Section, be deemed given one business day after delivery (in each case
regardless of whether such notice, request or other communication is received by
any other person to whom a copy of such notice, request or other communication
is to be delivered pursuant to this Section). Any party from time to time may
change its address, facsimile number or other information for the purpose of
notices to that party by giving notice specifying such change to the other
parties hereto.
10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement
supersedes all prior discussions and agreements, both written and oral, among
the parties hereto with respect to the subject matter hereof, other than the
Confidentiality Agreement, which shall survive the execution and delivery of
this Agreement in accordance with its terms, and contains, together with the
Confidentiality Agreement, the sole and entire agreement among the parties
hereto with respect to the subject matter hereof.
(b) The EUA Disclosure Letter, the NEES Disclosure Letter and
any Exhibit attached to this Agreement and referred to herein are hereby
incorporated herein and made a part hereof for all purposes as if fully set
forth herein.
10.04 No Third Party Beneficiary. The terms and provisions of this
Agreement are intended solely for the benefit of each party hereto and their
respective successors or permitted assigns, and except as provided in Article II
and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit
of the persons entitled to therein, and may be enforced by any of such persons),
it is not the intention of the parties to confer third-party beneficiary rights
upon any other person.
10.05 No Assignment; Binding Effect. Neither this Agreement nor any
right, interest or obligation hereunder may be assigned, in whole or in part, by
operation of law or otherwise, by any party hereto without the prior written
consent of the other parties hereto and any attempt to do so will be void,
except that LLC may assign any or all of its rights, interests and obligations
hereunder to another direct or indirect wholly owned Subsidiary of NEES,
provided that any such Subsidiary agrees in writing to be bound by all of the
terms, conditions and provisions contained herein and provided further that such
assignment (i) does not require a greater vote for EUA's Shareholder Approval,
(ii) does not require a subsequent vote following EUA's Shareholders Meeting, or
(iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES,
as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required
Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals,
or the NEES Required Consents. Subject to the preceding sentence, this Agreement
is binding upon, inures to the benefit of and is enforceable by the parties
hereto and their respective successors and assigns.
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10.06 Headings. The headings used in this Agreement have been
inserted for convenience of reference only and do not define, modify or limit
the provisions hereof.
10.07 Invalid Provisions. If any provision of this Agreement is held
to be illegal, invalid or unenforceable under any present or future law or
order, and if the rights or obligations of any party hereto under this Agreement
will not be materially and adversely affected thereby, (i) such provision will
be fully severable, (ii) this Agreement will be construed and enforced as if
such illegal, invalid or unenforceable provision had never comprised a part
hereof, and (iii) the remaining provisions of this Agreement will remain in full
force and effect and will not be affected by the illegal, invalid or
unenforceable provision or by its severance herefrom.
10.08 Governing Law. This Agreement shall be governed by and
construed in accordance with the laws of the Commonwealth of Massachusetts.
10.09 Enforcement of Agreement. The parties hereto agree that
irreparable damage would occur in the event that any of the provisions of this
Agreement was not performed in accordance with its specified terms or was
otherwise breached. It is accordingly agreed that the parties shall be entitled
to an injunction or injunctions to prevent breaches of this Agreement and to
enforce specifically the terms and provisions hereof in any court of competent
jurisdiction, this being in addition to any other remedy to which they are
entitled at law or in equity.
10.10 Certain Definitions. As used in this Agreement:
(a) except as provided in Section 4.14, the term "affiliate," as
applied to any person, shall mean any other person directly or indirectly
controlling, controlled by, or under common control with, that person; for
purposes of this definition, "control" (including, with correlative meanings,
the terms "controlling," "controlled by" and "under common control with"), as
applied to any person, means the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of that
person, whether through the ownership of voting securities, by contract or
otherwise;
(b) a person will be deemed to "beneficially" own securities if
such person would be the beneficial owner of such securities under Rule 13d-3
under the Exchange Act, including securities which such person has the right to
acquire (whether such right is exercisable immediately or only after the passage
of time);
(c) the term "business day" means a day other than Saturday,
Sunday or any day on which banks located in the Massachusetts are authorized or
obligated to close;
(d) the term "knowledge" or any similar formulation of
"knowledge" shall mean, with respect to any party hereto, the actual knowledge
after due inquiry of the executive officers of NEES and its Subsidiaries or EUA
and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES
Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided
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that as used in Section 4.13 the term "knowledge" shall also include the
knowledge of the environmental, health and safety personnel of EUA;
(e) the term "person" shall include individuals, corporations,
partnerships, trusts, limited liability companies, other entities and groups
(which term shall include a "group" as such term is defined in Section 13(d)(3)
of the Exchange Act);
(f) the "Representatives" of any entity shall have the same
meaning as set forth in the Confidentiality Agreement;
(g) the term "Subsidiary" means any corporation or other entity,
whether incorporated or unincorporated, in which such party directly or
indirectly owns at least a majority of the voting power represented by the
outstanding capital stock or other voting securities or interests having voting
power under ordinary circumstances to elect a majority of the directors or
similar members of the governing body, or otherwise to direct the management and
policies, or such corporation or entity.
10.11 Counterparts. This Agreement may be executed in any number of
counterparts, each of which will be deemed an original, but all of which
together will constitute one and the same instrument and will become effective
when one or more counterparts have been signed by each party and delivered to
the other parties.
10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE
FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY
JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING
TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON
CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO
REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY
OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK
TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER
PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER
THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
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IN WITNESS WHEREOF, each party hereto has caused this Agreement to be
signed by its officer thereunto duly authorized as of the date first above
written.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability therefor.
EASTERN UTILITIES ASSOCIATES
By: /s/ Donald G. Pardus
-----------------------------------
Name: Donald G. Pardus
Title: Chairman
The name "Eastern Utilities Associates" is the designation of the Trustees of
EUA for the time being in their collective capacity but not personally, under a
Declaration of Trust dated April 2, 1928, as amended, a copy of which amended
Declaration of Trust has been filed in the office of the Secretary of The
Commonwealth of Massachusetts and elsewhere as required by law; and all persons
dealing with EUA must look solely to the trust property for the enforcement of
any claim against EUA, as neither the Trustees nor the officers or shareholders
of EUA assume any personal liability for obligations entered into on behalf of
EUA.
RESEARCH DRIVE LLC
By: /s/ John G. Cochrane
-----------------------------------
Name: John G. Cochrane
Title: Manager
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Tab 2
CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
CONSENT AGREEMENT
This Consent Agreement (the "Agreement") is entered into as of
February 1, 1999 between The National Grid Group, p1c, a public limited company
incorporated under the laws of England and Wales ("NGG") and New England
Electric System, a Massachusetts business trust ("NEES").
WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly
owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as
of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC
will merge (the "Merger") with and into NEES with NEES being the surviving
entity and becoming a wholly owned subsidiary of NGG;
WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business
Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement
and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger
Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC
with and into EUA with EUA being the surviving entity and becoming a wholly
owned subsidiary of NEES; and
WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is
required to obtain the consent of NGG before entering into the EUA Merger
Agreement and with respect to certain actions relating to the consummation of
the transactions set forth therein.
NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties hereby agree as
follows:
1. Consent to EUA Merger Agreement. Subject to the terms and
conditions of this Consent, NGG hereby consents to NEES entering into the EUA
Merger Agreement with EUA in the form set forth in Exhibit A and agrees that,
subject to the immediately following sentence, the consummation by NEES of the
transactions contemplated by the EUA Merger Agreement in accordance with the
term thereof shall not constitute a breach by NEES of the terms of the Merger
Agreement. NEES and NGG acknowledge that the financing necessary to consummate
the EUA Merger was not contemplated when NEES and NGG agreed to the limitations
set forth in Article VI of the Merger Agreement and NGG consents to such
financing provided that such financing is consistent with the financing
parameters set forth on Exhibit B hereto. NGG also consents to the formation and
<PAGE>
capitalization of Research Drive LLC by NEES for the purpose of effecting the
EUA Merger as contemplated in the EUA Merger Agreement.
2. Access to Information. Subject to the following sentence, NEES
hereby agrees to provide NGG with reasonable access to any information it
receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to
consult with NGG on a regular basis concerning the status of EUA and the EUA
Merger. NGG hereby acknowledges that any such material that is "Evaluation
Material" (as such term is defined in the letter agreement dated as of December
21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be
governed by the terms of the Confidentiality Agreement.
3. Regulatory Filings. NEES hereby agrees that NGG shall have the
right to review in advance, and that NEES will consult with NGG and give due
regard to NGG's views concerning, any applications, notices, petitions, filings
and other documents filed with any Governmental Authority (as defined in the EUA
Merger Agreement) in connection with the EUA Merger which could reasonably be
expected to have a material adverse effect on NGG's or NEES' ability to
consummate the Merger or which could reasonably be expected to adversely affect
in any material manner any material benefit of the Merger to NGG or NEES.
4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will
not, without the prior written consent of NGG, amend or modify the EUA Merger
Agreement in any material respect, including, without limitation, amend or
otherwise modify any provision of the EUA Merger Agreement providing for or
relating to the amount, type or structure of the Merger Consideration (as
defined in the EUA Merger Agreement) or agree to any additional or different
amount, type or structure for the Merger Consideration (as so defined).
5. Acknowledgment. NGG and NEES acknowledge and agree that the
covenants set forth in Article VI of the Merger Agreement do not reflect the
operations of EUA if the EUA Merger is consummated prior to the Effective Time
(as defined in the Merger Agreement). In the event that the EUA Merger is
consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate
in good faith to make appropriate modifications to such covenants set forth in
Section 6.01 of the Merger Agreement to reflect the operations of EUA.
6. Termination and Amendment. This Consent Agreement and the
obligations of NEES hereunder shall terminate upon the earlier to occur of (i)
the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the
Merger, in each case without any further action by the parties hereto. Except as
<PAGE>
provided in the preceding sentence, this Consent can not be terminated or
amended in any material respect prior to the termination of the EUA Merger
Agreement without the prior written consent of EUA. The foregoing sentence is
intended for the benefit of EUA and may be enforced by EUA.
7. Notices. NEES hereby agrees to provide NGG with copies of all
notices and other communications it sends to EUA and all notices and other
communications it receives from EUA under the EUA Merger Agreement. All notices
and other communications provided under this Agreement must be in writing and
shall be given in the same manner and to the same parties as set forth in
Section 10.02 of the Merger Agreement.
8. Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
9. Governing Law and Waiver of Jury Trial. This Agreement shall be
governed by and construed in accordance with the laws of the State of New York
applicable to a contract executed and performed in such State, without giving
effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO
THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL
BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR
RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER
THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR
ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH
OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING
WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN
INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS
AND CERTIFICATIONS IN THIS SECTION.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: /s/ Fiona B. Smith
-----------------------------------
Name: Fiona B. Smith
Title: Company Secretary
NEW ENGLAND ELECTRIC SYSTEM
By: ___________________________
Name:
Title:
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: ______________________________
Name:
Title:
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES
(not legible)
<PAGE>
EXHIBIT B - Financing Parameters
Financing will be in an amount of up to $630 M provided through a
group of banks. The financing (i) will be prepayable, (ii) will have a term not
to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv)
will have other terms and conditions usual and customary for transactions of
this nature.
<PAGE>
The Narragansett Electric Company,
Blackstone Valley Electric Company, and
Newport Electric Corporation
Rate Plan Filing in Support of Merger
Volume 1
Filing Letter and
Testimony and Exhibits of:
Michael E. Jesanis
Robert G. Powderly
Lawrence J. Reilly
David M. Webster
May, 1999
Submitted to:
Rhode Island Public Utilities Commission
RIPUC Docket __________
Submitted by:
NEES Logo
EUA Logo
<PAGE>
May 20, 1999
Luly E. Massaro
Commission Clerk
Public Utilities Commission
100 Orange Street
Providence, RI 02903
Re: Rate Plan Filing Relating to the Consolidation of
Narragansett Electric, Blackstone Valley Electric, and
Newport Electric
Dear Ms. Massaro:
Enclosed for filing with the Commission are ten copies of a rate plan
filing of The Narragansett Electric Company ("Narragansett"), Blackstone Valley
Electric Company ("BVE"), and Newport Electric Corporation ("Newport")
(collectively, "Companies"). The rate plan relates to the consolidation of the
Companies in connection with the merger of New England Electric System ("NEES")
and Eastern Utilities Associates ("EUA").
Through this filing the Companies are seeking approval of a rate plan
that would go into effect within 120 days of the closing of the EUA-NEES merger
or April 1, 2000, whichever occurs later ("Rate Consolidation Date"). On the
Rate Consolidation Date, distribution rates for BVE and Newport customers would
be immediately reduced by approximately $2 million and $3.4 million,
respectively, as BVE's customers are placed on Narragansett's distribution rates
and Newport's distribution rates are moved half the distance to Narragansett's
distribution rates. This represents reductions in average total delivery rates
for BVE and Newport in the first year (excluding the Standard Offer) of 2.6% and
8.8%, respectively.
Additional customer savings will be accomplished through a two phase
distribution rate freeze applicable to all customers (including Narragansett
<PAGE>
Rate Plan Filing of
Narragansett Electric, BVE,
and Newport Electric
May 20, 1999
Page 2 of 3
customers) through 2004. Specifically, the Companies commit as part of the
NEES-EUA transaction to freeze the distribution component of its rates through
the year 2002. In addition, the Companies propose to extend the rate freeze on
the distribution component of its delivery rate for an additional two years
through 2004 if the National Grid Group's merger with NEES is approved. Thus,
under the rate plan, customers will see stable distribution charges through
December 31, 2004. In addition, by 2004, total average delivery rates for BVE
and Newport under the rate plan will be approximately 15% and 20% less than they
otherwise would have been in the absence of the merger.
The four year distribution rate freeze shares the savings expected to
result from the NEES-EUA merger. We believe that the merger will allow the
combined Rhode Island and Massachusetts based system to reduce annual costs by
$35 million in 2005. Rhode Island's annual share of that amount will be
approximately $9 million after the expiration of the rate freeze in 2005.1 In
addition, the distribution rate freeze eliminates cost of service increases that
might otherwise have added $20 million additional revenues to the base
distribution charges of the combined companies, assuming distribution rates
would have risen by at least the rate of inflation. Over the four year period of
the distribution rate freeze, customers of the consolidated company receive
economic benefits equal to $79 million. Almost $49 million of this amount stems
directly from the economic value of the distribution rate freeze. Finally, the
consolidation of the Companies and the integration of the Narragansett, BVE, and
Newport billing systems should promote the competitive market for electricity
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1 Under our proposal, these savings are applied first to the cost of the
EUA acquisition and are then divided equally between customers and the
recovery of the acquisition costs resulting from the NEES-National Grid
transaction.
<PAGE>
Rate Plan Filing of
Narragansett Electric, BVE,
and Newport Electric
May 20, 1999
Page 3 of 3
supplies by lowering marketing and transaction costs for suppliers and
customers.
Thank you for your attention to this matter. For the convenience of
the Commission, a copy of this letter has been inserted and bound into volume 1
of the filing under the first tab.
Sincerely,
/s/ Ronald T. Gerwatowski
----------------------------------------
Ronald T. Gerwatowski
Thomas G. Robinson
Attorneys for Narragansett Electric
Very truly yours,
/s/ David A. Fazzone
----------------------------------------
David A. Fazzone
McDermott, Will & Emery
Attorney for Blackstone Valley Electric
and Newport Electric
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ------------------------------------
)
Narragansett Electric )
Blackstone Valley Electric Company ) R.I.P.U.C. No. __________
Newport Electric Corporation )
)
- ------------------------------------
DIRECT TESTIMONY
OF
MICHAEL E. JESANIS
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ------------------------------------
)
Narragansett Electric )
Blackstone Valley Electric Company ) R.I.P.U.C. No. __________
Newport Electric Corporation )
)
- ------------------------------------
DIRECT TESTIMONY
OF
MICHAEL E. JESANIS
Table of Contents
Page
I. Qualifications .......................................................1
II. Purpose of Testimony and Summary of Filing ...........................2
III. Terms, Conditions, and Structure of the Transaction ..................6
IV. Rate Plan.............................................................9
A. Rate Reductions and Rate Consolidation Plan..................9
B. Distribution Rate Freeze....................................15
1. First Phase: NEES-EUA, 2001 and 2002...............15
2. Second Phase: NEES-National Grid, 2003 and 2004....16
C. Recovering the Costs of Consolidation ......................18
V. Benefits Created by the NEES Acquisition of EUA......................24
VI. The Acquisition Premium and Transaction Costs........................33
VII. Future Earnings Reports .............................................39
VIII. FAS 71 ...................................................40
IX. Other Regulatory Approvals...........................................42
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 1 of 44
<S> <C>
1 I. Qualifications.
2 Q. Please state your name and business address.
3 A. Michael E. Jesanis, 25 Research Drive, Westborough, Massachusetts.
4
5 Q. By whom are you employed and what is your position?
6 A. I am Senior Vice President and Chief Financial Officer of New England Electric System
7 ("NEES"). I am also Vice President of The Narragansett Electric Company
8 ("Narragansett"), New England Power Company ("NEP"), and New England Power
9 Service Company ("NEPSCO").
10
11 Q. Please summarize your professional and educational background.
12 A. I joined the NEES companies in 1983 as a financial analyst and was elected Treasurer of
13 NEES in 1992. I was elected a Vice President of NEES effective January 1, 1997 and
14 Senior Vice President and Chief Financial Officer effective March 1, 1998. I earned
15 bachelor's and master's degrees in mathematics from Clarkson College of Technology and
16 a master of business administration degree from the Wharton School at the University of
17 Pennsylvania.
18
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 2 of 44
1 Q. Have you previously testified before any regulatory commission?
2 A. Yes. I have testified before the Commission, the Massachusetts Department of
3 Telecommunications and Energy, the New Hampshire Public Utilities Commission, and
4 the Federal Energy Regulatory Commission.
5
6 II. Purpose of Testimony and Summary of Filing.
7 Q. What is the purpose of this filing?
8 A. On February 1, 1999, NEES, Eastern Utilities Associates ("EUA"), and Research Drive
9 LLC ("Research Drive"), a directly and indirectly wholly owned subsidiary of NEES
10 entered into an Agreement and Plan of Merger ("EUA Agreement"), through which EUA
11 will become a wholly owned subsidiary of NEES. Upon the closing of the EUA
12 transaction, it is the intention of NEES to consolidate the three Rhode Island operating
13 companies, Narragansett, Blackstone Valley Electric ("BVE"), and Newport Electric
14 Corporation ("Newport") (together, the "Companies"). This filing requests the
15 Commission approve rates that would go into effect within 120 days of the closing of the
16 EUA merger or April 1, 2000, whichever occurs later.
17
18 Q. Please describe the companies involved in this transaction?
19 A. NEES is a registered holding company under the Public Utility Holding Company Act of
20 1935 ("Holding Company Act") and owns the common equity of several electric utility
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 3 of 44
1 companies, including Narragansett, Massachusetts Electric Company, Nantucket Electric
2 Company, NEP, and Granite State Electric Company. NEES has entered into an
3 agreement to merge with National Grid Group ("National Grid"), completion of which is
4 awaiting regulatory approvals.
5
6 EUA also is a registered holding company under the Holding Company Act and owns
7 directly or indirectly the common equity of several electric utility companies, including
8 BVE, Newport, Eastern Edison Company ("Eastern Edison"), and Montaup Electric
9 Company ("Montaup").
10
11 Q. What approvals are being sought from the Commission?
12 A. The Companies are seeking approval of a rate plan that would go into effect within 120
13 days of the closing of the EUA acquisition or April 1, 2000, whichever occurs later. The
14 rate plan lowers Newport and BVE rates, and freezes distribution rates for all customers
15 through the year 2004. As a part of the rate plan, the Companies seek an order from the
16 Commission allowing rate recovery of the acquisition premium paid to acquire EUA and a
17 mechanism for recovering a portion of the premium paid by National Grid to acquire
18 NEES, which has allowed this transaction to move forward. In addition, the Companies
19 seek an order relating to the implementation of new depreciation rates, including a
20 mechanism for addressing a problem that Narragansett faces relating to the recovery of
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 4 of 44
1 cost of removal expenses, which will be described in greater detail in this filing. Finally,
2 the Companies request a consolidation of the respective storm funds of each of the three
3 Companies.
4
5 Q. What issues will your testimony address?
6 A. I explain the structure and terms of the EUA/NEES merger, summarize its benefits for
7 NEES customers, employees, and shareholders, and describe the regulatory approvals
8 necessary to implement the transaction. I also summarize our plan for consolidating the
9 NEES and EUA operating companies. In addition, I will summarize the Companies' rate
10 plan proposal that moves BVE's customers to Narragansett's lower distribution rates
11 reducing rates to BVE customers by approximately $2.0 million, lowers distribution rates
12 for Newport customers by $3.4 million, and implements a four year distribution rate freeze
13 across the board. As I explain, the four year rate freeze provides over $79 million of
14 economic value to the customers of the three companies and reduces retail delivery rates
15 by 15 percent for BVE and 20.4 percent for Newport below the rates that would have
16 occurred without the consolidation and distribution rate freeze. Finally, I address the
17 transaction and acquisition costs associated with the transaction and explain our plans for
18 allocating these costs among the NEES operating companies and addressing them in the
19 ratemaking process.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 5 of 44
1 Q. Who else is supporting the filing?
2 A. In addition to my testimony, Mr. Robert Powderly, Executive Vice President of EUA will
3 discuss the reasons behind EUA's decision to be acquired by NEES. Lawrence J. Reilly,
4 President and Chief Executive Officer of Narragansett describes how Narragansett
5 Electric and its affiliated distribution companies are organized today to provide quality
6 service to customers. In addition, he describes the integration process that is underway
7 with EUA and the anticipated benefits for customers. Finally, he describes the benefits
8 that the merger creates for customers in the power supply market.
9
10 David M. Webster, Principal Financial Analyst with the NEES companies, addresses the
11 accounting issues associated with the combination of the three companies, including the
12 development of consistent depreciation schedules and accruals for accounting purposes.
13 Mr. Webster also explains the issues related to cost of removal expenditures that have
14 resulted in a deficiency in the deferred taxes reserves recorded on Narragansett's books
15 that the Company ultimately will need to reflect in rates. In addition, Mr. Webster
16 discusses the Company's proposal to consolidate the storm funds of the three Rhode
17 Island utilities.
18
19 James M. Molloy, Senior Rate Analyst for the NEES companies, and James J. Bonner,
20 Manager of Retail Pricing and Rate Administration for the EUA companies, support the
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 6 of 44
1 rate plan following the merger. Their testimonies document the rates and rate mapping
2 associated with consolidating the NEP and Montaup transmission rates, moving BVE
3 customers to Narragansett's rates, and lowering rates for Newport customers.
4
5 Finally, David J. Hoffman and Richard J. Levin of Mercer Management Consulting
6 provide the analysis of synergies and savings that were identified as part of our analysis
7 leading to the merger decision. These savings support the rate treatment of the acquisition
8 costs associated with the EUA/NEES merger.
9
10 III. Terms, Conditions, and Structure of the Transaction.
11 Q. Mr. Jesanis, would you please summarize the transaction between NEES and EUA?
12 A. The transaction is set forth in the EUA Agreement included as Exhibit MEJ-1. Pursuant
13 to the EUA Agreement, Research Drive will merge with and into EUA with EUA
14 becoming a wholly owned subsidiary of NEES. EUA shareholders will receive $31 per
15 share in cash, which will be increased at a rate of $.003 each day beginning six months
16 after EUA shareholder approval of the EUA acquisition. The merger agreement contains
17 terms and conditions which are typical to a merger transaction. Closing of the merger is
18 subject co obtaining approval of EUA shareholders and obtaining required regulatory
19 approvals.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 7 of 44
1 Q. How will the acquisition affect EUA's utility subsidiaries?
2 A. At the time of closing, there will be no immediate impact on EUA's utility subsidiaries.
3 For example, BVE and Newport, currently subsidiaries of EUA, will remain so, with EUA
4 becoming a subsidiary of NEES. However, as soon as practicable thereafter, we intend to
5 consolidate the operating companies of EUA with the operating companies of NEES
6
7 Q. How will the consolidations be implemented?
8 A. In the case of the Rhode Island operating companies, it is our intention to merge BVE and
9 Newport into Narragansett. However, there may be an interim period during which the
10 three companies retain their legal existence as separate corporations, pending a
11 clarification in Rhode Island law that mergers of public utilities are permitted. Currently,
12 the law allows a public utility to purchase the business and assets of another public utility,
13 but the law is somewhat ambiguous as to whether it permits a formal merger. The
14 clarification could come in the form of legislation or, if necessary, a declaratory judgment
15 request. To the extent that a merger is not permitted, the Companies would exist as
16 separate legal entities, but be operated in a consolidated fashion. In such case, the
17 Companies would propose that the Commission allow one cost of service for the
18 consolidated companies for purposes of rate review. In either case, the Companies' rate
19 plan proposal is not affected by the form of the consolidation.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 8 of 44
1 Q. What about the other operating companies?
2 A. There is no such complication for the other operating companies. Montaup will merge
3 into NEP, and Eastern Edison will merge into Massachusetts Electric. In addition, we
4 expect to combine the operations of the two service companies, NEPSCO and EUA
5 Service Corporation. With the exception of the addition of EUA's unregulated
6 companies, the resulting corporate structure will look essentially the same as NEES's
7 current corporate structure. The corporate structures immediately after the acquisition of
8 EUA and after the later consolidation of the operating companies are shown in Exhibit
9 MEJ-2.
10
11 Q. Are there any closing conditions in the EUA Agreement that pertain to Rhode Island
12 regulatory approvals?
13 A. Yes. In Article VIII, paragraph (d), of the EUA Agreement, there is a condition stating
14 that the parties need to receive "Final Orders from the Massachusetts Department of
15 Telecommunications and Energy and the Rhode Island Public Utilities Commission
16 pertaining to the recovery of costs (including, without limitation, transaction premium and
17 integration costs) associated with the Merger that are materially consistent with existing
18 policy and previous orders of such agencies." As I will explain later in my testimony, the
19 Company is requesting certain rate treatment for the EUA acquisition premium, consistent
20 with Commission precedent and the intent of that closing condition.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 9 of 44
1 IV. Rate Plan.
2 Q. What is the rate plan proposed for Narragansett, BVE, and Newport customers?
3 A. The rate plan has three components. First, we propose to lower distribution rates for
4 BVE and Newport customers by approximately $2.0 million and $3.4 million, respectively.
5 BVE customers would be moved to Narragansett's lower distribution rates, and Newport
6 customers are moved halfway to those lower rates. Transmission rates will be
7 consolidated and transition charges will gradually be moved into parity so that all
8 customers would pay the same transition charges by 2005. Second, we propose to freeze
9 the distribution component of rates for customers of all three Companies through the year
10 2004. Finally, we propose a mechanism to recover the acquisition premium for the
11 NEES-EUA transaction and a portion of the acquisition for the NEES-National Grid
12 transaction. Each of these components is discussed below.
13
14 A. Rate Reductions and Rate Consolidation Plan.
15 Q. What is the first component of the plan?
16 A. The first component of the plan is to reduce rates to the customers of BVE and Newport
17 effective on the later of April 1, 2000 or 120 days after the merger is approved (the "Rate
18 Consolidation Date"). Since the implementation of retail choice in 1997, each utility's
19 rates has been composed of four components -- the distribution charge (including
20 renewables and DSM charges), the transmission charge, the transition charge, and the
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 10 of 44
1 standard offer. The first three of these components represent the delivery rates for
2 customers. The final component represents power supply which is avoided when the
3 customer purchases its power supply in the market. The rate consolidation plan focuses
4 on each of these elements.
5
6 First, with respect to the distribution component, Narragansett proposes to place all of
7 BVE's customers on Narragansett's distribution rates and move Newport's customers half
8 the distance to Narragansett's rates. This would be accomplished by placing Newport's
9 customers on Narragansett's distribution rates and implementing a separate distribution
10 surcharge applicable only to Newport's customers that represents 50 percent of the
11 differential between Newport's distribution rates (excluding DSM and renewables
12 charges) and Narragansett's distribution rates. For purposes of the tariffs, we refer to this
13 distribution surcharge as the "Zonal Distribution Factor."
14
15 The Navy, which is now served by Newport under a special distribution rate, will continue
16 on that rate with a 14 percent rate reduction in the distribution component, which is equal
17 to the average distribution rate decrease for all other Newport customers as a result of the
18 merger. There also is a special rate adjustment that is being proposed to prevent
19 Newport's street lighting customers from experiencing rate increases as a result of the
20 consolidation that is explained in the testimony of Mr. Molloy. In addition, the Companies
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 11 of 44
1 are proposing an interim credit mechanism for low income customers of the EUA
2 companies that also is described in Mr. Molloy's testimony. The result of the
3 consolidation of distribution rates in the rate plan is an annual reduction of approximately
4 $2 million for BVE's customers and $3.4 million for Newport's.
5
6 The Companies are proposing to consolidate the transmission component of the rates
7 effective on January 1, 2001. Prior to that time, the transmission rate components in
8 effect for each of the Companies during 2000 would be locked in at their presently
9 effective levels. Because Montaup's transmission rates are lower than NEP's, the
10 transmission rate consolidation will result in a decrease in transmission component of
11 Narragansett's rates in 2001 and thereafter. Increases in transmission charges for BVE
12 and Newport customers will be more than offset by reduced transition charges.
13
14 Base transition charges will be established at 1.15 cents per kilowatthour for the
15 customers of all three companies on the Rate Consolidation Date. In addition, Newport
16 and BVE customers will pay a surcharge designed to recover the difference between the
17 contract termination charges paid to NEP and Montaup by the three companies and the
18 revenues collected under the base transition charge of 1.15 cents per kilowatthour from
19 the customers of the three companies. This difference divided by the kilowatthour
20 deliveries of BVE and Newport will be applied to deliveries in BVE and Newport service
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 12 of 44
1 territories. For purposes of the tariffs, the transition surcharge is referred to as the "Zonal
2 Transition Factor." The Companies are proposing to keep this transition mechanism in
3 effect until a surcharge is no longer necessary and transition charges come into complete
4 parity. Once this occurs, the Companies will propose consolidated transition factors. We
5 expect that this will occur around 2005. Thus, the customers of Narragansett would
6 continue to pay 1.15 cents per kilowatthour until transition charges are consolidated.
7
8 Q. Did you consider blending the transition charges without adding the surcharge to BVE
9 and Newport to transition charge?
10 A. Yes. However, the rate differential is significant and blending would result in an increase
11 to Narragansett's customers. BVE and Newport's contract termination charges from
12 Montaup are higher than NEP's contract termination charges to Narragansett. In
13 addition, Narragansett has already brought down a significant component of its transition
14 charge through an early payment to NEP. As a result, Narragansett's transition charges
15 are significantly below those of BVE and Newport. These disparities make it difficult to
16 equalize the transition charges prior to 2005.
17
18 Q. What is the effect of the rate plan in 2000 after the Rate Consolidation Date?
19 A. The consolidation will reduce average delivery rates excluding the Standard Offer to BVE
20 and Newport customers by 2.6 percent and 8.8 percent, below the levels in place before
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 13 of 44
1 the Rate Consolidation Date. Rates to Narragansett's current customers do not change.
2 The rates and revenues in 2000 before and after the merger are shown on Exhibit MEJ-3,
3 page 1. As that Exhibit demonstrates, the merger produces significant economic benefits
4 for BVE and Newport customers on the Rate Consolidation Date.
5
6 Q. What happens to rates of the consolidated companies in 2001?
7 A. As explained above, the transmission component of the retail delivery rate is combined on
8 January 1, 2001, producing a reduction for Narragansett's existing customers of about
9 .057 cents per kilowatthour. Under our plan this reduction is partially offset by an
10 increase in the distribution component of the rate of .039 cents per kilowatthour designed
11 to recover on a prospective basis Narragansett's costs of removing its equipment after the
12 equipment is retired. The distribution increase is applied to the consolidated distribution
13 rate of the three companies. As Mr. Webster explains, this recovery is necessary to assure
14 the Company's depreciation rates are adequate on a prospective basis to recover the full
15 cost of retiring and removing Narragansett's plant. Both BVE and Newport already
16 reflect cost of removal expenses in their rates and the Division has agreed in a prior case
17 that this recovery is appropriate for Narragansett. Under our plan, we will recognize the
18 increased depreciation expense on our books and match it with rate recovery on January
19 1, 2001. As shown on Exhibit MEJ-3, page 2, the net effect of the two adjustments is a
20 slight decrease for Narragansett's existing customers. Although transmission and
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 14 of 44
1 distribution rates for BVE and Newport customers increase slightly, these increases are
2 more than offset by reduced transition charges in 2001. Thus, the proposed rate plan
3 removes the likelihood of the need for a significant rate increase related to cost of removal
4 alone without increasing delivery charges to customers in 2001. In fact, delivery rates to
5 Narragansett's existing customers fall slightly, and the delivery rates to BVE and Newport
6 decline by an additional 6.5 percent and 6.0 percent respectively (Exhibit MEJ-3, page 2).
7
8 Q. Mr. Webster has also identified a significant deficiency in the provision for taxes for cost
9 of removal. How does the rate plan address that issue?
10 A. Narragansett proposes to recover the deficiency with revenue requirements of about $33
11 million through refunds that would otherwise be made resulting from certain
12 reconciliations in NEP's and Montaup's Contract Termination Charge to the Company.
13 Narragansett and NEP have already agreed to an adjustment equal to $ 10 million from the
14 Reconciliation Report filed in December. In addition, we expect further adjustments as
15 the result of the settlement of a claim with Hydro Quebec (about $2 million), and gas
16 pipeline refunds. These and other refunds that may be received from time to time from
17 either NEP or Montaup could reduce the prior unfunded amount significantly. We
18 propose to continue to apply future credits to Narragansett from settlements and the sale
19 of assets to the account balance until Narragansett's next rate case at which time any
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 15 of 44
1 remaining deficiency would be amortized and recovered beginning at the time of
2 Narragansett's next change in distribution base rates.
3
4 B. Distribution Rate Freeze.
5 Q. Please describe the rate freeze component of the plan.
6 A. The second component of the plan involves a two-phase distribution rate freeze through
7 the year 2004. I will describe each phase below.
8
9 1. First Phase: NEES-EUA, 2001 and 2002.
10 Q. Please explain the first phase of the distribution rate freeze.
11 A. The Company commits as part of the NEES-EUA transaction to freeze the distribution
12 component of its rates through the year 2002. The distribution rate freeze will apply to
13 the customers of all companies under the consolidated rate plan. Narragansett and BVE
14 will charge the same distribution rates through 2001 and 2002, and Newport will maintain
15 its Zonal Distribution Factor at the level initially established on the Rate Consolidation
16 Date through the two year rate freeze period.
17
18 Thus, if the EUA merger is completed, distribution rates to Narragansett's customers,
19 which are among the lowest in New England, will remain at the same level for five years,
20 except for the cost of removal and depreciation adjustment on January 1, 2001. The
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 16 of 44
1 Company would retain only the ability to adjust rates to reflect costs incurred as a result of
2 any one of the following exogenous events occurring during the rate freeze period: (1)
3 changes to local, state, and federal tax laws, regulations, or precedents, (2) incurrence of
4 hazardous waste clean up liability from manufactured gas plants of Narragansett,
5 Newport, or BVE or their predecessor companies, and (3) changes to accounting rules
6 and practices. Assuming distribution rates would have otherwise increased at an inflation
7 rate of 2.2 percent per annum, the cumulative value of the rate plan for the customers of
8 the consolidated Narragansett is approximately $31 million through December 31, 2002.
9 See Exhibit MEJ-4, page 1, line 5.
10
11 The two year distribution rate freeze shares the savings from the NEES-EUA merger. As
12 described more fully later in my testimony, we believe that the merger will allow the
13 combined system to reduce annual costs by $35 million in 2005. The Rhode Island share
14 of this amount is about $9 million per year. In contrast, the distribution rate freeze
15 eliminates cost of service increases that might otherwise have added $20 million additional
16 revenues to the base distribution charges of the combined companies, assuming
17 distribution rates would have risen by at least the rate of inflation.
18
19 2. Second Phase: NEES-National Grid, 2003 and 2004.
20 Q. Please describe the second phase of the rate freeze.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 17 of 44
1 A. The second phase involves a further two year extension of the distribution rate freeze.
2 Because we believe that the National Grid merger will allow us to produce significant
3 additional savings through improved operations, further efficiency gains, the adoption of
4 best practices, and improved scale economies, Narragansett proposes to extend the
5 distribution rate freeze an additional two years through December 31, 2004 contingent
6 upon the closing of the NEES-National Grid merger. This provides Narragansett's
7 customers price stability for regulated service for seven years. The value of the rate plan
8 will grow to over $26 million per year by 2004 and will total approximately $79 million
9 over the rate freeze period. See Exhibit MEJ-4, page 1, line 4.
10
11 The distribution rate freeze represents the most significant element of these savings. As
12 shown on page 1, lines 5 and 6 of Exhibit MEJ-5, the savings associated with the
13 distribution rate freeze total $20 million in 2004 and $49 million over the 4 year period.
14 Because of the length of the rate freeze and the potential that inflation may exceed current
15 projections by a significant amount, we propose to add an adjustment in the event that
16 inflation occurring during the extended rate freeze in calendar years 2003 and 2004
17 exceeds 3.0 percent. Specifically, the average distribution rate at the "Consolidation Date"
18 is 2.993 cents per kilowatthour as shown in Exhibit JMM-3, page 1, line 1. This amount
19 will be adjusted in accordance with the methodology illustrated in Exhibit MEJ-6, which
20 compares actual inflation as measured by the Consumer Price Index Deflator - All Urban
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 18 of 44
1 Consumers ("CPI-U") to 3.0 percent, and adjusts distribution rates in effect in 2003 for 75
2 percent of the excess over 3.0 percent. The adjustment would be calculated at the end of
3 September, 2002 prior to the first year of the extended rate freeze, and the adjustment, if
4 any, would be rolled into distribution rates as a permanent increase. The process would be
5 followed again for the end of September, 2003 for the following year, 2004 which is the
6 last year of the rate freeze. This adjustment would be in addition to any adjustments for
7 the other exogenous factors identified above. We are proposing to use CPI-U as the
8 inflation index because we already use this index in the adjustments to Narragansett's
9 storm fund. It is a broad index of inflation that is representative of the economic
10 conditions in Narragansett's service area.
11
12 C. Recovering the Costs of Consolidation.
13 Q. What is the fourth component of the plan?
14 A. The fourth and final component of the proposed rate plan focuses on Narragansett's
15 financial integrity and the rate setting process following the period of the distribution rate
16 freeze. As set forth later in my testimony, there are significant costs associated with
17 producing the savings that stem from the consolidation of NEES-EUA and NEES-
18 National Grid. These costs for the NEES-EUA transaction are quantified in this filing and
19 compared directly to the savings from the consolidation. As I explain below, the savings
20 from the NEES-EUA consolidation exceed the acquisition premium and the transaction
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 19 of 44
1 costs of the NEES-EUA acquisition. Accordingly, we are proposing to amortize for
2 ratemaking purposes the EUA acquisition premium and transaction costs that are allocated
3 to Narragansett over 20 years as shown on Exhibit MEJ-7.
4
5 Q. Is the Company proposing any rate treatment for the acquisition premium and transaction
6 costs arising out of the NEES-National Grid merger?
7 A. Yes. We also are proposing to retain 50 percent of the savings from the EUA acquisition
8 above and beyond the amortization of the EUA acquisition premium and transaction costs
9 to recover a portion of the acquisition premium and transaction costs paid by National
10 Grid to acquire NEES. The remaining 50 percent of the excess savings will flow through
11 to customers following the rate freeze producing a reduction in distribution rates from the
12 level that customers would have experienced absent the merger.
13
14 Q. Does the Company propose to recover the costs of severance payments for officers of
15 EUA, the parent company of BVE and Newport, or for NEES, the parent of
16 Narragansett?
17 A. No. We have excluded the costs of those severance payments for all EUA parent
18 company officers. However, the transaction costs do include other severance payments
19 that may be made to other EUA system employees who may be displaced as a result of the
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 20 of 44
1 merger. We have also excluded the costs of any severance payments that might be made
2 to any NEES parent company officers.
3
4 Q. How will the sharing mechanism relating to the National Grid-NEES acquisition premium
5 and transaction costs work?
6 A. The annual savings from the consolidation of the companies will equal $35 million per
7 year in the first full year after the rate freeze. These savings are expected to grow by
8 inflation over the long term. Of this amount, we expect that approximately 25 percent or
9 $9 million will flow to the consolidated Narragansett. These savings provide the basis for
10 the sharing plan.
11
12 Under our plan, the future annual savings will be fixed and determined in this proceeding.
13 At the time of any future Narragansett distribution rate proceeding, Narragansett would be
14 allowed to include in its cost of service the annual amortization of the EUA acquisition
15 premium and transaction costs, because the annual amortization is less than the savings
16 produced by the merger. As shown in Exhibit MEJ-8, the Rhode Island portion of the
17 annual amortization expense for the EUA transaction is $5,473,000 for 20 years and zero
18 thereafter. Under our proposal, the amortization would first be subtracted from the annual
19 savings and 50 percent of the remaining savings would then be applied to recover the
20 NEES-National Grid acquisition premium and transaction costs. For example, if the
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 21 of 44
1 Commission found that the EUA consolidation produced $35 million of annual savings in
2 2005 when the distribution rate freeze ends, and that $8,887,000 would be allocated to
3 Narragansett, Narragansett could include in its first cost of service following the rate
4 freeze, an annual amortization of the EUA-NEES acquisition premium equal to
5 $5,473,000 plus one half of the remaining savings to apply against the NEES-National
6 Grid acquisition premium. Thus, 50 percent of $3,414,000 ($8,887,000 - $5,473,000 =
7 $3,414,000) equal to $1,707,000 would be applied against the National Grid premium and
8 transaction costs, and $1,707,000 will be reflected in a lower cost of service.
9
10 The amount of savings available for the 50/50 sharing mechanism grows over time as the
11 savings grow by inflation, and amortization of the EUA acquisition premium is eliminated
12 after 20 years. Exhibit MEJ-8 illustrates the calculation based on an assumed level of
13 inflation equal to 2.2 percent, and shows the annual sharing amounts. The actual level of
14 sharing will be based on actual inflation experienced over the period. Under our proposal,
15 except for the adjustment to reflect actual inflation, these amounts would be fixed for the
16 NEES-EUA transaction in this proceeding.
17
18 Q. Does the share of savings that is applied against the National Grid acquisition premium
19 and transaction costs match the amortization of the premium for accounting purposes?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 22 of 44
1 A. No. As we have explained, the ratemaking treatment for the acquisition premium and
2 transaction costs is different from the accounting treatment. As with the EUA acquisition
3 premium and transaction costs, the National Grid acquisition premium and transaction
4 costs will be pushed down to the NEES companies, including Narragansett, and amortized
5 for accounting purposes over 20 years. The accounting treatment of the National Grid
6 premium does not control rate recovery and the sharing mechanism postpones rate
7 recovery of the portion of the National Grid acquisition premium recovered through the
8 proposed sharing mechanism to a later period.
9
10 Q. What is the portion of the NEES-National Grid premium that is recovered through this
11 mechanism?
12 A. The present values of the savings from the NEES-EUA merger, the amortization of the
13 EUA acquisition premium and transaction costs, and the remaining savings are shown on
14 Exhibit MEJ-9. As that exhibit shows, the net present value of the Rhode Island portion
15 of the merger savings in excess of the EUA recovery is $91 million. Fifty percent of this
16 present value or $46 million is the recovery of the NEES-National Grid premium. This
17 amount will be deducted from the present value of the amortization of the NEES-National
18 Grid premium allocated to Narragansett and will not be recovered in any other way.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 23 of 44
1 Q. Would this sharing mechanism be applied to future acquisitions?
2 A. Yes. Our goal is to generate further savings through future consolidations in the
3 Northeast. Under our plan, 50 percent of the savings in excess of the EUA acquisition
4 premium and transaction costs allocated to Rhode Island customers will also be applied to
5 recover the NEES-National Grid acquisition premium and the transaction costs. The
6 National Grid acquisition of NEES is essential for the consolidation of other low cost
7 utilities in the Northeast. Even though these consolidations, by definition, would involve
8 acquisitions outside of Rhode Island, savings will flow to Narragansett automatically
9 without any associated acquisition premium or transaction costs. For example, if Mass.
10 Electric were to merge with another Massachusetts utility, Rhode Island would see
11 benefits from that transaction without an allocation of acquisition costs. Similarly, as
12 shown on Exhibit MEJ-9, a portion of the savings from the EUA transaction is
13 automatically flowing to New Hampshire customers, but the acquisition costs are not,
14 because EUA has no operations in New Hampshire. These benefits are the direct result of
15 this and future consolidations. If we successfully implement other mergers in the future,
16 Narragansett's customers will share the benefits of these consolidations even though they
17 occur outside of Rhode Island. As in this case, Narragansett would demonstrate the
18 savings and the sharing at the outset through a synergy study.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 24 of 44
1 Q. Would the 50 percent sharing apply to savings from ongoing efficiency gains?
2 A. No. Ongoing efficiencies will be generated through an array of activities beyond
3 consolidations. We propose to maintain flexibility to design incentives and sharing
4 mechanisms tailored to specific issues and problems. A simple sharing mechanism may
5 not produce the correct economic incentive for specific operations and programs.
6 Program-specific incentive designs may be necessary in the future to encourage capital
7 investment to reduce operating costs, losses, or congestion, or to further specific public
8 policy objectives.
9
10 Q. Will there be a cap on recovery of the NEES-National Grid acquisition premium?
11 A. Yes. Narragansett's recovery will stop when the portion of the acquisition premium and
12 transaction costs associated with the National Grid transaction that is allocated to
13 Narragansett has been recovered. As explained above, the EUA transaction reduces the
14 present value of this recovery by $46 million. Future transactions will be applied to
15 reduce the premium in the same way. When the premium is fully offset, recovery of the
16 National Grid premium will cease.
17
18 V. Benefits Created by the NEES Acquisition of EUA.
19 Q. Would you summarize the benefits created through the NEES acquisition of EUA?
20 A. The acquisition of EUA by NEES will result in the creation of substantial benefits which
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 25 of 44
1 can be used to provide improved service at lower rates to customers, greater opportunities
2 for employees, a premium to EUA shareholders, and an opportunity for NEES and
3 National Grid shareholders to earn reasonable returns on their investments in the
4 companies.
5
6 The benefits to customers will be produced by the proposed rate plan described above.
7 These benefits are financed in part by the savings produced by the NEES-EUA
8 consolidation. The acquisition and consolidation produce synergies which are typical of
9 utility combinations. These synergies build on efficiencies already achieved by the
10 Companies, which are low cost utilities in New England.
11
12 Q. How will the cost savings you described be achieved?
13 A. The cost savings will come from a variety of categories. Approximately 70 percent of the
14 savings will come from eliminating approximately 250 positions from the combined
15 organization. These reductions come from across the organization. Administrative areas
16 such as accounting and finance, where significant redundancies exist between the two
17 companies, will be reduced. EUA's and NEES' customer service operations will be
18 integrated to handle increased volumes at a lower unit cost. The unit cost of field
19 operations will also be reduced through standardization and mutual support. The
20 remainder of the operating savings will come from disposing of duplicate facilities,
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 26 of 44
1 realizing greater purchasing power, and eliminating redundant administrative costs, such as
2 corporate governance expense. Mr. Hoffman testifies at length on these savings.
3
4 Q. What is your estimate of savings that will be achieved?
5 A. Based on the analysis performed by NEES and Mercer Management, the savings will be
6 about $31.1 million per year by the end of the distribution rate freeze period for all of the
7 NEES/EUA retail distribution companies in Rhode Island and Massachusetts. For reasons
8 I describe below, I believe that the estimate developed by Mercer Management is
9 conservative and that we will achieve total savings of $3 5 million per year by the end of
10 the rate freeze period. These savings will grow with inflation over time. As shown on
11 Exhibit MEJ-9, the present value of the savings after amortization of the EUA acquisition
12 premium and transaction costs will be at least $356 million. Narragansett's share of that
13 amount is $91 million.
14
15 Q. Please describe the goals of the NEES/EUA integration process.
16 A. In my view, there are two overriding goals to the integration process. First, the
17 integration process is critical to achieving the efficiency gains upon which the transaction
18 was predicated. Second, it is equally important to combine the two organizations in a way
19 that maintains or improves service quality. The integration process is providing us the
20 opportunity to review our business practices to identify additional opportunities to
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 27 of 44
1 streamline operations. The integration process also provides us the opportunity to
2 compare business processes and adopt best practices where they can improve service to
3 customers.
4
5 Q. How is the integration effort organized?
6 A. Following the announcement of the NEES-EUA transaction, the two companies created a
7 transition team charged with consolidating the companies in a manner which creates more
8 cost savings than were assumed in the Mercer analysis. The transition team is led by
9 Thomas E. Rogers, Vice President and Director of Corporate Planning for NEPSCO, who
10 directed the sale of our non-nuclear generating business, and Mr. Powderly of EUA, who
11 was responsible for integration activities following EUA's acquisition of Newport. The
12 transition team has formed over 60 individual sub-teams covering all aspects of the
13 business. Each of these teams is charged with the task of identifying savings and
14 efficiency gains.
15
16 Q. What is the schedule for the integration effort?
17 A. The various transition teams have been established and are meeting regularly. For
18 planning purposes, we are targeting October 1, 1999, as the completion date for the
19 process so that we will be ready to move forward with implementation as soon as the
20 necessary regulatory approvals are in hand.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 28 of 44
1 Q. How do you expect that the integration efforts will lead to an improvement on Mercer's
2 estimate of $30 million in annual savings?
3 A. One example of my expectation of better performance is within administrative functions.
4 The Mercer analysis concluded that the combined NEES-EUA companies would need 18
5 percent more personnel in administrative functions than NEES presently has today when
6 the combined company has 22 percent more customers. Given that we will be merging the
7 operating companies into a structure that is nearly identical to NEES's structure, I do not
8 believe that we will need 18 percent more accountants, information systems professionals,
9 lawyers and rate analysts when we have no more utility companies in our holding company
10 creating accounting statements, making rate filings or requiring information system
11 resources. Reducing the incremental administrative needs by half will increase savings by
12 $3-5 million per year at the end of the rate freeze. I further believe that Mercer's
13 estimates in customer service and distribution operations understate the benefits we will
14 achieve from the larger scale of the combined NEES-EUA system.
15
16 Q. Are there other savings that are not included in your analysis?
17 A. Yes. We believe that the NEES-National Grid merger will produce additional savings and
18 efficiency gains. We are now evaluating integration possibilities between NEES and
19 National Grid that will implement best practices. These efforts will produce savings for
20 NEES and for the newly acquired EUA companies. Equally important, we expect that
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 29 of 44
1 over time National Grid's significantly larger scale, both in financial and operational terms,
2 will enhance our ability to be at the leading edge of developments in transmission and
3 distribution technology, information systems and capital markets. The increased expertise
4 and resources will enhance our ability to provide customers of both NEES and EUA with
5 high quality transmission and distribution service at reasonable costs. The benefits that
6 will accrue to EUA from the NEES-National Grid integration process are not reflected in
7 our savings estimates for the NEES-EUA merger. Rather, the NEES-National Grid
8 savings will be demonstrated in a separate proceeding.
9
10 In addition, the savings study performed by Mr. Hoffman excludes certain cost savings
11 which are typically counted in other utility mergers. For example, most utility mergers
12 include as savings the costs of building one rather than two sets of new information
13 systems (usually customer or financial) at some time in the future. Both NEES and EUA
14 have older customer information systems. The cost of replacing these systems would
15 currently be in excess of $10 million per company. We did not include these costs in our
16 study because of the difficulty in pinpointing the timeframe in which the savings will occur.
17 Nevertheless, the savings are real and Will provide future benefits.
18
19 Finally, we expect the higher credit ratings of the NEES companies to lead to financing
20 savings as the debt of the EUA companies is refinanced over time.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 30 of 44
1 Q. Can the annual savings included in your analysis be achieved absent the proposed
2 acquisition?
3 A. No. NEES and EUA have superb long-term records of managing costs. One measure of
4 this record is the rates charged to customers. As shown on Exhibit MEJ-10, NEES and
5 EUA customers enjoy lower rates than the customers of most investor owned utilities in
6 neighboring service areas in New England.
7
8 Another measure of cost efficiency is the number of employees required to serve each
9 1,000 customers. Prior to the combination, NEES (at 2.4 employees/1,000 customers)
10 and EUA (at 2.8 employees/1,000 customers) are significantly more efficient than Boston
11 Edison Company, the second largest utility in Massachusetts (which has 3.4
12 employees/1,000 customers). EUA's performance is particularly noteworthy because it
13 has achieved this record of performance despite the fact that it has less than half the
14 customers of Boston Edison. Both NEES and EUA have met their obligations to reduce
15 their costs on a stand alone basis. The combination of NEES, EUA and National Grid
16 represents the best opportunity to continue the track record of NEES and EUA in
17 controlling costs for the benefit of customers.
18
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 31 of 44
1 Q. How will EUA shareholders benefit from the combination?
2 A. The benefits to EUA shareholders stem from the consideration received for their shares at
3 closing. The base consideration of $31 per share is equal to 105 percent of the $29-1/16
4 market value of the shares on the last trading day before the merger was announced and
5 approximately 169 percent of EUA's book value per share of $18.29 as of December 31,
6 1998. The purchase is equal to a 23 percent premium over the market price on December
7 4, 1998, the last trading day before the BEC Energy-Commonwealth Energy merger was
8 announced. As explained earlier, the purchase price is subject to adjustment depending on
9 the timing of the closing The purchase price will be paid in cash. Mr. Powderly further
10 describes the basis for EUA's conclusion that the price to be paid is fair to EUA
11 shareholders.
12
13 Q. Why did you use the December 4, 1998 closing price in determining the value to
14 shareholders?
15 A. Beginning on December 7, 1998 with the announcement of the BEC Energy -
16 Commonwealth Energy merger, EUA's share began rising substantially above the range in
17 which they had traded in recent months. Based on the long-term previous performance of
18 EUA shares in the market, I believe that this price appreciation is the result of speculation
19 that EUA would enter into some kind of merger agreement at a price significantly higher
20 than the trading price on December 4, 1998.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 32 of 44
1 Q. What about the benefits to employees?
2 A. Although the merger is expected to reduce employment by about 250 positions in the
3 combined companies, we believe that these employee reductions can be achieved
4 predominantly through attrition or voluntary early retirement and without significant
5 involuntary layoffs. The efficiency gains are essential to the viability of our companies in
6 the restructured utility industry. For remaining employees, the merger and the NEES-
7 National Grid transaction represent a superb opportunity for growth as we move forward
8 as the United States base of operations for a large international group. The expanded
9 opportunities in this country will stem from National Grid's express intention to expand
10 and consolidate its operations here in this country. The fulfillment of this plan ensures that
11 NEES and EUA employees will remain active in the industry restructuring debate in the
12 United States. National Grid's expanding foreign operations will also provide
13 opportunities for employees abroad.
14
15 Q. Are NEES and EUA taking steps to mitigate the loss of positions following the NEES-EUA
16 merger?
17 A. Yes. In anticipation of the merger's approval, we have placed a limitation on hiring for
18 our company. The NEES companies expect to have a significant number of vacant
19 positions by the time the transaction closes. Natural attrition at EUA is expected to add
20 more positions. We are making every effort to leave these positions vacant until
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 33 of 44
1 employees affected by the acquisition have an opportunity to be considered for a position.
2 Beyond vacancies and attrition, we can economically offer 200 to 250 NEES and EUA
3 employees a voluntary early retirement program, Through these measures, we expect to
4 meet our workforce reduction targets without having a significant impact on individual
5 employees.
6
7 NEES has also agreed in the merger agreement to honor EUA's collective bargaining
8 agreements and to provide non-union employees joining the NEES companies with
9 compensation and benefits in the aggregate at least equivalent to those obtained prior to
10 the merger for a year following closing. EUA employees joining the NEES system will
11 find that the compensation and benefit philosophies of the two companies are very similar,
12 allowing us to merge benefit plans without significant disruption to employees.
13
14 VI. The Acquisition Premium and Transaction Costs.
15 Q. What are the costs associated with NEES's acquisition of EUA?
16 A. NEES is acquiring EUA at a premium of approximately $260 million above the book
17 value of EUA's shares. Because the acquisition of EUA is for cash, the conditions for
18 pooling of interest accounting are not met in this transaction and therefore, purchase
19 accounting must be used. Under Generally Accepted Accounting Principles (GAAP) for
20 purchase accounting, the premium is recorded as goodwill on the acquired company's
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 34 of 44
1 accounts. The premium will be allocated to each of the EUA operating companies
2 following the closing and added to their balance sheets as goodwill. The goodwill will be
3 amortized over 20 years for ratemaking purposes.
4
5 In addition to the acquisition premium, we expect that the transaction costs and the cost of
6 integrating EUA into NEES and achieving our savings targets will be approximately $64
7 million. Mr. Hoffman provides support for our cost estimates.
8
9 Q. How will these costs be allocated among the EUA subsidiaries?
10 A. A "fair value" study will be conducted around the time of closing the merger to determine
11 the allocation of the purchase price among the EUA subsidiaries. The acquisition
12 premium and transaction costs will be allocated in two steps. First, the acquisition
13 premium will be allocated to the unregulated subsidiaries based on the difference between
14 their market value and their book value. This adjustment brings the value of the
15 unregulated firms up to the value reflected in the acquisition. In our analysis we have
16 based this allocation on the underlying book value of the unregulated firms. We expect
17 the allocation to be refined in the valuation study, because the book value of an
18 unregulated enterprise does not bear any direct relationship to its market value.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 35 of 44
1 The second step of the analysis allocates the remainder of the acquisition premium among
2 the regulated companies. This analysis includes the allocation of the transaction and
3 integration costs which are in this transaction all related to regulated operations. Our
4 proposed allocation among the regulated companies is based on the kilowatt-hour sales
5 following the consolidations in Rhode Island and Massachusetts. We propose that the
6 balance of the acquisition premium that is allocated to the regulated businesses be
7 allocated among BVE, Newport and the Massachusetts subsidiary Eastern Edison on the
8 basis of a three year average of kilowatt-hour deliveries to Rhode Island and
9 Massachusetts customers. The integration costs, which are entirely related to the
10 regulated subsidiaries, would be allocated among them in a similar manner.
11
12 This allocation matches the allocation of savings from the transaction, and the economic
13 value that is produced by the consolidation and reflected in the purchase price. Given that
14 transmission and distribution remain regulated businesses priced at the cost of providing
15 service, the value added by the transaction is related to the underlying savings produced by
16 the consolidation. As the result of rate design and service company allocations, these
17 savings will generally be based on kilowatthour deliveries to retail customers. The
18 allocation of the acquisition premium and transaction costs follows this methodology.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 36 of 44
1 Q. Have you allocated any transaction costs or acquisition premium to Montaup/NEP?
2 A. Not in the analysis included in this filing. The primary savings associated with the EUA
3 transaction will be realized in distribution to retail delivery customers. Retail delivery and
4 its associated cost of service represent the bulk of the costs on the system and will
5 represent the most significant source of our savings, directly and indirectly through lower
6 administrative and general expense per customer service. This approach also matches the
7 allocation of the acquisition premium for other utilities whose transmission and
8 distribution rates remain unbundled in the same operating company.
9
10 Moreover, to the extent transmission savings exist, they will flow to retail customers
11 automatically through NEP's formula rate in proportion to Narragansett's retail deliveries.
12 NEP's transmission charges are based on demands at the time of NEP's peak, and
13 although NEP's rate includes deliveries to both affiliated and non-affiliated customers, the
14 allocation of acquisition costs parallels the kilowatthour allocation. Our proposed
15 allocation also maintains the Commission's jurisdiction over the issue.
16
17 Q. Do you have an estimate of the acquisition costs to be allocated to the EUA Companies?
18 A. Yes. BVE and Newport would be allocated $60,372,000 of acquisition premium which,
19 when adjusted for income taxes, produces a revenue requirement of $92,876,000. In
20 addition to this amount, BVE and Newport would be allocated $16,593,000 of transaction
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 37 of 44
1 costs. This produces a total revenue requirement of $109,469,000. With a 20 year
2 amortization period, the annual revenue requirement is estimated at $5,473,000. This
3 compares to about $8.9 million for Rhode Island's share of savings in the year following
4 the rate freeze. Exhibit MEJ-7, page 1 illustrates the allocation of the costs of the
5 transaction. The savings grow with inflation over time, but the amortization of the
6 acquisition premium and transaction costs does not. As explained earlier, 50 percent of
7 the excess of savings each year will be applied to recover the NEES-National Grid
8 premium, and following the rate freeze, the remaining 50 percent of excess savings will be
9 reflected in the cost of service to Narragansett's customers.
10
11 Q. Please explain Narragansett's proposal to retain savings to pay the premium paid by
12 National Grid to acquire NEES.
13 A. One of the benefits of the National Grid-NEES merger was the facilitation of
14 consolidation of transmission and distribution companies by low-cost companies such as
15 NEES. The benefits from NEES's acquisition of EUA are the first step in realizing the
16 vision behind the National Grid-NEES merger. Therefore, we are proposing that a
17 portion of the benefits from the NEES-EUA acquisition be shared between customers and
18 National Grid-NEES. The sharing mechanism we propose is fair and efficient. It provides
19 customers with $34.6 million of up-front value through the rate freeze, (Exhibit MEJ-5,
20 page 1, line 6 ($48,773,235 - $14,186,956 = $34,586,279)), and with matching savings
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 38 of 44
1 throughout the remainder of the period. The proposal puts the risk on the Company to
2 realize the savings during the rate freeze period, and significantly postpones the recovery
3 for this portion of the National Grid premium. In short, the proposal is fair and efficient.
4 It assures that Narragansett's customers are better off economically because of the merger
5 with National Grid and EUA, and the future consolidations that will be produced from our
6 new, larger and more financially sound organization.
7
8 Q. Wouldn't the benefits of the EUA acquisition be achieved without the National Grid
9 NEES merger?
10 A. Without the National Grid-NEES merger, the full benefits of the EUA acquisition would
11 not be realized. First, it is unlikely that NEES would have agreed to acquire EUA at this
12 time absent the National Grid-NEES merger agreement. As described in NEES's proxy
13 statement dated March 26, 1999, over the course of 1998, the management and board of
14 directors of NEES determined that finding a strategic partner such as National Grid was in
15 the Company's best interest. As I have explained, the National Grid merger is essential for
16 the low cost NEES utilities to compete in the consolidation of the industry. An agreement
17 to acquire EUA by NEES prior to NEES finding a strategic partner could have
18 significantly impaired or delayed NEES's ability to find and reach agreement with a
19 strategic partner. Under these circumstances, an acquisition of EUA by NEES would
20 have been deferred for a year or longer and perhaps not have occurred at all.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 39 of 44
1 Second, while EUA had alternatives to an acquisition by NEES, in my opinion, those
2 alternatives would not have produced the level of savings or the rate reductions to EUA
3 customers that can be achieved in this proposed acquisition. I believe that EUA's
4 alternatives generally involved mergers with or acquisitions by higher-cost regional
5 utilities. Those utilities do not possess the track record to operate their own service
6 territories at the efficiency levels of NEES or EUA. Therefore they cannot produce the
7 economic benefits by combining with EUA that NEES can achieve. In addition, to the
8 extent savings are achieved, EUA customers are less likely to benefit from these savings
9 since they would most likely be applied to reducing the rates of the acquiring company.
10 EUA's customers could actually be faced with higher costs as the acquiring company
11 combined its higher cost operations with EUA's low-cost operations.
12
13 The EUA acquisition by NEES represents the first tangible benefits of the National Grid
14 NEES merger. Therefore, a portion of the savings should be used to compensate National
15 Grid for its investment in NEES.
16
17 VII. Future Earnings Reports.
18 Q. How would the Company propose to treat the acquisition premiums for earnings report
19 purposes after the merger?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 40 of 44
1 A. In order for the Company to assume the risks inherent in a long term rate freeze, the
2 Company needs a clarification from the Commission that the Company's amortization of
3 both the EUA and the National Grid premiums would be taken into account in
4 determining the Company's earnings. The Company requests the Commission provide this
5 clarification in any order it issues approving the rate plan.
6
7 VIII. FAS 71.
8 Q. Does the proposed rate plan have any other potential accounting ramifications?
9 A. Yes. Presently, both NEES and EUA apply Financial Accounting Standard No. 71
10 (FAS 71) to their regulated operations. Pursuant to FAS 71, regulated entities are
11 required to record regulatory assets and liabilities to reflect certain differences between
12 accounting and ratemaking principles. If the NEES-EUA and NEES-National Grid
13 transactions are completed under the rate plan proposed in this docket,
14 Narragansett/BVE/Newport and NEP/Montaup may be required to discontinue use of
15 FAS 71, effective upon consummation of the NEES-National Grid merger.
16
17 Q. Why might these companies be required to discontinue use of FAS 71?
18 A. In order to apply FAS 71, a regulated entity must meet certain criteria, including the
19 criteria that the entity's rates are based on its cost of service. It is my understanding that
20 in interpreting FAS 71, that the accounting profession considers long-term fixed rate plans
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 41 of 44
1 to be inconsistent with the criteria of FAS 71. The implementation of the distribution rate
2 freeze through 2004 may require Narragansett/BVE/Newport to discontinue use of FAS
3 71. In the case of NEP/Montaup, their ability to continue to use FAS 71 for costs being
4 recovered through contract termination charges depends on their continued recovery as
5 part of cost-based rates. Because the underlying distribution companies may no longer
6 qualify to use FAS 71, NEP/Montaup may also be required to discontinue use of FAS 71.
7
8 Q. What impact would the discontinuation of FAS 71 have on the financial statements of
9 NEES's affected subsidiaries including Narragansett?
10 A. There are several principal impacts. First, in establishing the initial balance sheet of
11 Narragansett/BVE/Newport and NEP/Montaup, following the consummation of the
12 mergers, regulatory assets would not be recognized. The impact of not recognizing
13 regulatory assets would be to increase the goodwill account by the amount of the
14 regulatory assets. In addition, because the operation of FAS 71 would be discontinued,
15 future differences between accounting and ratemaking principles would not lead to the
16 creation of regulatory assets and liabilities.
17
18 The discontinuation of FAS 71 could cause other differences in accounting to occur as
19 well. Narragansett/BVE/Newport and NEP/Montaup have traditionally adhered to the
20 accounting rules included in the FERC Uniform System of Accounts, which set of rules
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 42 of 44
1 have been adopted by the Commission with limited exceptions. While those rules are in
2 most cases the same accounting rules followed by unregulated companies, there may be
3 some exceptions. For example, the companies would no longer record AFDC, but would
4 instead record capitalized interest calculated in accordance with accounting standards for
5 unregulated businesses.
6
7 In addition, while we have described previously the amount of goodwill that we expect to
8 be allocated to the companies and the amortization period for such goodwill for
9 ratemaking purposes, those amounts could differ for accounting purposes.
10
11 Q. Would the discontinuation of FAS 71 affect rates?
12 A. No. The recovery of regulatory assets today reflects ratemaking, rather than accounting
13 principles. While goodwill would be increased as a result of discontinuing FAS 71, the
14 definition of the acquisition premium to be recovered through rates would not include
15 goodwill resulting from regulatory assets otherwise being recovered through rates.
16
17 IX. Other Regulatory Approvals.
18 Q. Mr. Jesanis what other regulatory approvals are necessary before the merger of the parent
19 companies, NEES and EUA, can be closed?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 43 of 44
1 A. Federal approval is required from the SEC under the Holding Company Act and approval
2 by FERC under Section 203 of the Federal Power Act. FERC will also approve the
3 consolidation of NEP and Montaup's transmission rates under Section 205 of the Federal
4 Power Act. Modifications to Montaup's contract termination charge, if required, will also
5 be implemented pursuant to Section 205. A Nuclear Regulatory Commission approval
6 under the Atomic Energy Act, will be required to transfer Montaup's nuclear entitlements
7 to NEP as part of the merger. Approval of state commissions in Connecticut, Vermont,
8 and New Hampshire where Montaup owns property may also be required. The
9 Massachusetts Department of Telecommunications and Energy has direct jurisdiction over
10 the consolidation of the operating companies in Massachusetts as well as a rate plan for
11 the combined companies. The merger has already received clearance from the Federal
12 Trade Commission under the Hart Scott Rodino Act that requires review for potential
13 anti-trust effects of mergers. A copy of the FERC filing was provided to the Commission.
14 Our filing with the SEC will be provided to the Commission when it is made. The other
15 filings will be provided on request.
16
17 Q. Are any other Rhode Island approvals needed for the parent company merger?
18 A. No. The merger of the parent companies does not require any Rhode Island approvals.
19 However, in order for BVE and Newport to be merged into Narragansett, the Companies
20 would need to obtain approval from the Division of Public Utilities and Carriers pursuant
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of M.E. Jesanis
Page 44 of 44
1 to Section 39-3-24 of Rhode Island General Laws once the law is clarified that a merger is
2 permissible under that section.
3
4 Q. What is the estimated time schedule for those proceedings?
5 A. We hope to complete all regulatory proceedings on the merger this year and implement
6 the rate plan on April 1, 2000.
7
8 Q. Does this complete your testimony?
9 A. Yes.
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibits
of
Michael E. Jesanis
Exhibit MEJ-1 NEES-EUA Merger Agreement
Exhibit MEJ-2 NEES-EUA Simplified Corporate Organization, Post-Closing
Exhibit MEJ-3 Rate Comparison for BVE, Newport and Narragansett
Exhibit MEJ-4 Economic Impact of Rate Plan
Exhibit MEJ-5 Economic Impact of Rate Freeze Extensions
Exhibit MEJ-6 Illustration of Calculation of Inflation Adjustment to
Distribution Rates in 2003 and 2004
Exhibit MEJ-7 Eastern Acquisition Premium and Transaction Cost
Amortization
Exhibit MEJ-8 Sharing of Savings Following NEES/EUA Merger
Exhibit MEJ-9 Present Value Analysis of Acquisition Costs and Savings
from NEES-EUA Consolidation
Exhibit MEJ-10 Rate Comparison by Utility
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-1
Exhibit MEJ-1
NEES-EUA Merger Agreement
See Separate Volume
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-2
Exhibit MEJ-2
NEES-EUA Simplified Corporate Organization, Post-Closing
<PAGE>
Exhibit MEJ-2
Simplified Corporate Structure
for Regulated Operating Companies
(Plan for Full Consolidation)
--------------------------------------------------------------------
-----------------
| National Grid |
| Group |
-----------------
| |
|
| |
|
| |
-------- -------
| NEES |<- - - - - - - - - - - - - - - - - - - - - | EUA |
-------- -------
| | |
| | ----------|
| | ---------------- ---------------- |
| |----|Mass. Electric|< - - - - -|Eastern Edison|------------|
| | ---------------- ---------------- |
| | | |
| | | |
- ---------- | | ---------------- ------------ |
|Granite | | |----|New England |< - - - - -| Montaup | |
| State |-----| | | Power | ------------ |
|Electric| | ---------------- - - - - - - - - - - - - - - |
- ---------- | | -------------------- | |
| | | Blackstone Valley |-|-----|
| ---------------- | -------------------- | |
|----|Narragansett |< - - -| | |
---------------- | ------------ | |
| | Newport |----------|-----|
| ------------ |
- - - - - - - - - - - - - -
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.______
Exhibit MEJ-3
Page 1 of 7
Narragansett Electric Company
Blackstone Valley Company and Newport Electric Corporation
Effect on Individual Billing Components at Rate Merger
Narraganset Blackstone Newport
----------- ---------- -------
DISTRIBUTION WITHOUT MERGER
<S> <C> <C> <C>
(1) Average Rate (Exhibit JMM-2, Column 1, Line 1) 2.967 3.003 4.189
(2) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(3) Revenue (Line (1) * Line (2) * 10,000) $153,245,550 $ 39,939,900 $ 22,788,160
- ----------------------------------------------------------------------------------------------------------------
DISTRIBUTION WITH MERGER
(4) Average Rate (Exhibit JMM-2, Column 2, Line 1) 2.967 2.852 3.568
(5) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
---- ----- ---
(6) Revenue (Line (4) * Line (5) * 10,000) $153,245,550 $ 37,931,600 $ 19,409,920
- ----------------------------------------------------------------------------------------------------------------
(7) BENEFIT TO TOTAL CUSTOMERS (LINE (3) + LINE (6)) $0 $2,008,300 $ 3,378,240
--
- ----------------------------------------------------------------------------------------------------------------
TRANSMISSION WITHOUT MERGER
(8) Average Rate (Exhibit JMM-2, Column 1, Line 4) 0.466 0.278 0.273
(9) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(10) Revenue (Line (8) * Line (*8) * 10,000) $ 24,068,900 $ 3,697,400 $ 1,485,120
- ----------------------------------------------------------------------------------------------------------------
TRANSMISSION WITH MERGER
(11) Average Rate (Exhibit JMM-2, Column 2, Line 4) 0.466 0.278 0.273
(12) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(13) Revenue (Line (11) * Line (12) * 10,000) $ 24,068,900 $ 3,697,400 $ 1,485,120
- ----------------------------------------------------------------------------------------------------------------
(14) BENEFIT TO TOTAL CUSTOMERS (LINE (10) + LINE (13) $0 $0 $0
- ----------------------------------------------------------------------------------------------------------------
TRANSITION WITHOUT MERGER
(15) Average Rate (Exhibit JMM-2, Column 1, Line 5) 1.150 2.320 2.340
(16) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75 5,165 1,330 544
----- ----- ---
(17) Revenue (Line (15) * Line (16) * 10,000) $ 59,397,500 $ 30,856,000 $ 12,729,600
- ----------------------------------------------------------------------------------------------------------------
TRANSITION WITH MERGER
(18) Average Rate (Exhibit JMM-2, Column 2, Line 5) 1.150 2.320 2.340
(19) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- -----
(20) Revenue (Line (18) * Line (19) * 10,000) $ 59,397,500 $ 30,856,000 $ 12,729,600
- ----------------------------------------------------------------------------------------------------------------
(21) BENEFIT TO TOTAL CUSTOMERS (LINE (17) + LINE (20) $0 $0 $0
- ----------------------------------------------------------------------------------------------------------------
(22) TOTAL BENEFIT (COST) TO CUSTOMERS (LINE (7)+LINE (14)
+LINE (21)) $0 $ 2,008,300 $ 3,378,240
(23) TOTAL RETAIL DELIVERY RATE W/O MERGER
(INCL. .230(CENT)DSM) 4.813 5,831 7.032
(24) TOTAL RETAIL DELIVERY RATE W/MERGER
(INCL. .230(CENT)DSM) 4.813 5.680 6.411
(25) % BENEFIT (COST) TO CUSTOMERS 0.00% 2.59% 8.83%
- ----------------------------------------------------------------------------------------------------------------
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.______
Exhibit MEJ-3
Page 2 of 7
DISTRIBUTION 2000
(1) Average Rate (Exhibit JMM-2, Column 2, Line 1) 2.967 2.852 3.568
(2) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(3) Revenue (Line (1) * Line (2) * 10,000) $ 153,245,550 $ 37,931,600 $ 19,409,920
- ----------------------------------------------------------------------------------------------------------------
DISTRIBUTION 2001
(4) Average Rate (Exhibit JMM-2, Column 3, Line 1 and Line (1a)) 3.006 2.891 3.607
(5) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(6) Revenue (Line (4) * Line (5) * 10,000) $ 155,259,900 $ 38,450,300 $ 19,622,080
- ----------------------------------------------------------------------------------------------------------------
(7) BENEFIT TO TOTAL CUSTOMERS (LINE (3) + LINE (6)) ($2,014,350) ($518,700) ($212,160)
- ----------------------------------------------------------------------------------------------------------------
TRANSMISSION 2000
(8) Average Rate (Exhibit JMM-2, Column 2, Line 4) 0.466 0.278 0.273
(9) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(10) Revenue (Line (8) * Line (8) * 10,000) $ 24,068,900 $ 3,697,400 $ 1,485,120
- ----------------------------------------------------------------------------------------------------------------
TRANSMISSION 2001
(11) Average Rate (Exhibit JMM-2, Column 3, Line 4) 0.409 0.429 0.431
(12) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(13) Revenue (Line (11) * Line (12) * 10,000) $ 21,124,850 $ 5,705,700 $ 2,344,640
- ----------------------------------------------------------------------------------------------------------------
(14) BENEFIT TO TOTAL CUSTOMERS (LINE (10) + LINE (13) $ 2,944,050 ($2,008,300) ($859,520)
- ----------------------------------------------------------------------------------------------------------------
TRANSITION 2000
(15) Average Rate (Exhibit JMM-2, Column 2, Line 5) 1.150 2.320 2.340
(16) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(17) Revenue (Line (15) * Line (16) * 10,000) $ 59,397,500 $ 30,856,000 $ 12,729,600
- ----------------------------------------------------------------------------------------------------------------
TRANSITION 2001
(18) Average Rate (Exhibit JMM-2, Column 3, Line 5) 1.150 1.759 1.759
(19) Projected GWh Sales (Exhibit MEJ-4, Column 1, Line (5)/.75) 5,165 1,330 544
----- ----- ---
(20) Revenue (Line (18) * Line (19) * 10,000) $ 59,397,500 $ 23,394,700 $ 9,568,960
- ----------------------------------------------------------------------------------------------------------------
(21) BENEFIT TO TOTAL CUSTOMERS (LINE 917) + LINE (20)) $0 $ 7,461,300 $ 3,160,640
- ----------------------------------------------------------------------------------------------------------------
(22) TOTAL BENEFIT (COST) TO CUSTOMERS (LINE (7)+LINE (14)
+LINE (21)) $ 929,700 $ 4,934,300 $ 2,088,960
(23) TOTAL RETAIL DELIVERY RATE W/O MERGER
(INCL. .230(CENT)DSM) 4.813 5.680 6.411
(24) TOTAL RETAIL DELIVERY RATE W MERGER
(INCL. .230(CENT)DSM) 4.795 5.309 6.027
(25) % BENEFIT (COST) TO CUSTOMERS 0.37% 6.53% 5.99%
</TABLE>
<PAGE>
Average Delivery Costs in Rhode Island
Pre Rate Plan 2000 and Post Rate Plan 2000
Exhibit MEJ-3
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Pre and Post Rate Plans for Narragansett, Blackstone
Valley and Newport.
Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent
between and including 0.0 and 8.0 cents per kWh).
[Bar Chart lists four sets of rates for each of Narragansett, Blackstone Valley
and Newport: (i) distribution, (ii) transmission, (iii) transition, and (iv)
total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Narragansett:
Pre Rate Plan 3.197 0.466 1.150 4.813
Post Rate Plan 3.197 0.466 1.150 4.813
Blackstone Valley:
Pre Rate Plan 3.233 0.278 2.320 5.831
Post Rate Plan 3.082 0.278 2.320 5.680
Newport:
Pre Rate Plan 4.419 0.273 2.340 7.032
Post Rate Plan 3.798 0.273 2.340 6.411
</TABLE>
[NEES Logo]
Page 3 of 7
<PAGE>
Average Delivery Costs in Rhode Island
Post Rate Plan 2000 and 2001
Exhibit MEJ-3
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Post Rate Plan 2000 and 2001 for Narragansett,
Blackstone Valley and Newport.
Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent
between and including 0.0 and 8.0 cents per kWh).
[Bar Chart lists four sets of rates for each of Narragansett, Blackstone Valley
and Newport: (i) distribution, (ii) transmission, (iii) transition, and (iv)
total rates. Total rates equal the sum of distribution, transmission and
transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Narragansett:
2000 3.197 0.466 1.150 4.813
2001 3.236 0.409 1.150 4.795
Blackstone Valley:
2000 3.082 0.278 2.320 5.680
2001 3.121 0.429 1.759 5.309
Newport:
2000 3.798 0.273 2.340 6.411
2001 3.837 0.431 1.759 6.027
</TABLE>
[NEES Logo]
Page 4 of 7
<PAGE>
Average Delivery Costs for Blackstone Valley
Exhibit MEJ-3
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Average delivery costs for Blackstone Valley at Jan.
2000, Apr. 2000, 2001, 2002, 2003 and 2004.
Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent
between and including 0.0 and 8.0 cents per kWh).
[Bar Chart lists four sets of rates for Blackstone Valley: (i) distribution,
(ii) transmission, (iii) transition, and (iv) total rates. Total rates equal the
sum of distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Date Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Jan. 2000 3.233 0.278 2.320 5.831
Apr. 2000 3.082 0.278 2.320 5.680
2001 3.121 0.429 1.759 5.309
2002 3.121 0.429 1.859 5.409
2003 3.121 0.429 1.446 4.996
2004 3.121 0.429 1.298 4.848
</TABLE>
[NEES Logo]
Page 5 of 7
<PAGE>
Average Delivery Costs for Narragansett
Exhibit MEJ-3
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Average delivery costs for Narragansett at Jan. 2000,
Apr. 2000, 2001, 2002, 2003 and 2004.
Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent
between and including 0.0 and 8.0 cents per kWh).
[Bar Chart lists four sets of rates for Narragansett: (i) distribution, (ii)
transmission, (iii) transition, and (iv) total rates. Total rates equal the sum
of distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Date Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Jan. 2000 3.197 0.466 1.150 4.813
Apr. 2000 3.197 0.466 1.150 4.813
2001 3.236 0.409 1.150 4.795
2002 3.236 0.409 1.150 4.795
2003 3.236 0.409 1.150 4.795
2004 3.236 0.409 1.150 4.795
</TABLE>
[NEES Logo]
Page 6 of 7
<PAGE>
Average Delivery Costs for Newport
Exhibit MEJ-3
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Average delivery costs for Newport at Jan. 2000, Apr.
2000, 2001, 2002, 2003 and 2004.
Y-axis (left side of chart): Cents per kWh(listed in increments of 1.0 cent
between and including 0.0 and 8.0 cents per kWh).
[Bar Chart lists four sets of rates for Newport: (i) distribution, (ii)
transmission, (iii) transition, and (iv) total rates. Total rates equal the sum
of distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Date Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Jan. 2000 4.419 0.273 2.340 7.032
Apr. 2000 3.798 0.273 2.340 6.411
2001 3.837 0.431 1.759 6.027
2002 3.837 0.431 1.859 6.127
2003 3.837 0.431 1.446 5.714
2004 3.837 0.431 1.298 5.566
</TABLE>
[NEES Logo]
Page 7 of 7
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-4
Exhibit MEJ-4
Economic Impact of Rate Plan
<PAGE>
<TABLE>
<CAPTION>
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric
4YR_TOTAL BVE/Newport Electric
19-May-99 R.I.P.U.C. Docket No. _______
Exhibit MEJ-4
Page 1 of 4
Narragansett Electric Company
Blackstone Valley Electric Company and Newport Electric Corporation
Total Combined Effect of Retail Delivery Service Billings
With a Four Year Distribution Rate Freeze
2000 2001 2002 2003 2004 Cumulative
Increase/(Decrease):
<S> <C> <C> <C> <C> <C> <C>
(1) Blackstone Valley Electric Company ($1,506,225) ($4,685,052) ($6,060,292) ($9,336,185) ($11,984,285)
(2) Newport Electric Corporation ($2,533,680) ($4,656,091) ($5,341,282) ($6,876,463) ($8,153,143)
(3) Narragansett Electric Company $0 ($1,606,730) ($4,604,160) ($5,076,480) ($6,748,560)
(4) Combined Comany ($4,039,905) ($10,947,872) ($16,005,734) ($21,289,129) ($26,885,988) ($79,168,628)
(5) Cumulative Effect ($4,039,905) ($14,987,777) ($30,993,511) ($52,282,640) ($79,168,628)
- ----------------------------------------------------------------------------------------------------------------------------------
(1) Page 1, Line (6)
(2) Page 2, Line (6)
(3) Lage 3, Line (6)
(4) Line (1) + Line (2) + Line (3)
(5) Accumulation of Line (4)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric
4YR_BVE SAVING BVE/Newport Electric
19-May-99 R.I.P.U.C. Docket No. _______
Exhibit MEJ-4
Page 2 of 4
Blackstone Valley Electric Company
Estimated Reduction in Retail Delivery Service Billings
With a Four Year Distribution Rate Freeze
2000 2001 2002 2003 2004 Cumulative
Average Retail Delivery Rate -
<S> <C> <C> <C> <C> <C> <C>
(1) With Merger on April 1, 2000 5.680 5.309 5.409 4.996 4.848
(2) Assuming No Merger 5.831 5.657 5.855 5.674 5.704
(3) cents/kWh Reduction in Retail
Delivery Rate (0.151) (0.348) (0.446) (0.678) (0.856)
(4) % Reduction in Retail Delivery Rate -2.6% -6.2% -7.6% -11.9% -15.0%
(5) Forecasted MWh Sales 997,500 1,346,024 1,360,074 1,377,851 1,399,848
(6) $ Reduction in Retail Delivery Rate ($1,506,225) ($4,685,052) ($6,060,292) ($9,336,185) ($11,984,285) ($33,572,039)
(7) Cumulative Reduction ($1,506,225) ($6,191,277) ($12,251,569) ($21,587,754) ($33,572,039)
- ----------------------------------------------------------------------------------------------------------------------------------
(1) Exhibit JMM - 2, Page 2, Line (6)
(2) Exhibit JMM - 2, Page 2, January 1, 2000, Line (1) (inflated at 2.2% per year) + Line (2) + Line (4) + Transition Charge from
BVE RVC filing
(3) Line (1) - Line (2)
(4) Line (3)/Line (2)
(5) Forecast (from CTC filings)
(6) Line (3) x Line (5)
(7) Accumulation of Line (6)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric
4YR_NECO SAVING BVE/Newport Electric
19-May-99 R.I.P.U.C. Docket No. _______
Exhibit MEJ-4
Page 3 of 4
Narragansett Electric Company
Estimated Increase in Retail Delivery Service Billings
With a Four Year Distribution Rate Freeze
2000 2001 2002 2003 2004 Cumulative
Average Retail Delivery Rate -
<S> <C> <C> <C> <C> <C> <C>
(1) With Merger on April 1, 2000 4.813 4.795 4.795 4.795 4.795
(2) Assuming No Merger 4.813 4.826 4.883 4.891 4.921
(3) cents/kWh Reduction in Retail
Delivery Rate 0.000 (0.031) (0.088) (0.096) (0.126)
(4) % Reduction in Retail Delivery Rate 0.0% -0.6% -1.8% -2.0% -2.6%
(5) Forecasted MWh Sales 3,873,750 5,183,000 5,232,000 5,288,000 5,356,000
(6) $ Reduction in Retail Delivery Rate $0 ($1,606,730) ($4,604,160) ($5,076,480) ($6,748,560) ($18,035,930)
(7) Cumulative Reduction $0 ($1,606,730) ($6,210,890) ($11,287,370) ($18,035,930)
- ----------------------------------------------------------------------------------------------------------------------------------
(1) Exhibit JMM - 2, Page 2, Line (6)
(2) Exhibit JMM - 2, Page 2, January 1, 2000, Line (1) (inflated at 2.2% per year) + Line (2) + Line (4) + Transition Charge
from Narr. RVC filing + Cost of Removal Adjustment (Narragansett only) of 0.068 cents/kWh starting in 2001
(3) Line (1) - Line (2)
(4) Line (3)/Line (2)
(5) Forecast (from CTC filings)
(6) Line (3) x Line (5)
(7) Accumulation of Line (6)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\123data\JAMES\M&A\BASE\Mej-3.wk4 Narragansett Electric
4YR_NEW SAVINGS BVE/Newport Electric
19-May-99 R.I.P.U.C. Docket No. _______
Exhibit MEJ-4
Page 4 of 4
Newport Electric Corporation
Estimated Reduction in Retail Delivery Service Billings
With a Four Year Distribution Rate Freeze
2000 2001 2002 2003 2004 Cumulative
Average Retail Delivery Rate -
<S> <C> <C> <C> <C> <C> <C>
(1) With Merger on April 1, 2000 6.411 6.027 6.127 5.714 5.566
(2) Assuming No Merger 7.032 6.874 7.088 6.935 6.993
(3) cents/kWh Reduction in Retail
Delivery Rate (0.621) (0.847) (0.961) (1.221) (1.427)
(4) % Reduction in Retail Delivery Rate -8.8% -12.3% -13.6% -17.6% -20.4%
(5) Forecasted MWh Sales 408,000 549,613 555,606 563,367 571,358
(6) $ Reduction in Retail Delivery
Rate ($2,533,680) ($4,656,091) ($5,341,282) ($6,876,463) ($8,153,143) ($27,560,659)
(7) Cumulative Reduction ($2,533,680) ($7,189,771) ($12,531,053) ($19,407,516) ($27,560,659)
- ----------------------------------------------------------------------------------------------------------------------------------
(1) Exhibit JMM - 2, Page 4, Line (6)
(2) Exhibit JMM - 2, Page 4, January 1, 2000, Line (1) (inflated at 2.2% per year) + Line (2) + Line (4) + Transition Charge
from NEC RVC filing
(3) Line (1) - Line (2)
(4) Line (3)/Line (2)
(5) Forecast (from CTC filings)
(6) Line (3) x Line (5)
(7) Accumulation of Line (6)
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-5
Exhibit MEJ-5
Economic Impact of Rate Freeze Extensions
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ___________
Exhibit MEJ-5
Page 1 of 3
Narragansett Electric Company
Blackstone Valley Company and Newport Electric Corporation
Estimated Value of Four Year Distribution Rate Freeze
DISTRIBUTION WITHOUT MERGER 2000 2001 2002 2003 2004
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
TOTAL OF INDIVIDUAL COMPANIES
(1) Total Revenue $157,940,303 $216,670,421 $223,630,624 $231,183,289 $239,506,709 $1,068,931,347
(2) Cumulative Total Revenue $157,940,303 $374,610,724 $598,241,348 $829,424,638 $1,068,931,347
DISTRIBUTION WITH MERGER
TOTAL OF INDIVIDUAL COMPANIES
(3) Total Revenue $157,940,303 $212,005,610 $214,108,480 $216,568,800 $219,534,920 $1,020,158,113
(4) Cumulative Total Revenue $157,940,303 $369,945,913 $584,054,393 $800,623,193 $1,020,158,113
BENEFIT TO ALL CUSTOMERS
(5) Annual $0 $4,664,811 $9,522,144 $14,614,489 $19,971,789 $48,773,235
(6) Cumulative $0 $4,664,811 $14,186,959 $28,801,445 $48,773,235
</TABLE>
(1) Page 3, Line (13)
(2) Page 3, Line (14)
(3) Page 2, Line (13
(4) Page 2, Line (14)
(5) Line (1) - Line (3)
(6) Accumulation of Line (5)
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _________
Exhibit MEJ-5
Page 2 of 3
Narragansett Electric Company
Blackstone Valley Company and Newport Electric Corporation
Estimated Value of Four Year Distribution Rate Freeze
DISTRIBUTION WITHOUT MERGER 2000 2001 2002 2003 2004
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
NARRAGANSETT ELECTRIC
(1) Average Rate 2.967 2.967 2.967 2.967 2.967
(2) Projected GWh Sales 3,874 5,183 5,232 5,288 5,356
----- ----- ----- ----- -----
(3) Revenue $114,934,163 $153,779,610 $155,233,440 $156,894,960 $158,912,520 $739,754,693
(4) Cumulative Revenue $114,934,163 $268,713,773 $423,947,213 $580,842,173 $739,754,693
BLACKSTONE VALLEY ELECTRIC
(5) Average Rate 2.852 2.852 2.852 2.852 2.852
(6) Projected GWh Sales 998 1,346 1,360 1,378 1,400
---- ----- ----- ----- ------
(7) Revenue $28,448,700 $38,387,920 $38,787,200 $39,300,560 $39,928,000 $184,852,380
(8) Cumulative Revenue $28,448,700 $66,836,620 $105,623,820 $144,924,380 $184,852,380
NEWPORT ELECTRIC
(9) Average Rate 3.568 3.568 3.568 3.568 3.568
(10) Projected GWh Sales 408 556 563 571 580
--- --- --- --- ---
(11) Revenue $14,557,440 $19,838,080 $20,087,840 $20,373,280 $20,694,400 $95,551,040
(12) Cumulative Revenue $14,557,440 $34,395,520 $54,483,360 $74,856,640 $95,551,040
TOTAL OF INDIVIDUAL COMPANIES
(13) Total Revenue $157,940,303 $212,005,610 $214,108,480 $216,568,800 $219,534,920 $1,020,158,113
(14) Cumulative Total Revenue $157,940,303 $369,945,913 $584,054,393 $800,623,193 $1,020,158,113
</TABLE>
(1) Exhibit JMM - 2, Page 3, Line (1)
(2) Forecast (from CTC filings)
(3) Line (1) * Line (2)
(4) Accumulation of Line (3)
(5) Exhibit JMM - 2, Page 2, Line (1)
(6) Forecast (from CTC filings)
(7) Line (5) * Line (6)
(8) Accumulation of Line (7)
(9) Exhibit JMM - 2, Page 4, Line (1)
(10) Forecast (from CTC filings)
(11) Line (9) * Line (10)
(12) Accumulation of Line (11)
(13) Line (3) + Line (7) + Line (12)
(14) Line (4) + Line (8) + Line (13)
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _________
Exhibit MEJ-5
Page 3 of 3
Narragansett Electric Company
Blackstone Valley Company and Newport Electric Corporation
Estimated Value of Four Year Distribution Rate Freeze
DISTRIBUTION WITHOUT MERGER 2000 2001 2002 2003 2004
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
NARRAGANSETT ELECTRIC
(1) Average Rate (inflation
begining in 2001) 2.967 3.032 3.099 2.967 3.237
(2) Projected GWh Sales 3,874 5,183 5,232 5,288 5,356
----- ----- ----- ----- -----
(3) Revenue $114,934,163 $157,162,761 $162,138,844 $167,479,509 $173,365,109 $775,080,387
(4) Cumulative Revenue $114,934,163 $272,096,924 $434,235,768 $601,715,278 $775,080,387
BLACKSTONE VALLEY ELECTRIC
(5) Average Rate (inflation
beginning in 2001) 2.852 2.915 2.979 3.045 3.112
(6) Projected GWh Sales 998 1,346 1,360 1,378 1,400
---- ----- ----- ----- -----
(7) Revenue $28,448,700 $39,235,900 $40,514,400 $41,960,100 $43,568,000 $193,727,100
(8) Cumulative Revenue $28,448,700 $67,684,600 $108,199,000 $150,159,100 $193,727,100
NEWPORT ELECTRIC
(9) Average Rate (inflation
beginning in 2001) 3.568 3.646 3.726 3.808 3.892
(10) Projected GWh Sales 408 556 563 571 580
--- --- --- --- ---
(11) Revenue $14,557,440 $20,271,760 $20,977,380 $21,743,680 $22,573,600 $100,123,860
(12) Cumulative Revenue $14,557,440 $34,829,200 $55,806,580 $77,550,260 $100,123,860
TOTAL OF INDIVIDUAL COMPANIES
(13) Total Revenue $157,940,303 $216,670,421 $223,630,624 $231,183,289 $239,506,709 $1,068,931,347
(14) Cumulative Total Revenue $157,940,303 $374,610,724 $598,241,348 $829,424,638 $1,068,931,347
</TABLE>
(1) Exhibit JMM - 2, Page 3, Line (1), April 1, 2000, inflated at
2.2 percent
(2) Forecast (from CTC filings)
(3) Line (1) * Line (2)
(4) Accumulation of Line (3)
(5) Exhibit JMM - 2, Page 2, Line (1), April 1, 2000, inflated at
2.2 percent
(6) Forecast (from CTC filings)
(7) Line (5) * Line (6)
(8) Accumulation of Line (7)
(9) Exhibit JMM - 2, Page 4, Line (1), April 1, 2000, inflated at
2.2 percent
(10) Forecast (from CTC filings)
(11) Line (9) * Line (10)
(12) Accumulation of Line (11)
(13) Line (3) + Line (7) + Line (12)
(14) Line (4) + Line (8) + Line (13)
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-6
Exhibit MEJ-6
Illustration of Calculation of Inflation Adjustment
to Distribution Rates in 2003 and 2004
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ________
Exhibit MEJ-6
Page 1 of 1
Narragansett Electric Company
Illustration of Calculation Inflation Adjustment to Distribution Rates
in 2003 and 2004
3% Annual Annual Benchmark Illustrative
Annual CPI Percentage Inflation in 75% of Distribution Distribution
End of Month Inflation Index Change Excess of 3% Excess Rate Adjustment
------------ --------- ----- ------ ------------ ------ ---- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
(1) (2) (3) (4) (5) (6) (7) (8)
September 2001 136.6 2/
September 2002 140.9 2/
Annual Total 3.000% 1/ 3.148% 3/ 0.148% 4/ 0.111% 5/ 2.993 6/ 0.003 7/
September 2002 140.9 2/
September 2003 144.8 2/
Annual Total 3.000% 1/ 2.768 3/ n/a 2.996 8/ n/a
</TABLE>
- -----------------------------------------------------------------------------
1/ Annual rate of 3% for inflation benchmark
2/ Historical Consumer Price Index - All Urban Consumers (CPI-U) obtained
from the Bureau of Labor Statistics
3/ Percentage change between prior month's CPI-U and current month's CPI-U
4/ Difference between actual inflation (3/) and assumed inflation
benchmark of 3% (1/)
5/ 75% x excess inflation in 4/
6/ Exhibit JMM-2, Page 1, April 1, 2000, Line (1)
7/ 75% of excess inflation in 5/ multiplied by benchmark distribution rate
in 6/
8/ Prior year net distribution charge (6/) + (7/) as current year's
distribution benchmark
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-7
Exhibit MEJ-7
Eastern Acquisition Premium and Transaction Cost Amortization
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ________
Exhibit MEJ-7
Page 1 of 3
NEES/EUA Acquisition Premium
Amortization of Acquisition Premium and Transaction Costs
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
Allocation to States 12/
-------------------------------
Massachusetts Rhode Island
Total (Eastern Edison)
1 ACQUISITION PREMIUMS: 100.00% 73.91% 26.09%
--------------------- ------- ------ ------
<S> <C> <C> <C>
2 Total Acquisition Premium 1/ $260,000
3 Less: Allocation to Unregulated Subsidiaries 2/ 28,600
-------
4 Net Acquisition Premium to Regulated Subsidiaries 3/ $231,400 $171,028 $60,372
5
6 Times Tax Gross-Up Factor 4/ 1.6454 1.5384
------ ------
7
8 Acquisition Premium at Revenue Requirement 5/ $374,285 $281,409 $92,876
9
10 Amortization Period (Years) 6/ 20 20 20
11
12 Amortization per year for Acquisition Premiums 7/ $18,714 $14,070 $4,644
------- ------- ------
13
14
15 TRANSACTION COSTS:
16 Total Estimated Transaction Costs 8/ $63,600 $47,007 $16,593
17
18 Amortization Period (Years) 9/ 20 20 20
19
20 Amortization per year for Transaction Costs 10/ $3,180 $2,351 $829
------ ------ ----
21
22 TOTAL AMORTIZATION PER YEAR 11/ $21,894 $16,421 $5,473
------- ------- ------
</TABLE>
Notes:
1/ Exhibit MEJ-7, Page 3, Line 15.
2/ Allocation of costs to unregulated subsidiaries. (Exhibit MEJ-7, Page
3, Line 35 times Line 2.)
3/ Line 1 minus Line 2.
4/ For Massachusetts: 1 plus Federal Income Tax (FIT) Rate divided by 1
minus FIT rate plus State Income Tax (SIT) rate divided by 1 minus
SIT rate divided by 1 minus FIT rate
(1+(35%/(1-35%))+((6.5%/(1-6.5%)/(1-35%))). For Rhode Island: 1 plus
Federal Income Tax (FIT) Rate divided by 1 minus FIT rate.
(1+(35%/(1-35%))).
5/ Line 4 times Line 6.
6/ Proposed amortization period for Acquisition Premiums
7/ Line 8 divided by Line 10.
8/ Total Estimated Transaction costs to complete NEES/EUA merger.
9/ Proposed amortization period for Transaction Costs.
10/ Line16 divided by Line 18.
11/ Line 12 plus Line 20.
12/ Exhibit MEJ-7, Page 2, Column (f).
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ____
Exhibit MEJ-7
Page 2 of 3
NEES/EUA Acquisition Premium
Allocation of Acquisition Premium and Transaction Costs
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
1998 1997 1996 Total 3 Year Ave.
MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation
to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage
Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/
------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
1 Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328
2 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938
--------- --------- --------- ---------
3 Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 73.91%
---------- ---------- ---------- ----------
4
5 Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333
6 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965
7 Newport Electric 542,466 536,209 525,372 1,604,047
------- ------- ------- ---------
8 Total Rhode Island 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 26.09%
--------- --------- --------- ---------- --------- ------
9
Grand Total 26,109,893 25,430,615 25,192,103 76,732,611 25,577,537 100.00%
---------- ---------- ---------- ---------- ---------- -------
</TABLE>
Notes:
1/ 1998 FERC Form 1, Pages 300-301.
2/ 1997 FERC Form 1, Pages 300-301.
3/ 1996 FERC Form 1, Pages 300-301.
4/ Sum of Columns (a) through (c).
5/ Column (d) divided by three.
6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)).
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ____
Exhibit MEJ-7
Page 3 of 3
NEES/EUA Acquisition Premium
Amortization of Acquisition Premium and Transaction Costs
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation
Study
1 CALCULATION OF ACQUISITION PREMIUM:
2 Acquisition Price Per Share $31.00 1/
3
4 Outstanding EUA Common Shares
5 as of December 31, 1998 20,435,997 2/
----------
6
7 Total Acquisition Cost $633,516 3/
8
9
10 EUA Consolidated Net Book Value
11 as of December 31, 1998 $373,674 4/
----------
12
13 Total Acquisition Premium $259,842 5/
14
15 Total Acquisition Premium (Rounded) $260,000 6/
----------
16
17
18 CALCULATION OF ALLOCATION TO UNREGULATED SUBSIDIARIES:
19
20 Net Book Value of Unregulated Subsidiaries as of
21 December 31, 1998:
22
23 EUA Cogenex $48,361
24 EUA Energy Inv. (24,204)
25 EUA Energy Services (34)
26 EUA Ocean State 16,546
27 EUA Telecommunications (131)
-----
28 Total Net Book Value of Unregulated Subsidiaries 40,538 7/
------
29
30 Net Book Value of EUA Consolidated
31 as of December 31, 1998 (In Thousands) 373,674 8/
32
33 Percentage of Unregulated Subsidiaries to Total 10.85% 9/
34
35 Percentage (Rounded) 11.00% 10/
Notes:
1/ Acquisition Price per Share per NEES/EUA Merger Agreement.
2/ EUA common shares outstanding as of December 31, 1998 per EUA annual
report.
3/ Line 2 times Line 5.
4/ Net Book Value (Common Equity) as of December 31, 1998 per EUA annual
report before any adjustments required under purchase accounting
rules.
5/ Line 7 minus Line 11.
6/ Line 13 rounded to tens of millions.
7/ Net Book Value (Common Equity) as of December 31, 1998 before any
adjustments required under purchase accounting rules.
8/ Net Book Value (Common Equity) as of December 31, 1998 before any
adjustments required under purchase accounting rules.
9/ Line 28 divided by Line 31.
10/ Line 33 rounded to nearest whole percent.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-8
Exhibit MEJ-8
Sharing of Savings Following NEES/EUA Merger
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. __________
Exhibit MEJ-8
Page 1 of 1
NEES/EUA ACQUISITION PREMIUM
Sharing of Savings following NEES/EUA Merger
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
Rhode Island
Apportionment
Rhode Island of EUA Sharing of Net Savings
Anticipated Apportionment Acquisition Rhode Island National Grid Rhode Island
Savings (25.39%) Premium Recovery Net Savings Premium Customers
Year Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/
------------- ------------- ---------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
1 2005 $35,000 $ 8,887 $5,473 $ 3,414 $1,707 $1,707
2 2006 35,770 9,082 5,473 3,609 1,804 1,805
3 2007 36,557 9,282 5,473 3,809 1,905 1,904
4 2008 37,361 9,486 5,473 4,013 2,006 2,007
5 2009 38,183 9,695 5,473 4,222 2,111 2,111
6 2010 39,023 9,908 5,473 4,435 2,218 2,217
7 2011 39,882 10,126 5,473 4,653 2,326 2,327
8 2012 40,759 10,349 5,473 4,876 2,438 2,438
9 2013 41,656 10,576 5,473 5,103 2,552 2,551
10 2014 42,572 10,809 5,473 5,336 2,668 2,668
11 2015 43,509 11,047 5,473 5,574 2,787 2,787
12 2016 44,466 11,290 5,473 5,817 2,908 2,909
13 2017 45,444 11,538 5,473 6,065 3,033 3,032
14 2018 46,444 11,792 5,473 6,319 3,159 3,160
15 2019 47,466 12,052 5,473 6,579 3,290 3,289
16 2020 48,510 12,317 5,473 6,844 3,422 3,422
17 2021 and beyond 49,577 12,588 0 12,588 6,294 7/ 6,294 7/
</TABLE>
Notes:
1/ Anticipated Savings from NEES/EUA Merger in 2005 dollars escalated by
inflation of 2.2% per year.
2/ Column (a) times Rhode Island Savings Apportionment factor. (Exhibit
MEJ-9, Page 2, Line 3, column (f)).
3/ Exhibit MEJ-7, Page 1, Line 22.
4/ Column (b) minus Column (c).
5/ Proposed Merger Savings Sharing (Column (d) times 50%).
6/ Column (d) minus Column (e).
7/ Increases by inflation beginning in 2021.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-9
Exhibit MEJ-9
Present Value Analysis of Acquisition Costs and Savings
from NEES-EUA Consolidation
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit MEJ-9
Page 1 of 2
NEES/EUA Acquisition Premium
Net Present Value of Estimated Savings and Acquisition Premium
In Thousands of Dollars
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
Allocation to States 15/
------------------------------------------------
Massachusetts Rhode Island New Hampshire
Total (Eastern Edison)
<S> <C> <C> <C> <C>
1 NET PRESENT VALUE OF MEREER SAVINES: 100.00% 71.93% 25.39% 2.68%
-------- -------- -------- --------
2 Estimated Annual Savings 1/ $ 30,716 $ 22,094 $ 7,799 $ 823
3
4 Estimated After Tax Cost of Capital 2/ 7.50% 7.50% 7.50% 7.50%
5 Less: Estimated Inflation Rate 3/ 2.20% 2.20% 2.20% 2.20%
-------- -------- -------- --------
6 Net Discount Rate 4/ 5.30% 5.30% 5.30% 5.30%
7
8 Net Present Value of Estimated Annual Savings 5/ $579,547 $416,868 $147,151 $ 15,528
-------- -------- -------- --------
9
10
11 NET PRESENT VALUE OF MERGER COSTS:
12 Annual Amortization of Acquisition Premium 6/ $ 18,714 $ 14,070 $ 4,644
13
14 Net Present Value of Amortization of Acquisition
15 Premiums using 7.50% Discount Rate 7/ $190,780 $143,436 $ 47,343
-------- -------- --------
16
17
18 Annual Amortization of Transaction Premium 8/ $ 3,180 $ 2,351 $ 829
19
20 Net Present Value of Amortization of Acquisition
21 Premiums using 7.50% Discount Rate 9/ $ 32,418 $ 23,967 $ 8,451
-------- -------- --------
22
23 Total Net Present Value of Merger Costs 10/ $223,198 $167,403 $ 55,794
-------- -------- --------
24
25 Net Present Value of Excess Merger Savings 11/ $356,349 $249,465 $ 91,357 $ 15,528
26
27 Sharing of Excess Merger Savings 12/ 50% 50% 50% 50%
-------- -------- -------- --------
28
29 Allocation of Excess Merger Savings to National
30 Grid Acquisition Premium 13/ $178,174 $124,732 $ 45,679 $ 7,764
-------- -------- -------- --------
31
32 Allocation of Excess Merger Savings to Customers 14/ $178,175 $124,733 $ 45,678 $ 7,764
-------- -------- -------- --------
</TABLE>
Notes:
1/ $35 million of estimated savings in 2005 discounted to 1999 dollars by
inflation rate of 2.2%.
2/ Estimated after tax cost of capital.
3/ Estimated annual inflation rate.
4/ Line 4 minus Line 5.
5/ Line 2 divided by Line 6.
6/ Exhibit MEJ-7, Page 1, Line 12.
7/ Net Present Value of amortization of Acquisition Premium over 20
years.
8/ Exhibit MEJ-7, Page 1, Line 20.
9/ Net Present Value of amortization of Transaction Costs over 20 years.
10/ Line 15 plus Line 2 1.
ll/ Line 8 minus Line 23.
12/ Proposed Sharing of Excess Savings between customers and shareholders.
13/ Line 25 times Line 27.
14/ Line 25 minus Line 30.
15/ Exhibit MEJ-9, Page 2, Column (f).
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ________
Exhibit MEJ-9
Page 2 of 2
NEES/EUA Acquisition Premium
Allocation of Acquisition Premium and Transaction Costs
Illustrative Calculation pending completion of Acquisition Premium Allocation Study
1998 1997 1996 Total 3 Year Ave.
MWh Sales MWh Sales MWh Sales MWh Sales MWh Sales Allocation
to Ultimates to Ultimates to Ultimates to Ultimates to Ultimates Percentage
Column (a) 1/ Column (b) 2/ Column (c) 3/ Column (d) 4/ Column (e) 5/ Column (f) 6/
------------- ------------- ------------- ------------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C>
1 Massachusetts Electric 16,590,946 16,141,173 16,009,209 48,741,328
2 Eastern Edison 2,707,973 2,641,448 2,622,517 7,971,938
--------- --------- --------- ---------
3 Total Massachusetts 19,298,919 18,782,621 18,631,726 56,713,266 18,904,422 71.93%
---------- ---------- ---------- ----------
4
5 Narragansett Electric 4,977,637 4,822,669 4,778,027 14,578,333
6 Blackstone Valley Electric 1,290,871 1,289,116 1,256,978 3,836,965
7 Newport Electric 542,466 536,209 525,372 1,604,047
------- ------- ------- ---------
8 Total Rhode Island 6,810,974 6,647,994 6,560,377 20,019,345 6,673,115 25.39%
--------- --------- --------- ----------
9
10 Granite State Electric 718,452 693,879 699,569 2,111,900
------- ------- ------- ---------
11 Total New Hampshire 718,452 693,879 699,569 2,111,900 703,967 2.68%
------- ------- ------- --------- ------- -----
12
13 Grand Total 26,828,345 26,124,494 25,891,672 78,844,511 26,281,504 100.00%
---------- ---------- ---------- ---------- ---------- -------
</TABLE>
Notes:
1/ 1998 FERC Form 1, Pages 300-301.
2/ 1997 FERC Form 1, Pages 300-301.
3/ 1996 FERC Form 1, Pages 300-301.
4/ Sum of Columns (a) through (c).
5/ Column (d) divided by three.
6/ Ratio of Average MWh Sales to Total MWh Sales (Column (e)).
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit MEJ-10
Exhibit MEJ-10
Rate Comparison by Utility
<PAGE>
Comparison of Rhode Island and Massachusetts "Delivery" Rates
Residential Customer (500 kWh Usage)
(Cents per kWh)
Exhibit MEJ-10
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Rhode Island and Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to residential customers
(listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of ten Rhode Island and
Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii)
transition rates, and (iv) total rates. Total rates equal the sum of
distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
MECO 4.1 0.7 1.3 6.1
NECO 4.4 0.5 1.2 6.1
EECO 4.2 0.3 2.1 6.6
Camb 4.0 1.3 1.4 6.7
BVE 4.7 0.3 2.0 7.0
Newport 5.5 0.3 2.1 7.8
WMeco* 5.1 0.3 2.8 8.2
FG&E* 5.4 0.5 2.5 8.4
BECO 5.6 0.3 2.8 8.7
Comm 5.5 0.4 3.2 9.1
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of May 1, 1999.
Page 1 of 5
<PAGE>
Comparison of Rhode Island and Massachusetts "Delivery" Rates
Average G-1 Customer (6 kW Demand and 1,500 kWh Usage)
(Cents per kWh)
Exhibit MEJ-10
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Rhode Island and Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to average G-1 customers
(listed in increments of 2.0 cents between and including 0.0 and 10.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of ten Rhode Island and
Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii)
transition rates, and (iv) total rates. Total rates equal the sum of
distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
Camb 2.6 1.2 1.4 5.2
NECO 4.5 0.6 1.2 6.3
MECO 4.8 0.7 1.3 6.8
BVE 4.8 0.3 2.0 7.1
EECO 4.8 0.3 2.1 7.2
Comm 4.3 0.4 3.2 7.8
WMeco* 4.8 0.3 2.8 7.9
FG&E* 5.5 0.5 2.4 8.4
Newport 6.3 0.3 2.1 8.6
BECO 5.8 0.4 2.7 8.9
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of May 1, 1999.
Page 2 of 5
<PAGE>
Comparison of Rhode Island and Massachusetts "Delivery" Rates
Average G-2 Customer (50 kW Demand and 16,700 kWh Usage)
(Cents per kWh)
Exhibit MEJ-10
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Rhode Island and Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to average G-2 customers
(listed in increments of 2.0 cents between and including 0.0 and 8.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of ten Rhode Island and
Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii)
transition rates, and (iv) total rates. Total rates equal the sum of
distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
MECO 2.4 0.6 1.3 4.4
NECO 2.6 0.4 1.2 4.2
Camb 2.1 1.1 1.4 4.5
EECO 2.7 0.3 1.8 4.8
BVE 3.0 0.3 2.0 5.3
WMeco* 3.0 0.3 2.8 6.1
Newport 4.2 0.3 2.1 6.5
FG&E* 4.2 0.4 2.2 6.8
BECO 4.3 0.4 2.4 7.1
Comm 3.8 0.4 3.2 7.3
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of May 1, 1999.
Page 3 of 5
<PAGE>
Comparison of Rhode Island and Massachusetts "Delivery" Rates
Average G-3 Customer (610 kW Demand and 255,400 kWh Usage)
(Cents per kWh)
Exhibit MEJ-10
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Rhode Island and Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to average G-3 customers
(listed in increments of 1.0 cent between and including 0.0 and 7.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of ten Rhode Island and
Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii)
transition rates, and (iv) total rates. Total rates equal the sum of
distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
NECO 1.9 0.4 1.2 3.4
MECO 1.8 0.6 1.3 3.7
Camb 1.2 1.2 1.4 3.8
EECO 1.8 0.3 2.2 4.3
BVE 2.2 0.3 2.0 4.5
Comm 1.4 0.3 3.2 4.9
FG&E* 3.1 0.4 1.7 5.2
WMeco* 2.1 0.3 2.9 5.3
BECO 2.3 0.3 2.8 5.4
Newport 4.2 0.3 2.1 6.5
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of May 1, 1999.
Page 4 of 5
<PAGE>
Comparison of Rhode Island and Massachusetts "Delivery" Rates
Very Large C&I Customer (5,000 kW Demand and 2,000,000 kWh Usage)
(Cents per kWh)
Exhibit MEJ-10
[Vertical, Stacked Bar Chart]
X-axis (bottom of chart): Rhode Island and Massachusetts utilities.
Y-axis (left side of chart): Cents per kWh charged to very large C&I customers
(listed in increments of 1.0 cents between and including 0.0 and 7.0 cents per
kWh).
[Bar Chart lists four sets of rates for each of ten Rhode Island and
Massachusetts utilities (i) distribution rates, (ii) transmission rates, (iii)
transition rates, and (iv) total rates. Total rates equal the sum of
distribution, transmission and transition rates.]
<TABLE>
<CAPTION>
Utility Distribution Transmission Transition Total
<S> <C> <C> <C> <C>
NECO 1.7 0.4 1.2 3.3
MECO 1.8 0.6 1.3 3.7
BVE 1.7 0.3 2.0 4.0
Camb 1.2 1.4 1.4 4.0
EECO 1.8 0.3 2.2 4.3
Comm 1.1 0.3 3.2 4.7
WMeco* 1.7 0.3 3.0 5.0
FG&E* 3.1 0.4 1.7 5.2
BECO 2.3 0.3 2.8 5.4
Newport 3.7 0.3 2.1 6.0
</TABLE>
[NEES Logo]
(*) Rates do not include any adjustment reflecting divestiture.
Based on rates as of May 1, 1999.
Page 5 of 5
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ----------------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No. __________
Blackstone Valley Electric Company )
Newport Electric Corporation )
)
- ----------------------------------------
DIRECT TESTIMONY
OF
ROBERT G. POWDERLY
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ----------------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No. __________
Blackstone Valley Electric Company )
Newport Electric Corporation )
)
- ----------------------------------------
DIRECT TESTIMONY
OF
ROBERT G. POWDERLY
Table of Contents
Page
I. Qualifications.......................................................1
II. Purpose of Testimony.................................................3
Ill. Terms, Conditions, and Structure of the Transaction..................4
IV. Benefits to Customers, Employees and Shareholders....................8
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No. __________
Testimony of R. G. Powderly
Page 1 of 13
<S> <C>
1 I. Qualifications.
2 Q. Please state your name and business address.
3 A. My name is Robert G. Powderly and my business address is 750 West Center Street, West
4 Bridgewater, Massachusetts.
5
6 Q. By whom are you employed and in what capacity?
7 A. I am employed by EUA Service Corporation ("EUASC"). I am Executive Vice President
8 of Blackstone Valley Electric Company ("Blackstone"), Eastern Edison Company
9 ("Eastern"), Newport Electric Corporation ("Newport") and Montaup Electric Company
10 (Montaup). Additionally, I hold the same position for Eastern Utilities Associates
11 ("EUA"), the parent company of the above three retail affiliates, and for EUASC, the
12 service company for EUA subsidiaries. My areas of responsibility for regulated companies
13 in the EUA system include Customer Service, Human Resources, Information Systems,
14 and Rates.
15
16 Q. Please summarize your educational background and your professional qualifications.
17 A. I was graduated from the College of the Holy Cross in 1969 with a Bachelor of Arts
18 degree in mathematics. After serving five years in the U. S. Navy, I attended Northeastern
19 University, and received a Master of Science in Accounting degree in 1975. While in the
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 2 of 13
1 Navy, I was involved in the operation of naval nuclear propulsion units and in 1973 I
2 qualified as Engineer of Naval Nuclear Propulsion plants.
3
4 After graduate school, I was employed for almost four years by an international public
5 accounting firm (Ernst & Ernst, now called Ernst & Young). During this period, my
6 responsibilities included audits of publicly-held, regulated, and non-profit organizations.
7 In 1978, I joined EUASC as Audit Supervisor. My responsibilities were to develop and
8 implement a comprehensive audit program for the EUA system companies and to report
9 the results of that program to both management and the Audit Committee of the Board of
10 Trustees. After three years as Audit Supervisor, I was promoted to the position of
11 Manager of System Revenue Requirements. In this position, I was responsible for the
12 detailed coordination and preparation of rate cases for the EUA companies. I participated
13 personally in these cases in various ways, including testifying on matters reflected in the
14 cost of service or preparing cost-of-service adjustments under the direction of company
15 accounting witnesses. Effective August 1, 1985, I was promoted to Assistant Vice
16 President and I assumed responsibilities for special projects in the areas of accounting,
17 taxes, finance, and personnel. On April 15, 1986, I was named Vice President of EUA
18 Service Corporation wherein I assumed responsibility for the EUA Rate and Customer
19 Service Departments. In March 1990, I was elected President of Newport upon its
20 acquisition by EUA. I was responsible for the integration of operations of Newport and
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 3 of 13
1 EUA. In April 1992, I was elected Executive Vice President with EUA system
2 responsibilities of Corporate Communications, Customer Service, Information Systems,
3 and Rates.
4
5 I am a Certified Public Accountant in the Commonwealth of Massachusetts. In addition, I
6 have participated in several professional and utility associations, such as the American
7 Institute of Certified Accountants, the Massachusetts Society of Certified Public
8 Accountants, both the Audit Committee and the Rate Research Committee of the Edison
9 Electric Institute, both the Audit Committee and Energy Management Committee of the
10 Electric Council of New England, and the National Association of Accountants.
11
12 Q. Have you previously testified before any regulatory commission?
13 A. Yes. I have testified before the Rhode Island Public Utilities Commission in general rate
14 cases filed by Blackstone and Newport. I also have testified before the Massachusetts
15 Department of Telecommunications and Energy in Eastern's general rate cases, and
16 presented testimony before the Federal Energy Regulatory Commission on behalf of
17 Montaup, EUA's transmission and generation company.
18
19 II. Purpose of Testimony.
20 Q. What is the purpose of your testimony?
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 4 of 13
1 A. The purpose of my testimony is to explain the benefits of the merger of EUA with the
2 New England Electric System ("NEES") for the customers, employees, and shareholders
3 of the EUA companies.
4
5 III. Terms, Conditions, and Structure of the Transaction.
6 Q. What is the corporate form of EUA?
7 A. EUA is a Massachusetts voluntary association and a registered holding company under the
8 Public Utility Holding Company Act of 1935 ("Holding Company Act"). EUA owns the
9 common equity of three electric companies, Eastern, Blackstone, and Newport. Eastern
10 owns the common equity of Montaup. EUA also owns the common equity of EUASC,
11 the entity that provides nearly all professional, technical, and scientific services to EUA
12 affiliates. EUA owns the common equity of non-regulated subsidiaries, including EUA
13 Cogenex Corporation, EUA Energy Investment Corporation, and EUA Ocean State
14 Corporation.
15
16 Q. Mr. Powderly, would you please summarize the transaction between EUA and NEES?
17 A. Under the merger agreement, EUA shareholders will receive $31.00 for each share held
18 when the acquisition becomes effective. The cash payment will be subject to an increase
19 of $0.003 per share per day if the merger is not completed on or before the date following
20 six months after approval of the merger by EUA's shareholders. The precise structure of
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 5 of 13
1 the transaction will be a merger between Research Drive LLC ("Research Drive"), a
2 Massachusetts limited liability company which is owned by NEES, and EUA. Research
3 Drive will merge with and into EUA, with EUA becoming a wholly-owned subsidiary of
4 NEES. The Agreement and Plan of Merger, dated February 1, 1999, (the "Agreement")
5 contains terms and conditions which are typical of a merger transaction. A condition of
6 closing the merger is obtaining approval of the shareholders of EUA.
7
8 Q. Will the merger affect the corporate structure of the EUA operating companies?
9 A. Yes. At closing, EUA will become a wholly-owned subsidiary of NEES. Thereafter,
10 NEES and EUA plan, as part of this transaction, to merge both the holding companies and
11 to consolidate the underlying operating and service companies. As explained in the
12 testimony of Mr. Jesanis, it is the intention of NEES to have Narragansett Electric
13 Company merge with Blackstone and Newport Eastern. In addition, Eastern will merge
14 with Massachusetts Electric Company, and Montaup with New England Power Company.
15 Finally, EUASC and New England Power Service Company will also be consolidated to
16 lower administrative costs. In each case, the surviving entity will be the existing NEES
17 company.
18
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 6 of 13
1 Q. Will the merger affect the Commission's jurisdiction over the EUA operating companies?
2 A. No. At all times, the Commission will have the same jurisdiction over the EUA
3 subsidiaries and their ultimate successors as it has now.
4
5 Q. Please explain the impetus for EUA to seek a merger.
6 A. EUA began to consider a combination strategy as soon as it became apparent that the
7 electric utility industry would be restructured and generation deregulated at both the
8 federal and state levels. An integral part of restructuring was the divestiture by the
9 incumbent utilities of their generation portfolios. In the divested environment, EUA
10 determined, as did other electric utilities, that our skills and assets were best focused on
11 the transmission and distribution business. At the same time, it became evident that if our
12 transmission and distribution companies were to realize greater efficiencies, cost
13 reductions, and attractive returns, EUA would have to grow significantly. Put another
14 way, without the generation business and with relatively small service territories, EUA lost
15 important economies of scale and scope. The reduced scale and scope of the organization
16 after divestiture would make it impossible to sustain the infrastructure necessary to
17 maintain the same level of low-cost, high-quality service our customers have come to
18 expect. Our options would be to reallocate fixed costs over a significantly smaller, wires-
19 only, sales base or cut back on service. Maintaining or improving performance in
20 providing customer service, delivering safe, adequate, and reliable electricity at a low cost,
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 7 of 13
1 and fairly compensating our investors would not likely be the results of operating a small
2 wires-only business. Therefore, we concluded that the only acceptable affiliation must be
3 one that would produce these positive results for all our stakeholders.
4
5 Q. How did EUA identify potential business combination partners?
6 A. From late 1996 to early 1999, management and the Board continually evaluated the
7 various strategic options available to EUA as restructuring and the transition to
8 competition were taking place. Among the options considered were remaining a relatively
9 small, independent transmission and distribution company, growing the company by
10 acquiring other, smaller electric and/or gas companies within the region, looking for a
11 merger partner of similar size, and looking for a merger partner of larger size. EUA
12 retained its long-time advisor, Salomon Smith Barney, to assist us in our review of
13 alternatives and, if appropriate, to seek out potential merger or acquisition partners. To
14 meet financial and customer objectives, EUA would seek out a partner of a size that
15 would allow the resulting enterprise to achieve the economies of scale necessary to
16 increase efficiency and reduce costs. The most desirable partners would also have
17 characteristics such as being a low cost provider, a similar philosophy of system
18 operations, a strong customer service commitment, and a quality workforce. Discussions
19 with possible partners ensued.
20
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 8 of 13
1 Q. When did EUA reach a conclusion on its future?
2 A. On January 31, 1999 and February 1, 1999, the EUA Board held a special meeting to
3 review and consider the proposals received. After presentations by legal and financial
4 advisors and a full discussion and analysis, the Board unanimously determined that it was
5 in the best interests of all EUA stakeholders to enter into a business combination with
6 NEES and that the terms of the merger were fair to and in the best interests of EUA
7 shareholders; it authorized, approved, and adopted the plan of merger and the transaction
8 described in the Agreement. EUA was advised that NEES obtained the consent of
9 National Grid to enter into the Agreement and on the morning of February 1, 1999, at the
10 conclusion of the EUA Board meeting and prior to the opening of the financial markets,
11 EUA and NEES executed and delivered the Agreement.
12
13 IV. Benefits to Customers, Employees and Shareholders.
14 Q. Would you summarize the benefits of the merger for Blackstone and Newport customers?
15 A. Blackstone and Newport's customers will realize quantifiable benefits almost immediately
16 as a result of the rate plan proposed by Narragansett Electric. This plan is described in
17 the testimony of Michael E. Jesanis. Put simply, on the later of April 1, 2000 or 120 days
18 after the merger is completed, the rates of Blackstone and Newport will be consolidated
19 with Narragansett's lower rates. This will provide Blackstone and Newport customers
20 with annual savings of $1.2 million and $3.2 million respectively. Moreover, the rate plan
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 9 of 13
1 assures that economic benefits will not come at the sacrifice of quality service. Following
2 the acquisition, both Narragansett Electric and the EUA companies will continue our
3 commitment to maintain the same high standards of service and reliability that our
4 customers have come to expect. Our historic commitment to our communities and local
5 charities will also be maintained. Blackstone and Newport's record of quality service at
6 low rates will be enhanced by this transaction and we will join in Narragansett Electric's
7 exemplary performance of delivering low rates, reliability, and innovation to our
8 customers.
9
10 In addition, the merger will produce ongoing savings and efficiency gains. The merger
11 savings after the cost to achieve are projected by Mr. Hoffman and Mr. Jesanis to total at
12 least $35 million per year in the first full year for all of the Rhode Island and
13 Massachusetts distribution companies. These savings will endure and, as Mr. Hoffman
14 demonstrates, increase with inflation. Finally, Mr. Jesanis testifies that the NEES merger
15 with National Grid promises additional resources, scale, and the ability to implement
16 further consolidations in the Northeast. The benefits of savings from such future
17 consolidations and efficiencies gains would inure to Blackstone and Newport customers as
18 well. The expectation of savings from future consolidations, together with the distribution
19 rate freeze and the savings from this transaction, provide compelling economic benefits to
20 Blackstone and Newport customers. After the merger, Blackstone and Newport
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 10 of 13
1 customers will receive service from a wires company several times larger than the size of
2 their former distribution company with more financial and operational resources to deal
3 with emerging issues regarding customer service and reliability. Customers will enjoy
4 lower rates and the benefit of rate stability without sacrificing performance and reliability.
5
6 Q. How will the merger affect Blackstone and Newport employees?
7 A. As with most mergers, including ours, the achievable benefits are determined in major part
8 by the number and productivity of the employees retained by the surviving entity; some
9 workforce reduction is inevitable. One of EUA's chief concerns in seeking a combination
10 has been that its employees be treated fairly after the merger, a concern shared by the
11 Commission as well. Several factors peculiar to this merger lead to the conclusion that
12 our employees will be treated fairly. First, as I describe below, the number of necessary
13 employee reductions is small. Second, we anticipate that most of the employee reductions
14 can be accomplished through attrition and voluntary early retirement incentives. Third, we
15 are combining with an organization that is structured and operates much like EUA.
16 Fourth, NEES has made clear its intention to grow its transmission and distribution
17 business and has the financial backing to do so. This growth provides opportunities for
18 our employees they would not otherwise have. Fifth, National Grid is looking for
19 candidates for assignment elsewhere in its operations; these international job opportunities
20 could also be very attractive to our employees. And last, but not least, NEES has
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 11 of 13
1 committed to honor EUA's labor contracts. For our non-union workforce, NEES has
2 agreed that for 12 months following the closing date, compensation, benefits, and
3 coverage shall not be less favorable, in the aggregate, than those provided, in the
4 aggregate, immediately prior to the closing date. Our employees have heard directly, from
5 Richard P. Sergel, NEES's Chief Executive Officer, that their opportunities in the post-
6 merger organization will not be limited because they came from EUA.
7
8 EUA has been steadfastly committed to maximizing the effectiveness of its workforce
9 through a combination of training and motivating employees and optimizing their numbers.
10 Consistent with that objective, we have reduced our electric company and EUASC
11 populations from 1,343 at the end of 1990 to 946 at the end of 1998 (a 30 percent
12 reduction), while improving the quality of service. Our stringent control of personnel
13 counts has positioned us in this merger so that we will be able to achieve synergy savings
14 and still treat our employees fairly. The pre-merger combined staffing is about 4,100.
15 Projected merger savings are based on a reduction from that figure of approximately 250
16 employees, or about 6 percent of the combined total. We fully expect to achieve these
17 reductions almost entirely through attrition and voluntary early retirement programs.
18
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 12 of 13
1 Q. Would you summarize the benefits of the merger for EUA shareholders?
2 A. The benefits to EUA shareholders are directly related to the consideration they will receive
3 for their shares at the closing of the merger. The base consideration of $31.00 per share
4 represents a 23 percent premium above the price of EUA shares on December 4, 1998, the
5 last trading day before other regional merger announcements caused the price of its shares
6 to increase significantly, and a 5 percent premium above the closing price on January 29,
7 1999. As explained earlier, the purchase price is subject to an upward adjustment related
8 to the timing of the closing, and will be paid in cash. EUA's Board received an opinion
9 from Salomon Smith Barney that the consideration being paid to our common
10 stockholders is fair. We will request shareholder approval at our annual meeting this
11 spring.
12
13 Q. Would EUA have been able to deliver comparable benefits absent this merger?
14 A. Absolutely not. As I have testified earlier, a strategy of merger or acquisition in the
15 distribution and transmission business was essential to our continuing to meet the needs of
16 our stakeholders: low-cost, reliable service to our customers; a secure work environment
17 and continued opportunity for our employees; and a fair return to our shareholders. The
18 merger with NEES provides a partner with the size, proximity, low-cost structure and
19 operating philosophy to meet or exceed these objectives. I do not believe that there was
20 an alternative to this merger that would provide comparable benefits.
<PAGE>
Narragansett Electric
Blackstone/Newport Electric
R.I.P.U.C. Docket No.
Testimony of R. G. Powderly
Page 13 of 13
1 Q. Does this complete your testimony?
2 A. Yes.
</TABLE>
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- -----------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No. __________
Blackstone Valley Electric Company )
Newport Electric Corporation )
)
- -----------------------------------
DIRECT TESTIMONY
OF
LAWRENCE J. REILLY
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- -----------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No. __________
Blackstone Valley Electric Company )
Newport Electric Corporation )
)
- -----------------------------------
DIRECT TESTIMONY
OF
LAWRENCE J. REILLY
Table of Contents
Page
I. Qualifications .................................................... 1
II. Purpose of Testimony .............................................. 3
III. Organization of NEES Distribution Companies........................ 4
IV. Service Benefits from the Merger................................... 8
V. Development of the Competitive Power Supply Market................ 10
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 1 of 13
<S> <C>
1 I. Qualifications.
2 Q. Please state your name and business address.
3 A. My name is Lawrence J. Reilly. I have two business addresses: 280 Melrose Street,
4 Providence, Rhode Island 02907; and 55 Bearfoot Road, Northborough, Massachusetts
5 05132.
6
7 Q. What is your position with the Company?
8 A. I am President and Chief Executive Officer of The Narragansett Electric Company
9 ("Narragansett Electric" or the "Company"). In addition, I hold the same position for New
10 England Electric System's other electricity distribution subsidiaries: Massachusetts
11 Electric Company, Nantucket Electric Company; and Granite State Electric Company. I
12 am also a Director of each of these companies.
13
14 Q. Please describe your educational background and training.
15 A. In 1978, I received a Bachelor of Arts degree magna cum laude from the State University
16 of New York at Albany. In 1982, I received the degree of Master in City and Regional
17 Planning from the John F. Kennedy School of Government at Harvard University where I
18 specialized in Energy and Environmental Policy. Also in 1982, I received a Juris Doctor
19 degree cum laude from Boston University School of Law.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 2 of 13
1 Q. Please describe your professional experience.
2 A. I joined New England Power Service Company ("NEPSCO") as an Attorney in the
3 Corporate Legal Department in 1982. In that capacity I advised various New England
4 Electric System ("NEES") companies in the areas of finance and securities law as well as
5 in the areas of environmental licensing and permitting. In 1987, I became legal counsel to,
6 and Secretary of, Narragansett Electric. In that capacity my responsibilities included
7 advising the Company on a variety of regulatory and rate matters and permitting for the
8 Manchester Street Station Repowering Project. In July 1990, I became Director of Rates
9 for NEPSCO with responsibility for wholesale and retail rate matters for all of the NEES
10 companies. In 1993, I was elected a Vice President and assumed additional responsibility
11 for retail revenue requirements. Effective June 1, 1996, I was elected President of
12 Massachusetts Electric Company. I became President of Granite State Electric and
13 Narragansett Electric in January 1997 and October 1997, respectively. In my capacity as
14 Vice President and Director of Rates and as President and CEO of the NEES electricity
15 distribution companies I have been actively involved with electric industry restructuring
16 matters. My current areas of responsibility for the NEES electricity distribution
17 companies include transmission and distribution system operations, customer service, and
18 business service functions.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 3 of 13
1 Q. Do you serve on the boards of any other organizations?
2 A. Yes. I am a Director of the Massachusetts Technology Park Corporation. I also currently
3 serve as Chairman of the Massachusetts Alliance for Economic Development, a privately
4 funded non-profit organization dedicated to promoting economic growth in
5 Massachusetts. I am also on the Board of Grow Smart Rhode Island, a non-profit
6 organization focused on the interaction of economic growth, environment, and land use
7 issues. In addition, I serve on the Boards of the United Way of Central Massachusetts, the
8 United Way of Southeastern New England, the Foundation for Ocean State Public Radio,
9 the Worcester State Foundation, and as a Corporator of the Worcester Art Museum.
10
11 Q. Have you previously testified before any regulatory commission?
12 A. Yes, I have previously testified before the Rhode Island Public Utilities Commission
13 ("Commission'), the Massachusetts Department of Telecommunications and Energy, the
14 New Hampshire Public Utilities Commission, and the Federal Energy Regulatory
15 Commission.
16
17 II. Purpose of Testimony.
18 Q. What is the purpose of your testimony?
19 A. The purpose of my testimony is three-fold. First, I will describe how Narragansett
20 Electric and its affiliated distribution companies are organized today to provide quality
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 4 of 13
1 service to customers. Second, I will describe the integration process that is underway
2 with Eastern Utility Associates ("EUA") and the anticipated benefits for customers.
3 Finally, I will describe the benefits that the merger creates for customers in the power
4 supply market.
5
6 III. Organization of NEES Distribution Companies.
7 Q. Mr. Reilly, will you please describe how Narragansett Electric and the other NEES
8 distribution companies are organized to provide service to customers.
9 A. Narragansett Electric and its affiliated distribution companies in Massachusetts and New
10 Hampshire together provide service to almost 1.4 million customers. The breakdown of
11 customers by distribution company is detailed on Exhibit LJR-1. Although Narragansett
12 Electric has its own corporate identity and continues to be a leading corporate citizen in
13 the Rhode Island business community, to the extent possible, we operate all the NEES
14 distribution companies as an integrated organization. This integration allows us to operate
15 more efficiently and provide better service to customers. For example, this method of
16 operation allows us to implement best practices uniformly across the system and provides
17 us flexibility in terms of assigning crews where needed most in response to major storms.
18 Through this integrated management we are able to alleve the efficiency gains that have
19 historically been available through the sharing of administrative functions such as
20 accounting and legal services through NEPSCO.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 5 of 13
1 The combined service areas of the NEES distribution companies in the three states cover
2 almost 5000 square miles. For that reason, we have divided the combined territories up
3 into six operating districts and a number of operating satellites that are run from each
4 district. Exhibit LJR-2 is a map showing the current district boundaries within the service
5 territory and the location of key facilities.
6
7 For the most part, each operating district includes a functional head for operations,
8 customer service, and business services. These individuals are responsible for service
9 performance and program implementation throughout their respective districts. In
10 general, where there is a need to be close to the customers (because of travel time or
11 because detailed knowledge of the local conditions is required), individuals work out of
12 the local district offices or satellite locations; where frequent local contact is not critical,
13 individuals tend to work in the central locations, principally, Northborough, Westborough,
14 and Providence. The degree to which each operating district is supported centrally varies
15 from function to function. Narragansett Electric is currently organized as a single
16 operating district with functional heads for operations, customer service, and business
17 services located in Providence. After the merger with EUA, I expect there will be two
18 operating districts in Rhode Island.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 6 of 13
1 Q. Please explain the split between district and central functions in the Operations area.
2 A. In Operations, the physical workers (linemen, underground workers, substation
3 maintenance workers) are assigned to a district or satellite location. In the case of
4 Narragansett, that means that such workers are based in Providence or the other Rhode
5 Island satellite offices. Certain engineering functions are performed locally while other
6 engineering operations such as substation design and standards are performed centrally.
7 Operating functions handled centrally for all system companies include: training; material
8 supply; relay & telecommunications; transmission line engineering; engineering laboratory;
9 construction; environment; safety; and property assets. In some cases there are individuals
10 assigned to local district offices to implement programs and polices that are administered
11 centrally. Safety, environmental management, and vegetation management are examples
12 of areas that fall into this category. As such, there are employees of Narragansett
13 performing those functions in Rhode Island.
14
15 Q. How is responsibility divided between the field and central office in the customer service
16 area?
17 A. Meter reading is the clearest example of a function where it is most efficient to have the
18 workers located near the customers. Workers in the meter operations group, which is
19 responsible for installing, maintaining, exchanging, and testing meters, are also
20 decentralized; however, they receive central support from the Meter Operations and
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 7 of 13
1 Engineering Group in Worcester. Supplier services along with load research and load
2 estimation, which have become increasingly important in the restructured environment, are
3 located centrally in Northborough. Customer calls are handled in call centers located in
4 Providence and Northborough that are linked through telecommunications equipment
5 which automatically transfers calls between these two centers to minimize wait times for
6 customers. This arrangement also provides us access to two job markets for customer
7 service representatives and diversity of locations in the event of bad weather or a disaster
8 at either location.
9
10 Q. How is the Business Services function organized?
11 A. Each district office has a local Business Services Vice President and a staff of account
12 managers. The account managers handle service requests for our largest customers (200
13 kilowatts or greater demand per month) and are actively involved in the marketing of our
14 various Demand Side Management ("DSM") programs. DSM programs for residential
15 and small commercial and industrial customers are handled centrally by NEPSCO
16 employees in Northborough. Special programs and new initiatives are also developed in
17 Northborough and implemented in close coordination with Business Services personnel in
18 the field.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 8 of 13
1 IV. Service Benefits from the Merger.
2 Q. Do you believe that the merger will create service benefits for customers?
3 A. Yes. Several factors lead us to conclude that the merger will improve service to
4 customers. First is geographic proximity. A map showing the relationship between the
5 NEES and EUA distribution companies is included as Exhibit LJR-3. As shown, the
6 service territories of the companies are in very close proximity. It is this geographic
7 proximity that makes this merger so attractive from an operating perspective. This merger
8 goes a long way to rationalizing the service territories of the distribution companies in
9 southeastern New England and, with the integration of NEES and EUA field and central
10 functions, should enable us to provide comparable or better service at a lower cost.
11 Second, there is a long history of good working relationships between our companies,
12 including a history where a number of employees have moved between the companies over
13 time. Third, perhaps related to the first two items mentioned above, there appears to be a
14 very similar culture between the two companies - one where quality customer service
15 and cost control are widely recognized objectives. In my opinion, all three of these factors
16 will facilitate a successful integration of the businesses.
17
18 Q. Are the companies also addressing service quality issues in the integration process for the
19 merger?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 9 of 13
1 A. Yes. The proper integration of the companies is central to the effectiveness and efficiency
2 of our operations and the quality of our service following the merger. I am a member of
3 the integration steering committee that is responsible for the successful integration of the
4 companies. Our progress during the integration process has been substantial. We have
5 already found several ways to improve service and efficiency that we will build upon as we
6 complete the integration process and following the merger. The transition teams cover ten
7 different disciplines and approximately sixty subgroups have been established as part of the
8 effort to focus on specific areas. The teams and the areas they are responsible for are
9 outlined on Exhibit LJR-4.
10
11 Q. What benefits of the merger have you identified to date?
12 A. Although it is still early in the process, it is apparent that several key benefits will flow
13 from the eventual consolidation of the three Rhode Island utilities. Specifically:
14 o The larger company will have more resources to draw upon in the event of storms
15 or natural disasters;
16 o Customer service costs and other costs associated with administering separate
17 rates and maintaining separate companies will be reduced;
18 o BVE and Newport customers will be provided 24 hour per day access to customer
19 service representatives for routine billing and payment inquires (currently such
20 access is limited to 7 a.m. to 9 p.m. Monday through Saturday);
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 10 of 13
1 o The consolidation will produce administrative savings for the Commission and the
2 Division by reducing the number of regulated companies and associated reporting
3 requirements;
4 o The customers of Narragansett and the EUA companies benefit from the rate plan
5 proposed as part of this filing; and
6 o The consolidation will help in the development of the competitive power supply
7 market.
8
9 V. Development of the Competitive Power Supply Market.
10 Q. You stated that you expected the consolidation of Narragansett Electric and the EUA
11 companies to help in the development of the competitive power supply market. Please
12 explain why you believe this is to be the case.
13 A. Although it is certainly not the only barrier to development of a competitive market, the
14 multitude of distribution companies within southeastern New England has no doubt
15 retarded the growth of the competitive market in a number of ways. First, differing
16 distribution rates and availability clauses for providing distribution service complicate the
17 terrain for power suppliers considering entry into the market. Second, the patchwork
18 nature of the existing service territories complicates marketing efforts. Third, differing
19 electronic data interchange formats and testing requirements add to administrative
20 overheads for suppliers. The consolidation of rates for delivery service, the contiguous
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 11 of 13
1 nature of the expanded service territory, and one less point of contact for suppliers
2 entering the market here should all help to reduce barriers to entry into the competitive
3 supply market.
4
5 In Rhode Island, these benefits will be particularly important. Suppliers will be able to
6 enter the state by complying with a single set of regulations and a single set of terms and
7 conditions by the utility. We have an excellent opportunity to develop rational and
8 consistent rules that will make Rhode Island a key player in competitive power markets.
9 The more suppliers that we can attract, the higher value we will provide for Rhode Island
10 customers.
11
12 Q. Why is reducing barriers to entry for suppliers entering the competitive market important?
13 A. Prior to restructuring, the generation or supply component of customer bills accounted for
14 roughly two-thirds of the total cost of electricity. The significant potential for savings in
15 that portion of the bill was one of the factors that led to restructuring. Nothing has
16 changed in this area. Power supply costs are still the area where customers stand to save
17 the most money on their bills. Without regulation, however, there must be an efficient and
18 vigorous market for electricity supplies for customers to realize the full benefits of
19 competition.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 12 of 13
1 Q. In your opinion what other barriers exist to the development of a robust competitive
2 power supply market?
3 A. Lack of information is certainly a problem on several levels. Not all customers are aware
4 of their options or have ready access to billing data needed to minimize supply costs.
5 Power marketers may also lack information about potential customers that could benefit
6 from their products.
7
8 Q What actions are you planning to take to reduce these barriers?
9 A. We have a number of initiatives under way to inform customers of their options in the
10 power supply market. We currently offer "Power Talk", a speakers bureau program for
11 customer groups of all kinds. We are including information in "PowerLink", a newsletter
12 for our business customers, and are hosting breakfast meetings for our largest customers
13 to highlight opportunities available in the market. Under our "Power Connection"
14 program, with a customer's consent, we will provide billing data to all registered suppliers
15 in electronic format so that prospective suppliers can develop offers suited to the
16 individual customers. We are also distributing a software product called "Energy Smart"
17 to our customers that provides educational information to customers and is expected to
18 eventually aid customers who wish to shop for power supplies on-line.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Testimony of L. J. Reilly
Page 13 of 13
1 In addition, we also are developing a series of optional metering services that will be
2 available to any customer that wants detailed interval or real time demand and energy
3 use data. Also, to assist power marketers in getting access to prospective customers, we
4 intend to offer a mailing service to all power marketers whereby we would mail their
5 marketing information to customer segments they determine without disclosing any
6 customer data to the power marketer.
7
8 Q. How will the merger improve this effort?
9 A. As part of the integration process, we will continue to look for ways to improve our
10 outreach and education programs and make them more effective. The merger will assure
11 that the finally implemented programs will reach more customers, more efficiently. The
12 consolidation will also facilitate marketers' efforts to reach our customers with ideas and
13 products that will provide our customers with more value at lower prices.
14
15 Q. Does this conclude your testimony?
16 A. Yes.
</TABLE>
<PAGE>
EXHIBITS OF L. J. REILLY
LJR-1 Customers Served by NEES Distribution Company
LJR-2 Current Map of NEES Service Territory
LJR-3 Map of Combined NEES-EUA Service Territory
LJR-4 Integration Teams and Responsibilities
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibits
of
Lawrence J. Reilly
Exhibit LJR-1 Customers Served by NEES Distribution Company
Exhibit LJR-2 Map of Existing NEES Service Territory
Exhibit LJR-3 Map of Combined NEES-EUA Service Territory
Exhibit LJR-4 Integration Teams and Responsibilities
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit LJR-1
Exhibit LJR-1
Customers Served by NEES Distribution Company
<PAGE>
S:\RADATA1\EASTED\Ljr-1.wk4 Narragansett Electric
PAGE 1 BVE/NewPort Electric
10-May-1999 R.I.P.U.C. No. _____
Exhibit LJR-1
Page 1 of 1
New England Electric System
Number of Customers per Distribution Company
Number of
Customers
Massachusetts:
Massachusetts Electric Company 983,191
Nantucket Electric Company 10,169
------
Total Massachusetts 993,360
Rhode Island:
Narragansett Electric Company 336,029
New Hampshire:
Granite State Electric Company 37,114
3 State Total 1,366,503
=========
Source: March 1999 Billing Records
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit LJR-2
Exhibit LJR-2
Maps of Existing NEES Service Territory
<PAGE>
Exhibit LJR-2
Map of Existing NEES Service Territory
Two Maps
First Map: Reflects service territories, headquarters, customer service and
operations centers and operating satellites for Granite State, Mass. Electric,
Nantucket and Narragansett in Rhode Island, Massachusetts and New Hampshire.
Second Map: Reflects Narragansett service territory, headquarters and operating
satellites in Rhode Island.
<PAGE>
<TABLE>
<CAPTION>
Granite State Electric Massachusetts Electric
Company Company
<S> <C> <C> <C>
Lebanon Western Merrimack Valley
Acworth Adams Mount Washington Amesbury
Alstead Alford New Marlboro Andover
Bath Athol New Salem Billerica
Canaan Barre North Adams Boxford
Charlestown Belchertown Northampton Chelmsford
Cornish Brimfield Orange Dracut
Enfield Charlemont Palmer Haverhill
Grafton Cheshire Petersham Lawrence
Hanover Clarksburg Phillipston Lowell
Lnagdon East Longmeadow Rowe Methuen
Lebanon Erving Royalton Newbury
Marlow Florida Sheffield Newburyport
Monroe Goshen Shutesbury North Andover
Orange Granby South Egremont Salisbury
Plainfield Great Barrington Stockbridge Tewksbury
Surry Hampden Templeton Tyngsboro
Walpole Hancock Wales West Newbury
Hardwick Ware Westford
Hawley Warren
Salem Heath Warwick North Shore
Derry Holland Wendell Beverly
Pelham Lenox West Stockbridge Essex
Salem Monroe Wilbraham Everett
Windham Monson Williamsburg Gloucester
Monterey Williamstown Hamilton
Lynn
Narrangansett Electric Malden
Company Central Manchester
Auburn New Braintree Medford
Southern Ayer North Brookfield Melrose
Charlestown Berlin Oakham Nahant
Coventry Bolton Oxford Revere
East Greenwich Brookfield Paxton Rockport
Exeter Charlton Pepperell Salem
Hopkinton Clinton Rutland Saugus
Narragansett Dudley Shirley Swampscott
North Kingstown Dunstable Southbridge Topsfield
Richmond East Brookfield Spencer Wenham
South Kingstown Gardner Sturbridge Winthrop
Warwick Grafton Sutton
West Greenwich Harvard Webster
West Warwick Hubbardston West Brookfield
Westerly Lancaster West Groton
Leicester Westminster
Providence Leominster Winchendon
Barrington Millbury Worcester
Bristol
Cranston Southeast
East Providence Attleboro Northborough
Foster Bellingham Northbridge
Glocester Blackstone Norton
Johnston Douglas Plainville
Little Compton Foxborough Quincy
North Providence Franklin Randolph
Providence Hingham Rehoboth
Scituate Holbrook Seekonk
Smithfield Hopedale Southborough
Tiverton Marlborough Upton
Warren Mendon Uxbridge
Milford Westborough
Milville Weymouth
Nantucket Wrentham
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit LJR-3
Exhibit LJR-3
Map of Combined NEES-EUA Service Territory
<PAGE>
Exhibit LJR-3
[Map of Combined NEES-EUA Service Territory]
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit LJR-4
Exhibit LJR-4
Integration Teams and Responsibilities
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No.______
Exhibit LJR-4
Page 1 of 1
EUA/NEES TRANSITION TEAMS
General Business Areas
HR & RETAIL INFORMATION POWER
SUPPLY CHAIN COMPANIES SYSTEMS COMPANY
- ------------ ------------ ------------ ------------
HR-Compensation EO-Central Retail Transmission
& Operations Applications Marketing
Benefits
HR-Labor EO-Central Corporate Transmission
Engineering Applications Planning
HR-Culture EO-Field Operations Divestitures
Integration Operations
HR-Employee EO-Dispatching Technology Nuclear
Relations Services Issues
SCM-Inventory CS-Call
Center Y2000 PPA/PSA
Power
SCM-Goods CS-Meters IS Support Contracts
and Services
SCM-Accounts CS-Billing NEPOOL
Payable Issues
Health and CS-Credit
Safety &
Collections
Benefit RM&S-Demand Side
Plan Funding Management
RM&S-Business
Services
Telecommunication
Property
Environmental
and Safety
External
Affairs
============ =========== ============ ============
TRANSITION
STEERING
COMMITTEE
============ =========== ============ ============
Chairman:
T. Rogers/
R. Powderly
- ------------ ------------ ------------ ------------
DC Kennedy LJ Reilly DL Holt PG Flynn
HE Stapleford JL McGrath
- ------------ ------------ ------------ ------------
B. Hassan J Carney W Norko K Kirby
- ------------ ------------ ------------ ------------
KEY COORDINATION AREAS
- ------------ ----------- ------------
Regulatory Unregulated NGG Coord.
Approvals Businesses
- ------------ ----------- ------------
TREASURY RATE/REVREQ ACCOUNTING COMMUNICATIONS LEGAL
------------ ------------ ------------ ------------ -----------
Finance Revenue General External Legal
Requirement Accounting and
and Employee
Rates Communications
Risk Plant Corporate
Management Accounting Governance
Investor Standard Revenue
Relations Offer and Accounting
Default
Property Service Payroll
Tax Contracts
Taxes
"TIER 1" TRANSITION TEAMS
---------- ----------- ----------
========== =========== ========== =========== ===========
TRANSITION
STEERING
COMMITTEE
J.Zschokke TL WR Richer SM Stevens MA Katz
Schwennesen
---------- ----------- ---------- ----------- -----------
C Hebert D.St.Pierre A.Camara F. Mason D Fazzone
---------- ----------- ---------- ----------- -----------
OTHER CONSULTANTS
------------ ------------
Audit A&G Best
Practices
Planning, Early
Budgets and Decisions
Reporting Support
Facilities Organization
Planning
Asset Team Support
Separation
Records
Management
"Cut-over"
Plan
========== ============
TRANSITION
STEERING
COMMITTEE
T. Rogers Mercer
Management
Consultants
---------- ------------
M Hirsh
---------- ------------
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ----------------------------------
)
Narragansett Electric ) R.I.P.U.C. No. __________
BVE/Newport Electric )
)
- ----------------------------------
DIRECT TESTIMONY
OF
DAVID M. WEBSTER
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ----------------------------------
)
Narragansett Electric ) R.I.P.U.C. No. __________
BVE/Newport Electric )
)
- ----------------------------------
DIRECT TESTIMONY
OF
DAVID M. WEBSTER
Table of Contents
Page
I. Qualifications .................................................... 1
II. Purpose of Testimony............................................... 3
III. Recovery of Cost of Removal Expenditures .......................... 3
IV. Book/Tax Timing Differences on Cost of Removal..................... 9
V. Consolidation of Depreciation Rates ............................... 23
VI. Storm Contingency Fund............................................. 27
VII. Deferred FAS 106 Cost Recovery..................................... 29
VIII. Hazardous Waste Cost Recovery ..................................... 32
IX. Conclusion......................................................... 34
X.
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 1
<S> <C>
1 I. Qualifications
2 Q. Please state your full name and business address.
3 A. David M. Webster, 25 Research Drive, Westborough, Massachusetts 01582.
4
5 Q. Please state your position.
6 A. I am a Principal Financial Analyst in the Rate Department of New England Power
7 Service Company ("NEPSCO"). NEPSCO provides engineering, technical,
8 accounting, and other services for the New England Electric System ("NEES")
9 Companies, including The Narragansett Electric Company ("Narragansett" or
10 "Company").
11
12 Q. Please describe your educational background and training.
13 A. In 1986, I graduated with distinction from Southeastern Massachusetts University
14 with a Bachelor of Science degree in accounting.
15
16 Q. Please outline your professional experience.
17 A. In 1986, 1 was hired by NEPSCO as an Assistant Analyst in the Financial Reporting
18 Department. My responsibilities included assisting in the preparation of the various
19 external reporting requirements for NEES and subsidiaries. I was promoted to
20 Analyst in the Financial Analysis section in 1988. My responsibilities included
21 conducting various calculations and analysis in support of the closing of the
22 accounting books of record for the various NEES companies.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 2
1 In 1991, I was promoted to Supervisor of the NEPSCO Accounting Department,
2 responsible for the monthly closing of the accounting books of record as well as
3 all internal and external reporting requirements. In 1992, my supervisory
4 responsibilities were expanded to include overseeing the monthly closing of two
5 additional NEES subsidiaries' books of record as well as all internal and external
6 reporting requirements.
7
8 In 1993, I was promoted to Supervisor of Wholesale Accounting, overseeing the
9 monthly closing and internal reporting requirements for the Wholesale Business
10 unit of NEES. In 1995, I was promoted to Manager of Wholesale Accounting and
11 was given additional responsibilities associated with the Wholesale Accounting
12 section.
13
14 In February 1997, I accepted an assignment to the Rate Department to provide
15 revenue requirement analyses for the NEES retail companies.
16
17 Q. Have you previously testified before a regulatory commission?
18 A. Yes, I have testified in proceedings before regulatory commissions in Rhode
19 Island, New Hampshire and Massachusetts.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 3
1 II. Purpose of Testimony
2 Q. What is the purpose of your testimony?
3 A. My testimony describes the Company's proposal with regard to several
4 accounting issues that will arise as a result of the proposed merger of
5 Narragansett, Blackstone Valley Electric Company ("BVE") and Newport
6 Electric Company ("Newport") (together, the "Companies"). The issues that need
7 to be addressed under the rate plan proposed in the testimony of Mr. Jesanis
8 include consolidation of depreciation rates, storm contingency funds and deferred
9 FAS 106 costs. I also address certain accounting issues related to recovery of
10 hazardous waste remediation costs. However, I will begin my testimony by
11 describing Narragansett's proposal to recover cost of removal expenses. I will
12 first describe the treatment of Narragansett's cost of removal expenses under the
13 current rates. I will then describe how this proposal affects the consolidated rates
14 of the Companies.
15
16 III. Recovery of Cost of Removal
17 Q. Please provide an overview of Narragansett's proposal to recover cost of removal
18 expenditures.
19 A. There are three elements that need to be addressed to allow Narragansett to fully
20 recover both prior and prospective cost of removal expenditures. First,
21 Narragansett must be allowed to implement depreciation rates which contain an
22 allowance for cost of removal expenditures on both a historical and prospective
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 4
1 basis. As I describe below, the depreciation rates that Narragansett proposes to
2 implement will meet this requirement.
3
4 Second, Narragansett must be allowed to "normalize" the timing difference that is
5 resulting from the current regulatory treatment of cost of removal expenditures.
6 The current treatment of cost of removal dictates that Narragansett "flow-
7 through" to customers the tax deduction it receives for the cost of removal
8 expenses. Thus, providing an offsetting deferred tax will "normalize" or
9 eliminate the timing difference created by the current treatment of cost of
10 removal.
11
12 Finally, since Narragansett has been "flowing-through" tax benefits to customers
13 for items which it has not been reimbursed, Narragansett has a deficiency in the
14 provision for deferred taxes recorded on its books. As I will describe below,
15 Narragansett proposes to recover its entire deferred tax deficiency by applying
16 certain current and future settlements against the amount of the deficiency.
17
18 Q. What is cost of removal?
19 A. Cost of removal expenditures are the costs incurred by the Companies to remove
20 a unit of utility plant from service.
21
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 5
1 Q. How does the Narragansett currently account for these cost of removal
2 expenditures?
3 A. Narragansett does not charge cost of removal to expense. Instead, consistent with
4 group accounting practices prescribed by the Commission in prior general rate
5 case proceedings, Narragansett charges cost of removal expenditures, as
6 incurred, against its accumulated provision for depreciation. In addition,
7 Narragansett is not permitted to accrue for negative salvage (cost of removal) in
8 its current depreciation rates.
9
10 Therefore, Narragansett is not currently collecting any cost of removal
11 expenditures through rates. While Narragansett has proposed in previous rate
12 cases to include an allowance for cost of removal in its depreciation rates
13 included in cost of service, such accounting treatment has not yet been approved
14 by the Commission.
15
16 The current accounting treatment, which charges cost of removal directly to the
17 depreciation reserve, reduces the amount of accumulated depreciation, thereby,
18 increasing the amount of rate base on which Narragansett earns a return. Thus,
19 Narragansett is currently earning a return on the cost of removal expenditures,
20 but is not recovering the cost of removal expenditures themselves, either directly
21 as an expense or indirectly through depreciation rates. Under this regulatory
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 6
1 practice, Narragansett continues to accumulate cost of removal expenditures
2 which must be recovered in the future from customers.
3
4 Q. What are the problems associated with the current treatment of cost of removal
5 expenditures?
6 A. As stated above, the current rate making policy regarding cost of removal does
7 not allow Narragansett to be reimbursed for any of its cost of removal
8 expenditures to date. These expenses have been charged directly against the
9 accumulated provision for depreciation and as a result, over time, created a
10 deficiency in the accumulated provision for depreciation. The Companies are
11 proposing depreciation rates that would recover the existing deficiency in the
12 accumulated depreciation reserve. I describe this provision later in my testimony.
13
14 In addition, to eliminate future deficiencies in the accumulated reserve for
15 depreciation, Narragansett needs to include in its depreciation rates an amount to
16 begin recovering future cost of removal expenses (this is also known as negative
17 salvage) for the future removal of an asset placed into service today. This
18 methodology would recover the cost of removing that asset proportionately over
19 the life of the asset.
20
21 Q. What depreciation rates would Narragansett implement?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 7
1 A. The settlement agreement reached between Narragansett, the Rhode Island
2 Division of Public Utilities and Carriers ("Division"), and the Energy Council of
3 Rhode Island in RIPUC Docket No. 2290, resolved all issues except the
4 appropriate depreciation rates for Narragansett. As part of the settlement, the
5 parties agreed to further study the depreciation analysis presented to the
6 Commission by Narragansett.
7
8 After months of negotiation, the Division and Narragansett reached an agreement
9 resolving Narragansett's depreciation rates. The agreement was filed with the
10 Commission on May 9, 1996. This settlement represents an initial step in
11 attempting to resolve the problem associated with the Commission's treatment of
12 cost of removal expenses. A copy of the depreciation settlement agreement has
13 been included as Exhibit DMW-1. Under the terms of the agreement,
14 Narragansett may file with the Commission the agreed upon depreciation rates,
15 without opposition from the Division, which include a component for negative
16 salvage. As part of our rate plan, we are proposing to implement the agreed upon
17 depreciation rates which include an allowance for cost of removal on a
18 prospective basis. Specifically, we propose to implement the new rates as of
19 January 1, 2001.
20
21 Q. What impact will implementing the depreciation rates from the settlement have
22 on rates?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 8
1 A. As shown in Exhibit DMW-2, page 1, applying the settlement depreciation rates,
2 including the negative salvage component, to Narragansett's intrastate distribution
3 and general plant balances as of December 31, 1998 will increase Narragansett's
4 depreciation expense by approximately $1.9 million. As I explain below, this
5 increase is mitigated by the merger. Because BVE's and Newport's depreciation
6 rates are higher than Narragansett's, merging the companies and using the settled
7 depreciation rates lowers the impact of the change on customers.
8
9 Q. How did you calculate the amount of the increase in depreciation rates?
10 A. As shown in Exhibit DMW-2, pages 2 and 3, depreciation expense was calculated
11 for Narragansett's intrastate distribution and general plant based upon the current
12 depreciation rates and then based upon the rates in the depreciation settlement. In
13 each case, these rates were applied against Narragansett's intrastate plant
14 balances as of December 31, 1998. The incremental impact of applying the
15 depreciation settlement to interstate plant was not calculated since, under
16 Narragansett's integrated facilities agreement with New England Power Company
17 ("NEP"), Narragansett is reimbursed by NEP for essentially all costs associated
18 with the operation and maintenance of its transmission system. Since that
19 agreement is under the jurisdiction of the Federal Energy Regulatory
20 Commission ("FERC"), a change in the interstate transmission-related
21 depreciation rates must be approved by the FERC.
22
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 9
1 Using the settlement depreciation rates resulted in depreciation expense
2 amounting to $20,645,374, Exhibit DMW-2, page 1, compared to depreciation
3 expense of $18,757,750 when Narragansett applies its current depreciation rates.
4 Therefore, the proposed increase in depreciation expense is $1,887,624 or the
5 difference between the two numbers.
6
7 IV. Book/Tax Timing Differences on Cost of Removal
8 Q. Please explain the difference between the accounting for cost of removal
9 expenditures for book purposes versus for tax purposes.
10 A. As explained earlier, intrastate cost of removal expenditures are charged to the
11 reserve for depreciation for book purposes and thus far no allowance for cost of
12 removal has ever been included in Narragansett's intrastate book depreciation
13 expense. However, for tax purposes, since 1972, intrastate cost of removal
14 expenditures have been deducted on Narragansett's tax return in the year in which
15 the expenditure is made. Therefore, there is a timing difference between the
16 treatment of cost of removal for tax purposes in the current period versus the
17 treatment for book purposes which does not recognize cost of removal as an
18 expense. Simply stated, Narragansett is realizing a tax deduction for cost of
19 removal before these expenditures have ever entered into a determination of book
20 expense. This is commonly referred to as a book/tax timing difference.
21
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 10
1 Q. What has been the rate making treatment of this book/tax timing difference for
2 cost of removal expenditures.
3 A. Narragansett has flowed through these tax deductions for intrastate cost of
4 removal expenditures to its customers even though customers have not
5 reimbursed Narragansett for the cost that gave rise to this tax deduction. Stated
6 another way, Narragansett has never been allowed to include any deferred taxes
7 for these cost of removal tax deductions in cost of service. This effectively
8 provides a subsidy to current customers at the expense of future customers who
9 will at some point be asked to bear this expense without any associated tax
10 benefits.
11
12 Q. Is this the case for Narragansett's other book/tax timing differences?
13 A. No. Narragansett has been allowed to adopt deferred tax accounting for all of its
14 other book/tax timing differences.
15
16 Q. How does Narragansett propose to correct the flow-through of cost of removal in
17 future years?
18 A. Narragansett proposes to cease the flow-through of tax deductions related to cost
19 of removal by recording an offsetting deferred tax.
20
21 Q. What impact will cessation of the "flow-through" of tax benefits have on rates?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 11
1 A. As shown on Exhibit DMW-3, eliminating the "flow-though" of tax benefits will
2 increase rates by approximately $1.6 million. Together with the $1.9 million of
3 increased depreciation expense discussed above, this treatment increases
4 Narragansett's revenue requirement by $3.5 million on an ongoing basis as shown
5 on Exhibit DMW-4. As I explain below, these revenue requirements are
6 mitigated by the consolidation because the depreciation rates of BVE and
7 Newport are presently higher than the settlement rates that we propose to adopt
8 for the consolidated companies.
9
10 Q. How was this amount calculated?
11 A. To date there have not been any deferred taxes provided to normalize the
12 differences between Narragansett's books and its tax return, and because cost of
13 removal expenditures have not been recorded in book expense, the easiest way to
14 determine the impact on rates is to look at the actual cost of removal tax
15 deductions recorded.
16
17 Please refer to Exhibit DMW-3. The impact on rates was calculated by taking the
18 average of the actual intrastate cost of removal tax deduction taken by
19 Narragansett on its tax return for the years 1996, 1997 and 1998. Since the actual
20 amount of cost of removal expenditures varies from year to year, the three year
21 averaging approach was chosen to develop a representative amount of cost of
22 removal expenditures.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 12
1 As shown on line 9 of Exhibit DMW-3, the average intrastate tax deduction for
2 cost of removal amounted to approximately $3 million. Therefore, the resulting
3 average tax benefit amounted to approximately $1 million, as shown on line 11.
4 This amount is then grossed-up to its pre-tax level to reflect the annual impact on
5 rates on a prospective basis from eliminating the "flow-through" benefits from
6 cost of removal tax benefits.
7
8 Q. Could you explain how deferred tax accounting works?
9 A. Yes. Deferred tax accounting is meant to "normalize" or match up the differences
10 between the recognition of expenditures for tax purposes to the recognition of
11 those same expenditures on Narragansett's books. As mentioned above, these
12 differences are referred to as timing differences.
13
14 Q. Could you provide an example of how the accounting for cost of removal and the
15 related tax deductions should work in a normal situation?
16 A. I have prepared an example in Exhibit DMW-5, page 1. This example portrays
17 the proper method of accounting for cost of removal and its related tax benefits.
18 As previously mentioned, in Narragansett's case the tax deduction for cost of
19 removal actually occurs when the plant is removed from service, but the cost of
20 removal was never reflected in book depreciation expense. The correct method
21 of accounting for cost of removal would be to include a cost of removal
22 allowance in Narragansett's depreciation rates. Since cost of removal
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 13
1 expenditures occur at the end of the life of an asset, it should be anticipated in
2 advance and an estimated allowance for cost of removal should be included in
3 book depreciation expense during the period the asset is being depreciated. In
4 doing so, the reserve for depreciation at the end of the life of the asset would be at
5 a level which would cover the original cost plus the cost of removal expected to
6 be incurred.
7
8 In this example (Exhibit DMW-5, page 1) , an asset worth $20,000 is depreciated
9 over 10 years. It is anticipated that $ 1,000 will be incurred at the end of its ten
10 year life to remove it. Depreciation expense each year not only includes $2,000
11 per year for the original cost of the assets, but also an additional $100 per year in
12 anticipation of the cost of removal expenditure. At the end of year 10, the total
13 depreciation reserve would equal $21,000 which would be sufficient to cover the
14 original cost of the asset plus the cost of removing that asset.
15
16 For simplicity, we have assumed that tax depreciation is calculated exactly the
17 same as book depreciation with the exception that the Internal Revenue Service
18 ("IRS") would not permit the inclusion of the additional $100 for the anticipated
19 cost of removal allowance. However, since the Company will ultimately realize a
20 tax deduction, this allowance in book depreciation for cost of removal is a
21 book/timing difference for which deferred taxes should be recorded. In this
22 situation, a deferred tax receivable would be recorded which would have the
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 14
1 effect of reducing cost of service. This treatment would recognize that a
2 component of book depreciation is not deductible currently but will be in the
3 future, however it would accrue a future tax benefit during the life of the asset.
4 Absent deferred tax accounting, customers would have to bear the $100 portion
5 of book depreciation expense, representing the cost of removal allowance,
6 without the benefit of a tax deduction, which would ultimately occur in one year
7 at the end of the life of the asset. Deferred tax accounting attempts to normalize
8 the tax benefits over the period in which the book expense occurs instead of when
9 the tax deduction takes place.
10
11 Q. How does this compare to Narragansett's situation?
12 A. Narragansett's situation is much different because Narragansett has not been
13 allowed to include an allowance for cost of removal in its book depreciation in
14 advance of actually incurring the actual cost. Second, Narragansett has not been
15 allowed to record deferred taxes on its cost of removal tax deductions.
16
17 Q. Have you provided an example to illustrate this situation?
18 A. Yes. Please see Exhibit DMW-5, page 2. In this case, I have shown two assets,
19 each with 10-year lives, one constructed in year 0 and one constructed in year 11.
20 The first asset costs $20,000 and the second asset costs $30,000. The first asset
21 will incur $1,000 for cost of removal and the second asset will incur $1,500 for
22 cost of removal at the end of their useful lives. For asset number 1, I have not
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 15
1 reflected an allowance in depreciation expense for cost of removal. However, for
2 asset 2, I have built into the depreciation expense the anticipated cost of removal
3 for that asset and have also reflected a makeup provision for the actual cost of
4 removal for asset 1. In this example, I have also assumed that no deferred taxes
5 were recorded as is the case for Narragansett.
6
7 Two issues should be noted in this example. Customers who received service in
8 the last ten years of this example were paying for the cost of removal for asset 1
9 which should have been paid by the customers who received service during the
10 first ten years of this example. In addition, without deferred tax accounting,
11 customers in years 11 and 21 enjoyed the tax benefits of the cost of removal tax
12 deduction while customers in the years 12 through 20 not only paid the increased
13 depreciation cost related to cost of removal, but did so without the benefits of any
14 tax deductions relative to that cost.
15
16 Q. Have you provided any other examples?
17 A. Yes. In Exhibit DMW-5, page 3, I have an example which is similar to the one
18 described above. However, in this example I have included deferred taxes to
19 normalize the book/tax timing difference. The deferred tax accounting in the
20 example would have kept customers in years 11 and 21 from unfairly benefitting
21 from the cost of removal tax deductions and given those tax deductions to the
22 customers in years 12 through 20 who bore the related book expense.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 16
1 Q. Could you please explain what is meant by the prior flow-through of tax benefits
2 resulting from past regulatory practices?
3 A. As previously stated, Narragansett has been taking a tax deduction for the
4 amount of cost of removal expenditures incurred during the tax year. As a result,
5 customers have had their cost of service reduced to the extent of these tax
6 benefits, even though they have not been asked to pay for the cost which has
7 given rise to this tax benefit.
8
9 The example in Exhibit DMW-5, page 3, as described above, provides an
10 example of this situation. When you compare the example in Exhibit DMW-5,
11 page 2 to the example in Exhibit DMW-5, page 3, you can observe that a
12 deferred tax reserve should exist at the end of year 11 of $263 but in fact none
13 exists in the example in Exhibit DMW-5, page 2. This represents a deficiency in
14 the deferred tax reserves due to flow through accounting. Narragansett has such a
15 deficiency.
16
17 Q. How much in tax benefits has Narragansett "flowed-through" to customers since
18 1972?
19 A. As of December 31, 1998 Narragansett has a deficiency in its deferred tax
20 reserves amounting to approximately $21.7 million. The primary cause of this
21 deficiency is the cost of removal issue that is present in this filing. The
22 deficiency related to cost of removal represents $19.2 million of this amount.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 17
1 To fully reimburse Narragansett for the deficiency in its deferred tax reserves,
2 the amount of the deficiency must be grossed-up for federal income taxes to
3 ensure the proper amount is included in rates. As shown in Exhibit DMW-6, line
4 44, the grossed-up amount of the unfunded deferred taxes results in a revenue
5 requirement of $33.3 million to be collected from customers. The revenue
6 requirement associated with the accumulation of the tax benefits related to cost of
7 removal which Narragansett has "flowed-through" to customers represents
8 approximately $29.5 million of this amount. This deficiency will continue to
9 accumulate until deferred taxes are provided to offset the "flow-through" of tax
10 benefits related to cost of removal expenditures. The remainder of the deficiency
11 in the deferred tax reserves is comprised of other tax deductions previously
12 "flowed-through" to customers. These other tax benefits are partially offset by
13 excess deferred taxes resulting from the change in the federal tax rate from 46%
14 to 35%. Narragansett proposes to recover the $33.3 million deficiency.
15
16 Q. How can the continued accumulation of the deferred tax deficiency be resolved?
17 A. As stated above, allowing the Company to record deferred taxes related to cost of
18 removal upon implementation of the depreciation settlement rates, would stop
19 any further accumulation of the deferred tax reserve deficiency. This deferred
20 tax, based upon the timing difference for cost of removal, will normalize the
21 differences between the book expense for cost of removal and the tax deductions
22 on a prospective basis. In order to implement this deferred tax accounting
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 18
1 treatment, Narragansett needs an assurance from the Commission that it will be
2 allowed to recover the prior flow-through of tax benefits resulting from past
3 regulatory practices.
4
5 Q. How does Narragansett propose to recover the deficiency in its deferred tax
6 reserve?
7 A. There are two methods by which Narragansett could recover the deficiency in its
8 deferred tax reserves. In the first method, assuming that Narragansett is allowed to
9 recover cost of removal, the increase in Narragansett's book depreciation
10 expense would provide for both the recovery of past cost of removal expenditures
11 and the recovery of future cost of removal expenditures.
12
13 The portion of the book expense related to the recovery of the past cost of
14 removal expenditures would be included in depreciation rates without any related
15 tax benefits, because, as discussed above, the tax benefits associated with these
16 expenditures have previously been passed along to customers. When Narragansett
17 had ultimately recovered the full amount of its past cost of removal expenditures,
18 there would no longer be any past book/tax timing difference related to cost of
19 removal and the deficiency in the deferred tax reserve would no longer exist.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 19
1 For the portion of the book expense related to the recovery of future cost of
2 removal expenditures, Narragansett would provide deferred taxes, and thus
3 eliminate any "flow-through" of future tax benefits.
4
5 Narragansett does not advocate using this first method for several reasons. This
6 methodology results in very difficult and complex calculations for separating the
7 amount of book expense related to the past recovery of cost of removal
8 expenditures versus the portion related to the recovery of future cost of removal.
9 Second, in the future as the timing differences begin to reverse themselves, it
10 would be extremely difficult to determine which portion of the reversal relates to
11 deferred taxes for which Narragansett had initially provided a reserve and the
12 portion where the deferred taxes are deficient.
13
14 Q. What is the second method to recover the deficiency in the deferred tax reserve?
15 A. In the second method, Narragansett would be permitted to recover the deficiency
16 in the deferred tax reserves over a fixed number of years. Under this approach,
17 Narragansett would provide deferred taxes on the entire difference between the
18 books and the tax return related to cost of removal on a prospective basis, because
19 the deficiency in the deferred tax reserves would be collected separately. This
20 methodology ultimately achieves full amortization of book and tax timing
21 differences in a much more straight forward fashion.
22
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 20
1 Q. Does Narragansett have a proposal to recover the deficiency?
2 A. Yes. The deficiency in the deferred tax reserves could be alleviated from funds
3 that would otherwise flow through the Companies' transition charge. New
4 England Power Company ("NEP"), the Commission and the Division have
5 reached a settlement agreement in principle regarding NEP's first reconciliation
6 of the Contract Termination Charges ("CTC") billed by NEP to Narragansett.
7 Under the CTC settlement agreement, NEP will flow-through approximately $10
8 million, on a revenue requirement basis, to Narragansett through its reconciliation
9 account in 2000. Rather than reflect the reconciliation in its retail transition
10 charges, Narragansett proposes to retain this amount and apply the $ 10 million
11 against its deficiency in the deferred tax reserves (with the appropriate adjustment
12 for tax effects as described below). In addition, Narragansett proposes to use the
13 same approach for its portion (approximately $2 million) of the resolution of the
14 Hydro-Quebec litigation by NEP. This amount will also be included in NEP's
15 reconciliation for 2000 to Narragansett and would be applied to the deferred tax
16 deficiency.
17
18 Since this approach will only recover a portion of the total amount of the
19 deficiency, Narragansett also proposes to apply any future credits received from
20 future settlements and proceeds from the sales of assets or other reconciliations
21 from NEP's or Montaup's contract termination charges against the deficiency
22 during the rate freeze period. To the extent there is a remaining deferred tax
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 21
1 deficiency, Narragansett requests as part of this proceeding to be allowed to
2 collect the remaining deficiency by amortizing it over a five year period in the
3 first rate case following the end of the distribution rate freeze period.
4
5 Q. If the Commission adopted Narragansett's proposal, what would be the
6 remaining amount of unfunded deferred taxes?
7 A. As discussed above, the pre-tax deficiency in the reserve for deferred taxes
8 amounts to approximately $33.3 million as of December 31, 1998, on a revenue
9 requirement basis. If the Commission adopted Narragansett's proposal to apply
10 NEP's CTC reconciliation against the deficiency, this amount would be reduced
11 by approximately $12 million on a pre-tax basis. Thus the deferred tax deficiency
12 would be reduced to approximately $21.3 million on a pre-tax basis as of
13 December 31, 1998. Since Narragansett is proposing to correct the cost of
14 removal problem on a prospective basis beginning on January 1, 2001, the
15 unfunded deferred tax deficiency will continue to grow until that date. Therefore,
16 the final unfunded deferred tax deficiency will need to be calculated as of
17 December 31, 2000.
18
19 Q. What would the overall rate impact be from correcting the cost of removal issues
20 on a prospective basis?
21 A. As stated above, the overall impact on rates for recovering cost of removal
22 expenditures prospectively would be approximately $3.5 million. This recovery
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 22
1 consists of increased depreciation expense of $1.9 million and the cessation of the
2 "flow-through" of cost of removal benefit of $1.6 million.
3
4 Q. Is it correct to assume this problem is limited to Narragansett?
5 A. Yes. As I will discuss in further detail below, the problem is currently limited to
6 Narragansett and does not exist for BVE and Newport.
7
8 Q. Are there any other issues surrounding cost of removal that the Commission
9 should be informed about?
10 A. Yes. The IRS is currently studying whether to disallow the tax deduction for cost
11 of removal expenditures incurred during the tax year for assets which are replaced
12 by new assets of like kind. The IRS contends that the cost of removal of the old
13 asset should be capitalized as a portion of the cost of the new asset. Cost of
14 removal tax deductions would be included in the amount of tax depreciation over
15 the life of the new asset. However, to the extent the asset is removed from
16 service and is not replaced, the IRS would continue to allow a current year tax
17 deduction for cost of removal expenditures.
18
19 Q. What would the impact be on Narragansett if the IRS disallowed the cost of
20 removal tax deductions?
21 A. If the IRS disallowed the tax deductions related to cost of removal, Narragansett
22 would be required to pay the IRS approximately $6.6 million of taxes related to
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 23
1 cost of removal expenditures for the years 1994 through 1998. Since the IRS has
2 completed its audit of Narragansett through the end of 1993, the only remaining
3 issue with regards to the years 1972 through 1993, is the recovery of the
4 deficiency in the deferred tax reserves. However, since the IRS has not audited
5 1994 through 1998, Narragansett could be required to repay, with interest, any tax
6 deductions related to cost of removal taken during those years. Narragansett
7 estimates the interest on these deductions will amount to $4.3 million.
8
9 Under Narragansett's proposal described above, the $12 million applied against
10 the unfunded deferred tax reserve balance would be assumed by Narragansett,
11 with the permission of the Commission, to apply to the years for which the IRS
12 has yet to complete its audit. Therefore, to the extent the IRS does disallow these
13 tax deductions, Narragansett would reverse a portion of the $12 million it had
14 applied against the amount of the disallowance, excluding any interest. This
15 methodology would allow Narragansett to fully recover the tax benefits it has
16 passed along to customers.
17
18 V. Consolidation of Depreciation Rates
19 Q. Please describe the Companies' proposal with regard to consolidation of
20 depreciation rates.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 24
1 A. Narragansett will be the surviving entity upon completion of the merger. Thus,
2 the Companies propose to use Narragansett's settled depreciation rates, as
3 described earlier in my testimony, for the consolidated entity.
4
5 Q. Please describe why the Companies are proposing to implement Narragansett's
6 depreciation settlement rates for the consolidated entity.
7 A. To correct the cost of removal problem for Narragansett on a prospective basis,
8 the Companies would have to implement depreciation rates which contain a
9 provision to recover both past and future cost of removal expenditures. The
10 depreciation rates from Narragansett's depreciation settlement meet this
11 requirement.
12
13 Additionally, by implementing the settlement depreciation rates, the incremental
14 increase in depreciation expense Narragansett would have realized as a stand
15 alone company would be partially offset by the decrease in deprecation expense
16 BVE and Newport will realize moving from their current depreciation rate, which
17 are higher than Narragansett's current depreciation rates, to the settlement
18 depreciation rates.
19
20 Q. What is the incremental impact of applying Narragansett's depreciation settlement
21 rates to the consolidated entity?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 25
1 A. As shown in Exhibit DMW-7, page 1, the incremental impact of using the
2 settlement depreciation rates for the consolidated entity results in an increase in
3 depreciation expense of approximately $1.1 million.
4
5 This increase reflects an incremental increase of approximately $1.9 million for
6 Narragansett using the settlement depreciation rates. However as stated above,
7 since BVE's and Newport's depreciation rates are currently higher than those
8 contained in Narragansett's depreciation settlement, BVE and Newport will
9 realize an incremental decrease of approximately $815,000 and $25,000,
10 respectively, upon switching to the settlement rates. Thus, the net incremental
11 increase in deprecation expense is $ 1.1 million for the consolidated company.
12
13 Q. How did you calculate the incremental impact of using Narragansett's settled
14 depreciation rates for the consolidated entity?
15 A. I used the same methodology described above to calculate the incremental
16 impact of applying Narragansett' s settled depreciation rates for the consolidated
17 entity. As shown in Exhibit DMW-7, pages 2 and 3, depreciation expense was
18 calculated for each company's intrastate distribution and general plant based upon
19 their current depreciation rates and then based upon Narragansett's settled
20 depreciation rates. In each case, these rates were applied against the intrastate
21 plant balances as of December 31, 1998. As stated above, the incremental impact
22 of applying Narragansett's settled depreciation rates to the consolidated interstate
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 26
1 plant balances was not calculated since Narragansett, BVE and Newport each
2 operate their transmission facilities under integrated facilities agreements under
3 the jurisdiction of the FERC. Therefore, approval of a consolidated interstate
4 transmission-related depreciation rate must be obtained from the FERC.
5
6 Q. What effect does implementing Narragansett's settlement rates have on the
7 recovery of the cost of removal related items?
8 A. As shown in Exhibit DMW-8, using Narragansett's settlement depreciation rates,
9 the annual revenue requirement to correct the cost of removal issue going forward
10 would be approximately $2.7 million compared to approximately $3.5 million for
11 Narragansett as a stand alone company.
12
13 Q. Previously you discussed the possibility of the IRS disallowing the cost of
14 removal tax deductions. What would the impact be on BVE and Newport if the
15 IRS disallowed the cost of removal tax deductions?
16 A. If the IRS disallows the tax deductions for cost of removal, BVE and Newport
17 would also be required to pay to the IRS approximately $514,000 and $517,000,
18 respectively, for the period 1994 through 1998. BVE and Newport will also be
19 required to provide interest on the disallowed cost of removal which is estimated
20 to be approximately $200,000 and $158,000, respectively.
21
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 27
1 However, since BVE and Newport have been normalizing the book/tax timing
2 differences related to cost of removal over the past several years, if the IRS does
3 disallow these tax deductions, BVE and Newport would simply reverse their
4 respective corresponding deferred tax reserves to offset the impact of the
5 disallowance. Therefore, the impact of the disallowance will be limited to the
6 interest on the cost of removal tax deductions.
7
8 VI. Storm Contingency Fund
9 Q. Please describe how the Storm Contingency fund works.
10 A. Each electric utility operating in Rhode Island has a Storm Contingency Fund
11 which is used to pay for service restoration costs in the event of an extraordinary
12 storm. These reserves are funded by customers through an annual contribution
13 amount which is embedded in rates. The electric utilities also provide interest on
14 the accumulated balances in these funds.
15
16 To ensure that charges to these funds are only for extraordinary storms, the
17 Commission, in Docket No. 2500, set a threshold amount for each utility for
18 which the incremental costs per storm must exceed before service restoration
19 costs can be charged to the fund. Each year, the threshold amount is adjusted by
20 the change in the Consumer Price Index for All Urban (CPI-U) for the previous
21 year. Also, for each storm occurrence, to the extent the overall incremental cost
22 of service restoration exceeds the threshold amount, a deductible is assessed for
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 28
1 each company that is in turn deducted from the incremental storm costs charged
2 to the fund.
3
4 Q. Please describe each company's storm fund.
5 A. Please see Exhibit DMW-9. Narragansett currently collects in rates $641,000 on
6 an annual basis for continuing funding of the storm fund. As of December 31,
7 1998 Narragansett's storm contingency fund had accumulated into a reserve
8 balance of approximately $4.5 million. The threshold amount for Narragansett for
9 the year ended December 31, 1999 is $465,000. The deductible amount for
10 Narragansett is $300,000 for each storm occurrence.
11
12 BVE currently collects in rates $160,000 on an annual basis for continuing
13 funding of the storm fund. As of December 31, 1998 BVE's storm contingency
14 fund had accumulated into a reserve balance of approximately $210,000. The
15 threshold amount for BVE for the year ended December 31, 1999 is
16 approximately $145,000. The deductible amount for BVE is $94,000 for each
17 storm occurrence.
18
19 Newport currently collects in rates $240,000 on an annual basis for continuing
20 funding of the storm fund. As of December 31, 1998 Newport's storm
21 contingency fund had accumulated into a reserve balance of approximately $ 1.0
22 million. The threshold amount for Newport for the year ended December 31,
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 29
1 1999 is approximately $97,000. The deductible amount for Newport is $56,000
2 for each storm occurrence.
3
4 Q. Please describe the Companies' proposal with respect to treatment of the storm
5 contingency funds?
6 A. As shown in Exhibit DMW-9, the Companies propose to combine the current
7 storm contingency fund balances and funding levels. This will result in an
8 accumulated storm contingency fund balance of approximately $5.7 million, as of
9 December 31, 1998 and an annual funding level of $1,041,000. The Companies
10 propose to adopt Narragansett's threshold amount of $465,000 and deductible
11 amount of $300,000 for the combined entity since they are the largest.
12
13 VII. Deferred FAS 106 Cost Recovery
14 Q. Please describe the history of FAS 106.
15 A. In December 1990, the Financial Accounting Standards Board ("FASB") issued
16 Financial Accounting Standard No. 106 ("FAS 106") which required companies
17 to change from the practice of accounting for post-retirement benefits other than
18 pensions ("PBOPs") on a pay-as-you-go basis to an accrual basis. This resulted in
19 an additional incremental or "transition" expense for all companies.
20
21 As a result, the Commission opened a generic docket (Docket No. 2045)
22 regarding the rate making treatment of FAS 106. In that proceeding, the
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 30
1 Commission ordered companies switching from the pay-as-you-go approach to
2 the accrual basis to phase-in the incremental transition expense over a three year
3 period. The phase-in began on January 1, 1993. Companies were then allowed to
4 collect the deferred transition expenses at the end of the three year phase-in
5 period ratably over the next seven years. The recovery of the deferred expenses
6 was combined with the ongoing current year expense and developed into a
7 separate FAS 106 surcharge factor.
8
9 Q. Please describe the recovery of FAS 106 for each company.
10 A. Please see Exhibit DMW- 10. As of the end of 1995 Narragansett has completed
11 the transition to an accrual basis for FAS 106, and accumulated a deferred FAS
12 106 transition expense balance of approximately $4.4 million, related to intrastate
13 operations, to be recovered over the next seven years. Narragansett began
14 recovering these deferred expenses in 1996.
15
16 In November, 1997, as part of its 1998 Rate Adjustment filing, Narragansett
17 sought and received permission to apply overcollections generated by its FAS
18 106 surcharge factor to recover its remaining deferred FAS 106 balance. As a
19 result, as of December 31, 1997, Narragansett was fully recovered with respect to
20 its deferred FAS 106 costs. In that filing Narragansett also adjusted its annual
21 FAS 106 surcharge factor to collect only it's ongoing FAS 106 expenses.
22 Therefore, Narragansett has not been included in Exhibit DMW-10.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 31
1 By the end of 1995, BVE had also completed the transition to an accrual basis for
2 FAS 106, and had accumulated a deferred FAS 106 transition expense balance of
3 approximately $1.0 million to be recovered over the next seven years. BVE is
4 currently collecting approximately $145,000 in base rates annually to recover its
5 deferred FAS 106 costs. As of December 31, 1998, BVE's remaining deferred
6 FAS 106 balance was approximately $581,000. It is anticipated that at the
7 current levels, the recovery of deferred FAS 106 costs should be completed
8 during 2002.
9
10 Newport had completed the transition to an accrual basis for FAS 106 by the end
11 of 1995, and it too had an accumulated a deferred FAS 106 transition expense
12 balance of approximately $1.2 million to be recovered over the next seven years.
13 Newport is currently collecting approximately $172,000 in base rates annually to
14 recover its deferred FAS 106 costs. As of December 31, 1998, Newport's
15 remaining deferred FAS 106 balance was approximately $686,000. It is
16 anticipated that at the current levels, the recovery of deferred FAS 106 costs
17 should be completed during 2002.
18
19 Q. What are the Companies proposing with regard to deferred FAS 106 expenses?
20 A. As shown on Exhibit DMW-10, the Companies propose to combine the deferred
21 FAS 106 balances for BVE and Newport on the books of the combined entity.
22 The combined balance will be approximately $1.3 million. The Companies also
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 32
1 propose to combine the annual recovery levels for deferred FAS 106 factors
2 currently being charged by BVE and Newport until the recovery of the deferred
3 FAS 106 costs is completed, which the Company anticipates will be during the
4 year 2002. Thus, the annual recovery level of deferred FAS 106 costs for the
5 combined entity will amount to approximately $317,000. Upon completion of
6 the recovery of the deferred FAS 106 costs, this amount will be used to offset
7 other cost increases during the rate freeze period.
8
9 VIII. Hazardous Waste Cost Recovery
10 Q. Could you please describe the accounting issues related to hazardous waste?
11 A. BVE has recorded a regulatory asset for expenditures associated with hazardous
12 waste site remediation that have yet to be recovered from customers. As of
13 December 31, 1998, BVE had recorded on its books a deferred asset amounting
14 to approximately $1.5 million. As part of the settlement in RIPUC Docket No.
15 2016, BVE began recovering in rates $333,426 annually for hazardous waste site
16 remediation costs. However, for accounting purposes, BVE is amortizing
17 approximately $878,000 annually. At the present amortization level, BVE
18 anticipates that the deferred asset will be fully amortized during the year 2000.
19
20 In addition to the hazardous waste costs described above, BVE currently has
21 litigation pending on the issue of responsibility for certain remediation costs
22 associated with a manufactured gas site located on Mendon Road in Attleboro,
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 33
1 Massachusetts. In order to prevent the further accumulation of interest as a result
2 of a U. S. District court judgement that was appealed, BVE entered into an
3 escrow agreement with the Commonwealth of Massachusetts in January, 1995.
4 Under the terms of an escrow agreement arising out of the litigation, BVE
5 deposited $5.9 million, including $3.6 million of interest, into an interest bearing
6 escrow account which remains in the account while litigation continues. These
7 amounts have been recorded on BVE's books as a deferred asset.
8
9 Newport Electric does not have a hazardous waste regulatory asset recorded on its
10 books. Narragansett has recorded a provision on its books for its potential
11 liability in the remediation of a hazardous waste site. Narragansett is not currently
12 recovering these costs in rates.
13
14 Q. What are the Companies proposing with regard to recovery of the hazardous
15 waste expenditures?
16 A. The Companies propose to include BVE's hazardous waste regulatory asset on
17 the books of the combined entity and continue to recover the current amount
18 being collected in rates for BVE. The Companies propose to continue to collect
19 this amount until BVE's deferred hazardous waste cost recovery has been
20 completed.
21
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Testimony of D.M. Webster
Page 34
1 The recovery of any future liabilities regarding the remediation of hazardous
2 waste sites would be addressed as part of a future rate proceeding when the extent
3 of the Companies' liability, if any, is known. As described in the testimony of
4 Mr. Jesanis, remediation costs for hazardous waste site is one of the exogenous
5 factors proposed in the Companies' distribution rate freeze plan.
6
7 IX. Conclusion
8 Q. Does this conclude your testimony?
9 A. Yes, it does.
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibits
of
David M. Webster
Exhibit DMW-1 Settlement on Depreciation Expense R.I.P.U.C. No.
2290
Exhibit DMW-2 Incremental Impact of Narragansett Depreciation
Settlement to Correct Cost Removal
Exhibit DMW-3 Cessation of Cost of Removal Flow-Through Benefit
Exhibit DMW-4 Summary of Revenue Requirement for Cost of Removal
before Consolidation
Exhibit DMW-5 Book/Tax Timing Differences Related to Cost of Removal
Exhibit DMW-6 Unfunded Deferred Federal Income Taxes
Exhibit DMW-7 Incremental Impact of Narragansett Depreciation
Settlement
Exhibit DMW-8 Summary of Revenue Requirement for Cost of Removal
after Consolidation
Exhibit DMW-9 Summary of Storm Contingency Funds
Exhibit DMW-10 Summary of Deferred FAS 106 Costs
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-1
Exhibit DMW-1
Settlement on Depreciation Expenses
R.I.P.U.C. No. 2290
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-1
Page 1 of 5
STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
PUBLIC UTILITIES COMMISSION
- --------------------------------------------------
)
IN RE: NARRAGANSETT ELECTRIC COMPANY: ) Docket 2290
REQUEST FOR RATE INCREASE )
- --------------------------------------------------)
SETTLEMENT ON
DEPRECIATION EXPENSE
I. Introduction
On November 14, 1995, the Public Utilities Commission (Commission)
approved settlement agreements (dated September 8, 1995 and September 14, 1995,
as modified by a Supplemental Settlement dated October 11, 1995 - together, the
"Settlement") between The Narragansett Electric Company (Narragansett or the
Company), the Energy Council of Rhode island (TEC-RI), and the Division of
Public Utilities and Carriers (Division). The Settlement resolved all the
outstanding issues in Docket 2290 except for the appropriate depreciation rates
to be used for Narragansett. As part of the Settlement, the parties agreed to
complete, by January 31, 1996, a review of the depreciation study filed by
Narragansett in the rebuttal phase of Docket 2290. The Settlement further states
that if the parties reach agreement on the appropriate depreciation rates to be
used for Narragansett, the rates may be submitted by Narragansett, without
opposition by the Division, in Narragansett's next base rate proceeding. This
Settlement reflects such an agreement by the Division and Narragansett.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-1
Page 2 of 5
II. Stipulation and Settlement
After extensive discussion and review by experts retained by both the
Company and the Division, the Parties have reached agreement on the appropriate
depreciation rate methods to be used for Narragansett without opposition by the
Division, in Narragansett's next base rate proceeding filed pursuant to ss.
39-3-11, as follows:
(A) Narragansett shall change from the Broad Group Whole Life Method
of depreciation to the Vintage Group Remaining Life Method of
depreciation. These changes are recommended to better achieve the
goals and objectives of depreciation accounting through the use of a
procedure that distinguishes service lines among vintages and provides
cost apportionment over the estimated weighted average remaining life
of a rate category.
(B) For Transmission Plant, the lives shall be as set forth in
Attachment A Projection Life-Transmission Plant (the same as proposed
earlier in Docket 2290).
(C) For Distribution Plant, Narragansett shall use the same lives as
currently prescribed and specified on Attachment A.
(D) For General Plant, the life for account 390, (Structures and
Improvements), shall be reduced from 50 years to 40 years. For other
General accounts, Narragansett shall use an amortization period of 20
years.
2
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-1
Page 3 of 5
(E) For Salvage, transmission salvage shall be set at -20%.
Distribution salvage shall be set at -10%.
III. Miscellaneous Provisions
(A) Unless expressly stated herein, the making of this settlement
establishes no principles and shall not be deemed to foreclose any
party from making any contention in any other proceeding or
investigation.
(B) Unless expressly stated herein, the acceptance of this settlement
by the Commission shall not in any respect constitute a determination
by the Commission as to the merits of any issue in any rate proceeding
for this Company or another.
(C) This settlement is the product of settlement negotiations. The
content of those negotiations is privileged and all offers of
settlement shall be without prejudice to the position of any party.
(D) This settlement is submitted on the condition that it be approved
in full by the Commission, and on the further condition that if the
Commission does not approve it in its entirety it shall be deemed
withdrawn and shall not constitute a part of the record in any
proceeding or used for any purpose.
(E) The Attachments referenced in and attached to this settlement
shall be deemed an integral part hereof. In the event that any
inconsistency exists between the provisions of this settlement and the
3
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-1
Page 4 of 5
Attachment hereto, the provisions of this settlement shall supersede
the provision of any such Attachment.
IV. Conclusion
WHEREFORE, the Division and Narragansett respectfully request the
Commission approve this Settlement to resolve all depreciation rate issues in
Docket 2290.
4
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-1
Page 5 of 5
DATED AT PROVIDENCE, this 9th day of May, 1996.
THE DIVISION OF PUBLIC THE NARRAGANSETT
UTILITIES AND CARRIERS ELECTRIC COMPANY
/s/ Patricia M. French /s/ Craig L. Eaton
- ----------------------------- ----------------------------
Patricia M. French Esq. Craig L. Eaton, Esq.
Assistant Attorney General Thomas G. Robinson, Esq.
150 South Main Street 280 Melrose Street
Providence, RI 02903 Providence, RI 02907
(401) 274-4400 (401) 784-7526
5
<PAGE>
<TABLE>
<CAPTION>
Attachment A
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ___
Exhibit DMW-1
Page 5 of 5
NARRAGANSETT ELECTRIC COMPANY
SETTLEMENT OF DEPRECIATION RATES
Depreciation System
Current: Straight line method, broad group procedure, whole life technique.
Settled: Straight line method. vintage group procedure, remaining life technique for all but
accounts 391 through 398, which are to follow amortization accounting.
Proposed
Protection Life - Transmission Plant in Rate
Account Current Filing Settlement
<S> <C> <C> <C> <C>
352.00 Structures and Improvements 60.00 50.00 50.00
353.00 Station Equipment 35.00 55.00 55.00
354.00 Towers and Fixtures 65.00 50.00 50.00
355.00 Poles and Fixtures 40.00 45.00 45.00
356.00 Overhead Conductors and Devices 45.00 40.00 40.00
357.00 Underground Conduit 75.00 50.00 50.00
358.00 Underground Conductors and Devices 50.00 40.00 40.00
359.00 Roads and Trails 65.00 60.00 60.00
Estimated Annualized 1995 Accrual ($000's) $1,078 $859 $859
Projection Life - Distribution Plant
361.00 Structures and Improvements 50.00 40.00 50.00
362.00 Station Equipment 35.00 45.00 35.00
364.00 Poles Towers and Fixtures 25.00 32.00 25.00
365.00 Overhead Conductors and Devices 35.00 33.00 35.00
366.00 Underground Conduit 60.00 50.00 60.00
367.00 Underground Conductors and Devices 45.00 35.00 45.00
368.00 Line Transformers 25.00 27.00 25.00
369.00 Services 25.00 35.00 25.00
370.00 Meters 30.00 27.00 30.00
371.00 Installation on Customer Premises 35.00 20.00 35.00
372.00 Leased Property on Customer Premises 15.00 15.00 15.00
373.00 Street Lighting and Signal Systems 25.00 17.00 25.00
Estimated Annualized 1995 Accrual ($000's) $12.776 $13,703 S12,706
Projection Life - General Plant
390.00 Structures and Improvements 50.00 40.00 40.00
391.00 Office Furniture and Equipment 25.00 15.00 20.00
393.00 Stores Equipment 35.00 15.00 20.00
394.00 Tools Shop and Garage Equipment 30.00 15.00 20.00
395.00 Laboratory Equipment 25.00 15.00 20.00
397.00 Communication Equipment 10.00 15.00 20.00
398.00 Miscellaneous Equipment 25.00 15.00 20.00
Estimated Annualized 1995 Accrual ($000's) $420 $542 $495
Salvage
108.50 Transmission 0.00 -20.0% -20.0%
108.60 Distribution 0.00 -15.0% -10.0%
108.70 General 0.00 -5.0% -5.0%
Estimated Annualized 1995 Accrual ($000's) $0 $2,326 $1,626
Total Estimated Annualized 1995 Accrual ($000's)* $14,274 $17,430 $15,686
* Estimated annualized accruals are based on 1994 electric
plant in service amounts in FERC account 101.
</TABLE>
6
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-2
Exhibit DMW-2
Incremental Impact of Narragansett Depreciation Settlement
to Correct Cost Removal
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-2
Page 1 of 4
THE NARRAGANSETT ELECTRIC COMPANY
Incremental Impact of Narragansett Depreciation Settlement
1 Depreciation Expense Depreciation Expense Incremental Impact
2 Applying Depreciation Applying Current of Settlement
3 Settlement Rates Depreciation Rates Depreciation Rates
4 (a) (b) (c)=(a)-(b)
5 --- --- -----------
<S> <C> <C> <C> <C> <C>
6 Distribution Plant Depreciation $19,920,336 1/ $18,037,140 2/ $1,883,196
7
8 General Plant Depreciation 725,038 3/ 720,610 4/ 4,428
------- ------- -----
9
10 Total Depreciation $20,645,374 $18,757,750 $1,887,624
----------- ----------- ----------
</TABLE>
Notes:
1/ Exhibit DMW-2, page 2, line 29, column (e).
2/ Exhibit DMW-2, page 2, line 29, column (b).
3/ Exhibit DMW-2, page 3, line 25, column (e).
4/ Exhibit DMW-2, page 3, line 25, column (b).
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ________
Exhibit DMW-2
Page 2 of 4
THE NARRAGANSETT ELECTRIC COMPANY
Change in Distribution Plant Depreciation
to Implement Depreciation Settlement
Narragansett Depreciation Settlement
PUC Narr. Current ------------------------------------
Account Rates Investment Negative Salvage Total Rate
------- ----- ---------- ---------------- ----------
<S> <C> <C> <C> <C> <C>
1 361 2.00% 1.73% 0.37% 2.10%
2 362 2.86% 2.60% 0.37% 2.97%
3 364 4.00% 3.80% 0.37% 4.17%
4 365 2.86% 2.91% 0.37% 3.28%
5 366 1.67% 1.68% 0.37% 2.05%
6 367 2.22% 2.21% 0.37% 2.58%
7 368 4.00% 4.07% 0.37% 4.44%
8 369 4.00% 3.89% 0.37% 4.26%
9 370 3.33% 3.41% 0.37% 3.78%
10 371 2.87% 1.60% 0.37% 1.97%
11 373 4.00% 4.25% 0.37% 4.62%
12
<CAPTION>
13 The Narragansett Electric Company
Narragansett Depreciation Settlement
14 12/31/98 Depreciation ------------------------------------
15 Plant at Current Investment Negative
16 Depreciable Plant Balance I/ Rates Accrual Salvage Total
17 PUC Account (a) (b) (c) (d) (e)
----------- --- --- --- --- ---
<S> <C> <C> <C> <C> <C> <C>
18 361 $2,082,573 $41,651 $36,029 $7,706 $43,735
19 362 79,464,967 2,272,698 2,066,089 294,020 2,360,109
20 364 85,780,758 3,431,230 3,259,669 317,389 3,577,058
21 365 139,893,298 4,000,948 4,070,895 517,605 4,588,500
22 366 29,089,158 485,789 488,698 107,630 596,328
23 367 54,221,858 1,203,725 1,198,303 200,621 1,398,924
24 368 75,907,086 3,036,283 3,089,418 280,856 3,370,274
25 369 31,202,210 1,248,088 1,213,766 115,448 1,329,214
26 370 29,609,146 985,985 1,009,672 109,554 1,119,226
27 371 3,037 87 49 11 60
28 373 33,266,398 1,330,656 1,413,822 123,086 1,536,908
--------- --------- ------- ---------
29 Total Narragansett $18,037,140 $17,846,410 $2,073,926 $19,920,336
----------- ----------- ---------- -----------
</TABLE>
Notes:
1/ Exhibit DMW-2, page 4, line 18-26, column (d)
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ________
Exhibit DMW-2
Page 3 of 4
THE NARRAGANSETT ELECTRIC COMPANY
Change in General Plant Depreciation
to Implement Depreciation Settlement
Narragansett Depreciation Settlement
PUC Narr. Current ------------------------------------
Account Rates Investment Negative Salvage Total Rate
------- ----- ---------- ---------------- ----------
<S> <C> <C> <C> <C> <C>
1 390 2.00% 2.65% 0.17% 2.82%
2 391 2/ 4.00% 5.00% 0.00% 5.00%
3 393 2/ 2.86% 5.00% 0.00% 5.00%
4 394 2/ 3.33% 5.00% 0.00% 5.00%
5 395 2/ 4.00% 5.00% 0.00% 5.00%
6 397 2/ 10.00% 5.00% 0.00% 5.00%
7 398 2/ 4.00% 5.00% 0.00% 5.00%
8
<CAPTION>
9 The Narragansett Electric Company
Narragansett Depreciation Settlement
10 12/31/98 Depreciation ------------------------------------
11 Plant at Current Investment Negative
12 Depreciable Plant Balance 1/ Rates Accrual Salvage Total
13 PUC Account (a) (b) (c) (d) (e)
----------- --- --- --- --- ---
<S> <C> <C> <C> <C> <C> <C>
14 390 $12,181,900 $243,638 $322,820 $20,709 $343,529
15 391 553,326 22,133 27,666 0 27,666
16 393 441,611 12,630 22,081 0 22,081
17 394 2,113,557 70,381 105,678 0 105,678
18 395 944,498 37,780 47,225 0 47,225
19 397 3,182,694 318,269 159,135 0 159,135
20 398 394,474 15,779 19,724 0 19,724
------ ------ - ------
21 Total Narragansett $720,610 $704,329 $20,709 $725,038
-------- -------- ------- --------
</TABLE>
Notes:
1/ Exhibit DMW-2, page 4, Lines 2-14, column (d)
2/ Amortization Accounts equivalent to 5.0% depreciation rate.
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ________
Exhibit DMW-2
Page 4 of 4
THE NARRAGANSETT ELECTRIC COMPANY
Depreciable Plant Balances
As of December 31, 1998 1/
Interstate Intrastate
---------------------------------------------------
Percent of Total Amount Amount
1 Distribution Plant: (a) (b) (c)=(a) times (b) (d)= (a) - (c)
------------------ --- --- ----------------- --------------
<S> <C> <C> <C> <C> <C>
2 Structures and Improvements 361 $2,101,911 0.92% $19,338 $2,082,573
3 Station Equipment 362 80,202,833 0.92% 737,866 79,464,967
4 Poles, Towers and Fixtures 364 86,577,269 0.92% 796,511 85,780,758
5 Overhead Conductors 365 141,192,267 0.92% 1,298,969 139,893,298
6 Underground Conduit 366 29,359,263 0.92% 270,105 29,089,158
7 Underground Conductors 367 54,725,331 0.92% 503,473 54,221,858
8 Line Transformers 368 76,611,916 0.92% 704,830 75,907,086
9 Services 369 31,491,936 0.92% 289,726 31,202,210
10 Meters 370 29,884,080 0.92% 274,934 29,609,146
11 Installation on Cust. Premises 371 3,065 0.92% 28 3,037
12 Street lights 373 33,575,291 0.92% 308,893 33,266,398
---------- ------- ----------
13 Total $565,725,162 $5,204,673 $560,520,489
------------ ---------- ------------
14
15 General Plant:
16 Structures and Improvements 390 $15,140,318 19.54% $2,958,418 $12,181,900
17 Office Furniture and Equip. 391 687,703 19.54% 134,377 553,326
18 Stores Equipment 393 548,858 19.54% 107,247 441,611
19 Tools, Shop and Garage 394 2,626,842 19.54% 513,285 2,113,557
20 Laboratory Equip. 395 1,173,873 19.54% 229,375 944,498
21 Communication Equip. 397 3,955,623 19.54% 772,929 3,182,694
22 Miscellaneous Equipment 398 490,273 19.54% 95,799 394,474
------- ------ -------
23 Total $24,623,490 $4,811,430 $19,812,060
---------- ---------- -----------
24
25 Grand Total $590,348,652 $10,016,103 $580,332,549
------------ ----------- ------------
</TABLE>
Notes:
1/ Narragansett Electric's 1998 FERC Form 1, Page 207, Column (g), Lines
56-80.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-3
Exhibit DMW-3
Cessation of Cost of Removal Flow - Through Benefit
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ___
Exhibit DMW-3
Page 1 of 1
The Narragansett Electric Company
Cessation of cost of Removal Flow-Through Benefit
(Thousands of Dollars)
1. Calculation of 3 Year Average cost of Removal Tax Deduction:
2.
3. Total Interstate Intrastate
4. Year Company Plant Plant
5. 1998 $2,571 $373 $2,198 1/
6. 1997 $4,439 $1,447 $2,992 1/
7. 1996 $10,584 $6,753 $3,831 1/
------
8.
9. 3 Year Average $3,007 2/
10.
11. Tax on Cost of Removal Dedution $1,052 3/
12.
13. Revenue Requirement on cost of Removal
14. Flow-Through $1,618 4/
------
Notes:
1/ Actual cost of removal Deduction per Tax Returns.
2/ Average of Intrastate cost of Removal Tax Deductions on Lines 5,6&7.
3/ Line 9 times Federal Income Tax Rate (35%).
4/ Line 11 divided by (1-.35) to Reflect Revenue Requirement.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-4
Exhibit DMW-4
Summary of Revenue Requirement for Cost of Removal
before Consolidation
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ___
Exhibit DMW-4
Page 1 of 1
The Narragansett Electric Company
Summary of Revenue Requirement for
Cost of Removal
(Thousands of Dollars)
1 Increase in Depreciation Expenses to Reflect
2 Narragansett Depreciation Settlement $1,888 1/
3
4
5 Cessation of Cost of Removal Flow-Though Benefit $1,618 2/
6 ------
7
8 Total Increase in Narragansett Revenue Requirement $3,506 3/
------
Notes:
- -----
1/ Exhibit DMW-2, page 1, line 10, column (c).
2/ Exhibit DMW-3, page 1, line 14.
3/ Sum of Lines 2 and Line 5.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-5
Exhibit DMW-5
Book/Tax Timing Differences Related to Cost of Removal
<PAGE>
<TABLE>
<CAPTION>
Narrangsett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-5
Page 1 of 3
The Narragansett Electric Company
Box/Tax Timing Differences Related to Cost of Removal
1 Assumptions:
2 Asset # 1 Installed Costs $20,000
3 Asset Depreciable Life 10 yrs.
4 Estimated Cost of Removal $1,000
5
6
7
8
9 Book Depreciation Tax Deductions Book/Tax Accumulated
10 Asset Cost of Asset Cost of Timing Deferred Deferred Tax
11 Depreciation Removal Total Depreciation Removal Total Difference Taxes Reserve
12 (a) 1/ (b) 2/ (c)=(a)+(b) (d) 3/ (e) 4/ (f)=(d)+(e) (g)=(f)-(c) (h) 5/ (i) 6/
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
13 Year 1 $2,000 $100 $2,100 $2,000 $0 $2,000 ($100) $35 $35
14 Year 2 2,000 100 2,100 2,000 0 2,000 (100) 35 70
15 Year 3 2,000 100 2,100 2,000 0 2,000 (100) 35 105
16 Year 4 2,000 100 2,100 2,000 0 2,000 (100) 35 140
17 Year 5 2,000 100 2,100 2,000 0 2,000 (100) 35 175
18 Year 6 2,000 100 2,100 2,000 0 2,000 (100) 35 210
19 Year 7 2,000 100 2,100 2,000 0 2,000 (100) 35 245
20 Year 8 2,000 100 2,100 2,000 0 2,000 (100) 35 280
21 Year 9 2,000 100 2,100 2,000 0 2,000 (100) 35 315
22 Year 10 2,000 100 2,100 2,000 0 2,000 (100) 35 350
23 Year 11 1,000 1,000 1,000 (350) 0
24
25 Totals $20,000 $1,000 $21,000 $20,000 $1,000 $21,000 $0 $0
1 Assumptions:
2 Asset # 1 Installed Costs $20,000s
3 Asset Depreciable Life 10 yrs.
4 Estimated Cost of Removal $1,000l
5
6
7
8
9 Cost of Service
10 Depreciation Current Deferred
11 Expense FIT FIT Total
12 (j) = (c) (k) 7/ (l) = (h) (m)=(j)+(k)+(l)
13
<S> <C> <C> <C> <C>
14 Year 1 $2,100 ($35) $35 $2,100
15 Year 2 2,100 ($35) 35 2,100
16 Year 3 2,100 ($35) 35 2,100
17 Year 4 2,100 ($35) 35 2,100
18 Year 5 2,100 ($35) 35 2,100
19 Year 6 2,100 ($35) 35 2,100
20 Year 7 2,100 ($35) 35 2,100
21 Year 8 2,100 ($35) 35 2,100
22 Year 9 2,100 ($35) 35 2,100
23 Year 10 2,100 ($35) 35 2,100
24 Year 11 $350 (350) 0
25 Totals $21,000 $0 $0 $21,000
Notes:
1/ Column (a) equals depreciation of installed property over ten years.
2/ Column (b) equals cost of removal on installed property over ten years.
3/ Column (d) equals depreciation of installed property over ten years (column (a)).
4/ Column (e) reflects tax deduction in year cost of removal expenditures incurred.
5/ Column (h) equals column (g) times federal income tax rate (35%).
6/ Column (i) equals summation of column (h).
7/ Column (k) equals column (g) times 35% divided by 65% minus column (h) times 35% divided by 65%.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narrangsett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-5
Page 2 of 3
The Narragansett Electric Company
Box/Tax Timing Differences Related to Cost of Removal
1 Assumptions: Asset #1 Asset #2
2 Installed Date Year 1 Year 11
3 Installed Cost $20,000 $30,000
4 Asset Depreciable Life 10 yrs. 10 yrs.
5 Estimated Cost of Removal $1,000 $l,500
6
7
8
9
10 Book Depreciation Tax Deductions Book/Tax Accumulated
11 Asset Cost of Asset Cost of Timing Deferred Deferred Tax
12 Depreciation Removal Total Depreciation Removal Total Difference Taxes Reserve
13 (a) 1/ (b) 2/ (c)=(a)+(b) (d) 3/ (e) 4/ (f)=(d)+(e) (g)=(f)-(c) (h) 5/ (i) 6/
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
14 Year 1 $2,000 $0 $2,000 $2,000 $0 $2,000 $0 $0 $0
15 Year 2 2,000 0 2,000 2,000 0 2,000 0 0 0
16 Year 3 2,000 0 2,000 2,000 0 2,000 0 0 0
17 Year 4 2,000 0 2,000 2,000 0 2,000 0 0 0
18 Year 5 2,000 0 2,000 2,000 0 2,000 0 0 0
19 Year 6 2,000 0 2,000 2,000 0 2,000 0 0 0
20 Year 7 2,000 0 2,000 2,000 0 2,000 0 0 0
21 Year 8 2,000 0 2,000 2,000 0 2,000 0 0 0
22 Year 9 2,000 0 2,000 2,000 0 2,000 0 0 0
23 Year 10 2,000 0 2,000 2,000 0 2,000 0 0 0
24 Year 11 3,000 250 3,250 3,000 1,000 4,000 (750) 0 0
25 Year 12 3,000 250 3,250 3,000 0 3,000 250 0 0
26 Year 13 3,000 250 3,250 3,000 0 3,000 250 0 0
27 Year 14 3,000 250 3,250 3,000 0 3,000 250 0 0
28 Year 15 3,000 250 3,250 3,000 0 3,000 250 0 0
29 Year 16 3,000 250 3,250 3,000 0 3,000 250 0 0
30 Year 17 3,000 250 3,250 3,000 0 3,000 250 0 0
31 Year 18 3,000 250 3,250 3,000 0 3,000 250 0 0
32 Year 19 3,000 250 3,250 3,000 0 3,000 250 0 0
33 Year 20 3,000 250 3,250 3,000 0 3,000 250 0 0
34 Year 21 1,500 1,500 (1,500) 0 0
35
36 Totals $50,000 $2,500 $52,500 $50,000 $2,500 $52,500 $0 $0 $0
1 Assumptions: Asset #1 Asset #2
2 Installed Date Year 1 Year 11
3 Installed Cost $20,000 $30,000
4 Asset Depreciable Life 10 yrs. 10 yrs.
5 Estimated Cost of Removal $1,000 $l,500
6
7
8
9
10 Cost of Service
11 ----------------------------------------------------
12 Depreciation Current Deferred
13 Expense FIT FIT Total
(j)=(c) (k) 7/ (l)=(h) (m)=(j)+(k)+(l)
<S> <C> <C> <C> <C>
14 Year 1 $2,000 $0 $0 $2,000
15 Year 2 2,000 0 0 2,000
16 Year 3 2,000 0 0 2,000
17 Year 4 2,000 0 0 2,000
18 Year 5 2,000 0 0 2,000
19 Year 6 2,000 0 0 2,000
20 Year 7 2,000 0 0 2,000
21 Year 8 2,000 0 0 2,000
22 Year 9 2,000 0 0 2,000
23 Year 10 2,000 0 0 2,000
24 Year 11 3,250 (404) 0 2,846
25 Year 12 3,250 135 0 3,385
26 Year 13 3,250 135 0 3,385
27 Year 14 3,250 135 0 3,385
28 Year 15 3,250 135 0 3,385
29 Year 16 3,250 135 0 3,385
30 Year 17 3,250 135 0 3,385
31 Year 18 3,250 135 0 3,385
32 Year 19 3,250 135 0 3,385
33 Year 20 3,250 135 0 3,385
34 Year 21 0 (808) 0 (808)
35
36 Totals $52,500 $0 $0 $52,500
Notes:
1/ Column (a) equals depreciation of installed property over ten years.
2/ Column (b) equals cost of removal on installed property over ten years.
3/ Column (d) equals depreciation of installed property over ten years (Column (a)).
4/ Column (e) reflects tax deduction in year cost of removal expenditures incurred.
5/ Column (h) reflects the absence of deferred taxes in this example.
6/ Column (i) equals summation of column (h).
7/ Column (k) equals column (g) times 35% divided by 65% minus column (h) times 35% divided by 65%.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narrangsett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-5
Page 3 of 3
The Narragansett Electric Company
Box/Tax Timing Differences Related to Cost of Removal
1 Assumptions: Asset #1 Asset #2
2 Installed Date Year 1 Year 11
3 Installed Cost $20,000 $30,000
4 Asset Depreciable Life 10 yrs. 10 yrs.
5 Estimated Cost of Removal $1,000 $l,500
6
7
8
10 Book Depreciation Tax Deductions Book/Tax Accumulated
11 Asset Cost of Asset Cost of Timing Deferred Deferred Tax
12 Depreciation Removal Total Depreciation Removal Total Difference Taxes Reserve
13 (a) 1/ (b) 2/ (c)=(a)+(b) (d) 3/ (e) 4/ (f)=(d)+(e) (g)= (f)-(c) (h) 5/ (i) 6/
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
14 Year 1 $2,000 $0 $2,000 $2,000 $0 $2,000 $0 $0 $0
15 Year 2 2,000 0 2,000 2,000 0 2,000 0 0 0
16 Year 3 2,000 0 2,000 2,000 0 2,000 0 0 0
17 Year 4 2,000 0 2,000 2,000 0 2,000 0 0 0
18 Year 5 2,000 0 2,000 2,000 0 2,000 0 0 0
19 Year 6 2,000 0 2,000 2,000 0 2,000 0 0 0
20 Year 7 2,000 0 2,000 2,000 0 2,000 0 0 0
21 Year 8 2,000 0 2,000 2,000 0 2,000 0 0 0
22 Year 9 2,000 0 2,000 2,000 0 2,000 0 0 0
23 Year 10 2,000 0 2,000 2,000 0 2,000 0 0 0
24 Year 11 3,000 250 3,250 3,000 1,000 4,000 (750) 263 263
25 Year 12 3,000 250 3,250 3,000 0 3,000 250 (88) 175
26 Year 13 3,000 250 3,250 3,000 0 3,000 250 (88) 88
27 Year 14 3,000 250 3,250 3,000 0 3,000 250 (88) 0
28 Year 15 3,000 250 3,250 3,000 0 3,000 250 (88) (88)
29 Year 16 3,000 250 3,250 3,000 0 3,000 250 (88) (175)
30 Year 17 3,000 250 3,250 3,000 0 3,000 250 (88) (263)
31 Year 18 3,000 250 3,250 3,000 0 3,000 250 (88) (350)
32 Year 19 3,000 250 3,250 3,000 0 3,000 250 (88) (438)
33 Year 20 3,000 250 3,250 3,000 0 3,000 250 (88) (525)
34 Year 21 1,500 1,500 (1,500) 525 $0
35
36 Totals $50,000 $2,500 $52,500 $50,000 $2,500 $52,500 $0 $0
1 Assumptions: Asset #1 Asset #2
2 Installed Date Year 1 Year 11
3 Installed Cost $20,000 $30,000
4 Asset Depreciable Life 10 yrs. 10 yrs.
5 Estimated Cost of Removal $1,000 $l,500
6
7
8
9
10 Cost of Service
11 Depreciation Current Deferred
12 Expense FIT FIT Total
13 (j)=(c) (k)7/ (l)=(h) (m)=(j)+(k)+(l)
14 Year 1 $2,000 $0 $0 $2,000
15 Year 2 2,000 0 0 2,000
16 Year 3 2,000 0 0 2,000
17 Year 4 2,000 0 0 2,000
18 Year 5 2,000 0 0 2,000
19 Year 6 2,000 0 0 2,000
20 Year 7 2,000 0 0 2,000
21 Year 8 2,000 0 0 2,000
22 Year 9 2,000 0 0 2,000
23 Year 10 2,000 0 0 2,000
24 Year 11 3,250 (263) 263 3,250
25 Year 12 3,250 88 (88) 3,250
26 Year 13 3,250 88 (88) 3,250
27 Year 14 3,250 88 (88) 3,250
28 Year 15 3,250 88 (88) 3,250
29 Year 16 3,250 88 (88) 3,250
30 Year 17 3,250 88 (88) 3,250
31 Year 18 3,250 88 (88) 3,250
32 Year 19 3,250 88 (88) 3,250
33 Year 20 3,250 88 (88) 3,250
34 Year 21 0 (525) 525 0
35
36 Totals $52,500 $0 $0 $52,500
Notes:
1/ Column (a) equals depreciation of installed property over ten years.
2/ Column (b) equals cost of removal on installed property over ten years.
3/ Column (d) equals depreciation of installed property over ten years (Column (a)).
4/ Column (e) reflects tax deduction in year cost of removal expenditures incurred.
5/ Column (h) equals column (g) times federal tax rate (35%).
6/ Column (i) equals summation of column (h).
7/ Column (k) equals column (g) times 35% divided by 65% minus column (h) times 35% divided by 65%.
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-6
Exhibit DMW-6
Unfunded Deferred Federal Income Taxes
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-6
Page 1 of 1
THE NARRAGANSETT ELECTRIC COMPANY
Unfunded Deferred Federal Income Taxes
($000s)
1 Book Depreciable Plant at 12/31/98 $713,405
2 Less: Accumulated Depreciation (209,159)
3 Permanent book/tax differences
4 Equity AFUDC (1,489)
5 ITC Basis Adjustment (1,689)
-------
6 Adjusted net plant per books $501,068
7
8 Tax Depreciable Plant 701,399
9 Less: Accumulated depreciation (406,543)
--------
10 Adjusted net tax plant 294,856
11
12 Cumulative Timing Difference 206,212
13 Current Tax Rate 35.0%
-----
14
15 Total Cumulative Deferred Federal Tax
Liability $72,174
16
17 Property Related Deferred FIT Reserves
per Books at 12/31/98:
18
19 Contributions in Aid of Construction ($2,408)
20 Liberalized Depreciation 55,012
21 Construction Interest (1,166)
22 Construction - Other (11)
23 Cost of Removal 2,591
24 ACRS Retirements 1,560
25 Transfer Accounts (1,340)
26 Unfunded Tax Liability 38
--
27 Total $54,275
-------
28
29 Unfunded Property-Related Deferred $17,899
FIT Reserves
30
31 Non-Property Related Deferred FIT
Reserves per Books at 12/31/98:
32
33 Unfunded/
Bal. Per Bal. @ (Excess)
Books 35% --------
34 Deferred Tax Assets (14,694) (15,360) (666)
35 Deferred Tax Liabilities 10,287 14,751 4,464
36
37
38 Unfunded Non Property-Related
Deferred FIT Reserves 3,798
39 -----
40 Total Unfunded Deferred FIT
Reserves $21,697
-------
41
42 Tax Gross-Up Factor 1/ 1.5382
------
43
44 Total Revenue Retirement for Unfunded
Deferred FIT Reserves $33,374
-------
1/ For Rhode Island: 1 plus Federal Income Tax (FIT) Rate divided by 1
minus FIT rate. (1+(35%/(1-35%))).
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-7
Exhibit DMW-7
Incremental Impact of Narragansett Depreciation Settlement
<PAGE>
<TABLE>
<CAPTION>
Narrangansett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-7
Page 1 of 4
The Narragansett Electric Company
Incremental Impact of Narragansett Depreciation Settlement
on Consolidated Entity
1 Distribution Plant Deprec. Distribution Plant Deprec.
2 Applying Depreciation Applying Current
3 Settlement Rates Depreciation Rates
<S> <C> <C> <C>
4 Company (a) (b)
5
6 The Narragansett Electric Company $19,920,336 1/ $18,037,140 2/
7
8 Blackstone Valley Electric Company 3,541,466 3/ 4,293,217 4/
9
10 Newport Electric Company 2,065,635 5/ 2,135,668 6/
11
12 Total Distribution Plant Depreciation $25,527,437 $24,466,025
13
14
15 General Plant Deprec. General Plant Deprec.
16 Applying Depreciation Applying Current
17 Settlement Rates Depreciation Rates
18 Company (a) (b)
19
20 The Narragansett Electric Company $725,038 7/ $720,610 8/
21
22 Blackstone Valley Electric Company 160,952 9/ $222,867 10/
23
24 Newport Electric Company 194,232 11/ $147,217 12/
25
26 Total General Plant Depreciation $1,080,222 $1,090,694
27
28 Grand Total Depreciation $26,607,659 $25,556,719
1 Incremental Impact
2 of Settlement
3 Depreciation Rates
4 Company (c)=(a)-(b)
5
6 The Narragansett Electric Company $1,883,196
7
8 Blackstone Valley Electric Company (751,751)
9
10 Newport Electric Company (70,033)
11
12 Total Distribution Plant Depreciation $1,061,412
13
14
15 Incremental Impact
16 of Settlement
17 Depreciation Rates
18 Company (c)=(a)-(b)
19
20 The Narragansett Electric Company $4,428
21
22 Blackstone Valley Electric Company (61,915)
23
24 Newport Electric Company 47,015
25
26 Total General Plant Depreciation ($10,472)
27
28 Grand Total Depreciation $1,050,940
Notes:
1/ Exhibit DMW-7, page 2, line 29, column (e).
2/ Exhibit DMW-7, page 2, line 29, column (b).
3/ Exhibit DMW-7, page 2, line 47, column (e).
4/ Exhibit DMW-7, page 2, line 47, column (b).
5/ Exhibit DMW-7, page 2, line 65, column (e).
6/ Exhibit DMW-7, page 2, line 65, column (b).
7/ Exhibit DMW-7, page 3, line 25, column (e).
8/ Exhibit DMW-7, page 3, line 25, column (b).
9/ Exhibit DMW-7, page 3, line 41, column (e).
10/ Exhibit DMW-7, page 3, line 41, column (b).
11/ Exhibit DMW-7, page 3, line 57, column (e).
12/ Exhibit DMW-7, page 3, line 57, column (b).
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narrangansett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-7
Page 2 of 4
The Narragansett Electric Company
Change in Distribution Plant Depreciation to Narragansett's
Depreciation Settlement for Consolidated Entity
PUC Narr. Current Narragansett Depreciation Settlement Blackstone Newport
Account Rates Investment Negative Salvage Total Rate Valley Electric
<S> <C> <C> <C> <C> <C> <C> <C>
1 361 2.00% 1.73% 0.37% 2.10% 2.40% 1.71%
2 362 2.86% 2.60% 0.37% 2.97% 2.79% 3.73%
3 364 4.00% 3.80% 0.37% 4.17% 7.44% 4.28%
4 365 2.86% 2.91% 0.37% 3.28% 3.63% 2.74%
5 366 1.67% 1.68% 0.37% 2.05% 1.98% 1.28%
6 367 2.22% 2.21% 0.37% 2.58% 3.00% 3.11%
7 368 4.00% 4.07% 0.37% 4.44% 3.49% 3.57%
8 369 4.00% 3.89% 0.37% 4.26% 5.53% 5.14%
9 370 3.33% 3.41% 0.37% 3.78% 3.12% 2.89%
10 371 2.87% 1.60% 0.37% 1.97% 7.74% 7.74%
11 373 4.00% 4.25% 0.37% 4.62% 9.27% 4.08%
12
13 The Narragansett Electric Company
14 Intrastate Depreciation Narragansett Depreciation Settlement
15 Plant at Current Investment Negative
16 Depreciable Plant Balance 1/ Rates Accrual Salvage Total
17 PUC Account (a) (b) (c) (d) (e)
18 361 $2,082,573 $41,651 $36,029 $7,706 $43,735
19 362 79,464,967 2,272,698 2,066,089 294,020 2,360,109
20 364 85,780,758 3,431,230 3,259,669 317,389 3,577,058
21 365 139,893,298 4,000,948 4,070,895 517,605 4,588,500
22 366 29,089,158 485,789 488,698 107,630 596,328
23 367 54,221,858 1,203,725 1,198,303 200,621 1,398,924
24 368 75,907,085 3,036,283 3,089,418 280,856 3,370,274
25 369 31,202,210 1,248,088 1,213,766 115,448 1,329,214
26 370 29,609,147 985,985 1,009,672 109,554 1,119,226
27 371 3,037 87 49 11 60
28 373 33,266,397 1,330,656 1,413,822 123,086 1,536,908
29 Total Narragansett $18,037,140 $17,846,410 $2,073,926 $19,920,336
30
31 Blackstone Valley Electric Company
32 Intrastate Depreciation Narragansett Depreciation Settlement
33 Plant at Current Investment Negative
34 Depreciable Plant Balance 2/ Rates Accrual Salvage Total
35 PUC Account (a) (b) (c) (d) (e)
36 361 $2,038,522 $48,925 $35,266 $7,543 $42,809
37 362 14,912,929 416,071 387,736 55,178 442,914
38 364 15,911,336 1,183,803 604,631 58,872 663,503
39 365 18,006,124 653,622 523,978 66,623 590,601
40 366 4,820,439 95,445 80,983 17,836 98,819
41 367 8,098,313 242,949 178,973 29,964 208,937
42 368 14,093,867 491,876 573,620 52,147 625,767
43 369 9,474,467 523,938 368,557 35,056 403,613
44 370 6,617,396 206,463 225,653 24,484 250,137
45 373 4,639,963 430,125 197,198 17,168 214,366
46 Total Blackstone Valley $4,293,217 $3,176,595 $364,871 $3,541,466
47
48 Newport Electric Company
49 Intrastate Depreciation Depreciation Settlement
50 Plant at Current Investment Negative
51 Depreciable Plant Balance 3/ Rates Accrual Salvage Total
52 PUC Account (a) (b) (c) (d) (e)
53 361 $399,086 $6,824 $6,904 $1,477 $8,381
54 362 13,243,627 493,987 344,334 49,001 393,335
55 364 10,170,129 435,282 386,465 37,629 424,094
56 365 8,665,724 237,441 252,173 32,063 284,236
57 366 3,215,935 41,164 54,028 11,899 65,927
58 367 10,906,469 339,191 241,033 40,354 281,387
59 368 6,023,816 215,050 245,169 22,288 267,457
60 369 2,641,840 135,791 102,768 9,775 112,543
61 370 3,251,741 93,975 110,884 12,031 122,915
62 371 731,940 56,652 11,711 2,708 14,419
63 373 1,968,416 80,311 83,658 7,283 90,941
64 Total Newport $2,135,668 $1,839,127 $226,508 $2,065,635
65
66 Total Depreciation $24,466,025 $22,862,132 $2,665,305 $25,527,437
Notes:
1/ Exhibit DMW-7, page 4, lines 1-11, column (d)
2/ Exhibit DMW-7, page 4, lines 30-40, column (d)
3/ Exhibit DMW-7, page 4, lines 59-69, column (d)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narrangansett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-7
Page 3 of 4
The Narragansett Electric Company
Change in General Plant Depreciation to Narragansett's
Depreciation Settlement for Consolidated Entity
PUC Narr. Current Narragansett Depreciation Settlement Blackstone Newport
Account Rates Investment Negative Salvage Total Rate Valley Electric
<S> <C> <C> <C> <C> <C> <C> <C>
1 390 2.00% 2.65% 0.17% 2.82% 4.57% 1.73%
2 391 4/ 4.00% 5.00% 0.00% 5.00% 4.62% 5.28%
3 392 4/ 0.00% 5.00% 0.00% 5.00% 0.00% 0.00%
4 393 4/ 2.86% 5.00% 0.00% 5.00% 6.71% 4.16%
5 394 4/ 3.33% 5.00% 0.00% 5.00% 4.58% 3.75%
6 395 4/ 4.00% 5.00% 0.00% 5.00% 3.23% 4.10%
7 396 4/ 4.68% 5.00% 0.00% 5.00% 0.00% 4.68%
8 397 4/ 10.00% 5.00% 0.00% 5.00% 9.53% 4.70%
9 398 4/ 4.00% 5.00% 0.00% 5.00% 8.47% 3.49%
10
11 The Narragansett Electric Company
12 Intrastate Depreciation Narragansett Depreciation Settlement
13 Plant at Current Investment Negative
14 Depreciable Plant Balance 1/ Rates Accrual Salvage Total
15 PUC Account (a) (b) (c) (d) (e)
16 390 $12,181,900 $243,638 $322,820 $20,709 $343,529
17 391 553,326 22,133 27,666 0 27,666
18 393 441,611 12,630 22,081 0 22,081
19 394 2,113,557 70,381 105,678 0 105,678
20 395 944,498 37,780 47,225 0 47,225
21 397 3,182,694 318,269 159,135 0 159,135
22 398 394,474 15,779 19,724 0 19,724
23 Total Narragansett $720,610 $704,329 $20,709 $725,038
24
25 Blackstone Valley Electric Company
26 Intrastate Depreciation Narragansett Depreciation Settlement
27 Plant at Current Investment Negative
28 Depreciable Plant Balance 2/ Rates Accrual Salvage Total
29 PUC Account (a) (b) (c) (d) (e)
30 390 $2,769,094 $126,548 $73,381 $4,707 $78,088
31 391 597,292 27,595 29,865 0 29,865
32 393 13,656 916 683 0 683
33 394 325,641 14,914 16,282 0 16,282
34 395 236,970 7,654 11,849 0 11,849
35 397 402,841 38,391 20,142 0 20,142
36 398 80,861 6,849 4,043 0 4,043
37 Total Blackstone Valley $222,867 $156,245 $4,707 $160,952
38
39 Newport Electric Company
40 Intrastate Depreciation Depreciation Settlement
41 Plant at Current Investment Negative
42 Depreciable Plant Balance 3/ Rates Accrual Salvage Total
43 PUC Account (a) (b) (c) (d) (e)
44 390 $3,490,322 $60,383 $92,494 $5,934 $98,428
45 391 576,798 30,455 28,840 0 28,840
46 392 5/ 1,058,572 0 0 0 0
47 393 61,135 2,543 3,057 0 3,057
48 394 419,532 15,732 20,977 0 20,977
49 395 251,853 10,326 12,593 0 12,593
50 396 11,874 556 594 0 594
51 397 534,023 25,099 26,701 0 26,701
52 398 60,841 2,123 3,042 0 3,042
53 Total Newport $147,217 $188,298 $5,934 $194,232
54
55 Total Depreciation $1,090,694 $1,048,872 $31,350 $1,080,222
Notes:
1/ Exhibit DMW-7, page 4, lines 15-23, column (d)
2/ Exhibit DMW-7, page 4, lines 44-52, column (d)
3/ Exhibit DMW-7, page 4, lines 73-81, column (d)
4/ Amortization Accounts equivalent to 5.0% depreciation rate.
5/ Newport Electric depreciates its vehicles on a vehicle by vehicle basis. During 1998 depreciation expense of $14,611 was
recorded for vehicles. As of December 31, 1998, vehicles had a remaining net book values of $130,714. Depreciation
Expense for 1999 is estimated to be $10,800. Therefore, the depreciation effects from account 392 have been excluded from
this analysis.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narrangansett Electric
BVE/Newport Electric
R.I.P.U.C. No. _____
Exhibit DMW-7
Page 4 of 4
The Narragansett Electric Company
Depreciable Plant Balances
Interstate Intrastate
As of 12/31/98 1/ Percent of Total Amount Amount
The Narragansett Electric Company (a) (b) (c) = (a) x (b) (d) = (a) - (c)
Distribution Plant:
<S> <C> <C> <C> <C> <C>
1 Structures and Improvements 361 $2,101,911 0.92% $19,338 $2,082,573
2 Station Equipment 362 80,202,833 0.92% 737,866 79,464,967
3 Poles, Towers and Fixtures 364 86,577,269 0.92% 796,511 85,780,758
4 Overhead Conductors 365 141,192,267 0.92% 1,298,969 139,893,298
5 Underground Conduit 366 29,359,263 0.92% 270,105 29,089,158
6 Underground Conductors 367 54,725,331 0.92% 503,473 54,221,858
7 Line Transformers 368 76,611,915 0.92% 704,830 75,907,085
8 Services 369 31,491,936 0.92% 289,726 31,202,210
9 Meters 370 29,884,081 0.92% 274,934 29,609,147
10 Installation on Cust. Premises 371 3,065 0.92% 28 3,037
11 Street lights 373 33,575,290 0.92% 308,893 33,266,397
12 Total $565,725,162 $5,204,673 $560,520,489
13
14 General Plant:
15 Structures and Improvements 390 $15,140,318 19.54% $2,958,418 $12,181,900
16 Office Furniture and Equip. 391 687,703 19.54% 134,377 553,326
17 Stores Equipment 393 548,858 19.54% 107,247 441,611
18 Tools, Shop and Garage 394 2,626,842 19.54% 513,285 2,113,557
19 Laboratory Equip. 395 1,173,873 19.54% 229,375 944,498
20 Communication Equip. 397 3,955,623 19.54% 772,929 3,182,694
21 Miscellaneous Equipment 398 490,273 19.54% 95,799 394,474
22 Total $24,623,490 $4,811,430 $19,812,060
23
24 Grand Total $590,348,652 $10,016,103 $580,332,549
25
26 Blackstone Valley Electric Company As of 12/31/98 Interstate Interstate Intrastate
27 Distribution Plant: (a) (b) (c) (d)
28 Structures and Improvements 361 $2,123,460 $84,938 $2,038,522
29 Station Equipment 362 15,534,301 4.00% 621,372 14,912,929
30 Poles, Towers and Fixtures 364 16,574,308 4.00% 662,972 15,911,336
31 Overhead Conductors 365 18,756,379 4.00% 750,255 18,006,124
32 Underground Conduit 366 5,021,291 4.00% 200,852 4,820,439
33 Underground Conductors 367 8,435,743 4.00% 337,430 8,098,313
34 Line Transformers 368 14,681,111 4.00% 587,244 14,093,867
35 Services 369 9,869,236 4.00% 394,769 9,474,467
36 Meters 370 6,893,121 4.00% 275,725 6,617,396
37 Street lights 373 4,833,295 4.00% 193,332 4,639,963
38 Total $102,722,245 4.00% $4,108,889 $98,613,356
39
40 General Plant:
41 Structures and Improvements 390 $2,884,473 4.00% $115,379 $2,769,094
42 Office Furniture and Equip. 391 622,179 4.00% 24,887 597,292
43 Stores Equipment 393 14,225 4.00% 569 13,656
44 Tools, Shop and Garage 394 339,209 4.00% 13,568 325,641
45 Laboratory Equip. 395 246,844 4.00% 9,874 236,970
46 Communication Equip. 397 419,626 4.00% 16,785 402,841
47 Miscellaneous Equipment 398 84,230 4.00% 3,369 80,861
48 Total $4,610,786 $184,431 $4,426,355
49
50 Grand Total $107,333,031 $4,293,320 $103,039,711
51
52 Newport Electric Company As of 12/31/98 Interstate Interstate Intrastate
53 Distribution Plant: (a) (b) (c) (d)
54 Structures and Improvements 361 $408,858 2.39% $9,772 $399,086
55 Station Equipment 362 13,567,900 2.39% 324,273 13,243,627
56 Poles, Towers and Fixtures 364 10,419,147 2.39% 249,018 10,170,129
57 Overhead Conductors 365 8,877,906 2.39% 212,182 8,665,724
58 Underground Conduit 366 3,294,678 2.39% 78,743 3,215,935
59 Underground Conductors 367 11,173,516 2.39% 267,047 10,906,469
60 Line Transformers 368 6,171,310 2.39% 147,494 6,023,816
61 Services 369 2,706,526 2.39% 64,686 2,641,840
62 Meters 370 3,331,361 2.39% 79,620 3,251,741
63 Installation on Cust. Premises 371 749,862 2.39% 17,922 731,940
64 Street lights 373 2,016,613 2.39% 48,197 1,968,416
65 Total $62,717,677 $1,498,954 $61,218,723
66
67 General Plant:
68 Structures and Improvements 390 $3,624,426 3.70% $134,104 $3,490,322
69 Office Furniture and Equip. 391 598,959 3.70% 22,161 576,798
70 Transportation Equip. 392 1,099,244 3.70% 40,672 1,058,572
71 Stores Equipment 393 63,484 3.70% 2,349 61,135
72 Tools, Shop and Garage 394 435,651 3.70% 16,119 419,532
73 Laboratory Equip. 395 261,530 3.70% 9,677 251,853
74 Power Operated Equip. 396 12,330 3.70% 456 11,874
75 Communication Equip. 397 554,541 3.70% 20,518 534,023
76 Miscellaneous Equipment 398 63,179 3.70% 2,338 60,841
77 Total $6,713,344 $248,393 $6,464,951
78
79 Grand Total $69,431,021 $1,747,347 $67,683,674
Notes:
1/ Narragansett Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-68.
2/ Blackstone Valley Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-68.
3/ Newport Electric's 1998 FERC Form 1, Page 207, Column (g), Lines 56-68.
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-8
Exhibit DMW-8
Summary of Revenue Requirement for Cost of Removal
after Consolidation
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No._______
Exhibit DMW-8
Page 1 of 1
The Narragansett Electric Company
Summary of Revenue Requirement for
Cost of Removal for Consolidated Entity
(Thousands of Dollars)
1 Increase in Depreciation Expenses to Reflect
2 Narragansett Depreciation Settlement $1,051 l/
3
4
5 Cessation of Cost of Removal Flow-Though Benefit $1,618 2/
-----
6
7
8 Total Increase in Narragansett Revenue Requirement $2,669 3/
------
Notes:
1/ Exhibit DMW-7, page 1, line 28, column (c).
2/ Exhibit DMW-3, page 1, line 14.
3/ Sum of Line 2 and Line 5.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-9
Exhibit DMW-9
Summary of Storm Contingency Funds
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ____
Exhibit DMW-9
Page 1 of 1
THE NARRAGANSETT ELECTRIC COMPANY
Summary of Storm Contingency Funds
Narragansett Blackston e Newport Combined
Electric Valley Electric Entity
-------- ------ -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
1 Balance in Storm Funds as of
2 December 31, 1998 $4,476,595 1/ $209,261 2/ $1,020,879 3/ $5,706,735
3
4 Annual Storm Fund Contributions
5 Collected through Revenue $641,000 4/ $160,000 5/ $240,000 6/ $1,041,000
6
7 Annual Threshold Amount for
8 the Year 1999 $465,000 7/ $145,000 8/ $97,000 9/ $465,000
9
10 Deductible Amount per each
11 Storm Occurrence $300,000 10/ $94,000 10/ $56,000 10/ $300,000
</TABLE>
Notes:
1/ Narragansett Electric's 1998 FERC Form 1, Page 278.
2/ Blackstone Valley Electric's 1998 FERC Form 1, Page 278.
3/ Newport Electric's 1998 FERC Form 1, Page 278.
4/ RIPUC Order in Docket No. 1938.
5/ RIPUC Order in Docket No. 2016.
6/ RIPUC Order in Docket No. 2036.
7/ Narragansett Electric's Annual Storm Fund Report, Filed April 1, 1999.
8/ Blackstone Valley Electric's Annual Storm Fund Report, Filed April 1,
1999.
9/ Newport Electric's Annual Storm Fund Report, Filed April 1, 1999.
10/ RIPUC Order in Docket No. 2509.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit DMW-10
Exhibit DMW-10
Summary of Deferred FAS 106 Costs
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No._______
Exhibit DMW- 10
Page 1 of 1
The Narragansett Electric Company
Summary of Deferred FAS 106 Costs
Blackstone Newport Combined
Valley Electric Entity
<S> <C> <C> <C> <C>
1 Deferred FAS 106 Balance as of $581,291 l/ $686,365 2/ $1,267,656
2 December 31, 1998
3
4 Annual Recovery of Deferred FAS 106 $145,300 3/ $171,600 3/ $316,900
5 Costs Collected through Revenue
6
7 Anticipated Year Deferred FAS 106 will 2002 2002 2002
8 be Completed
Notes:
1/ Blackstone Valley Electric's 1998 FERC Form 1, Page 232.
2/ Newport Electric's 1998 FERC Form 1, Page 232.
3/ November, 1995 Compliance Filing in RIPUC Docket No. 2045.
</TABLE>
<PAGE>
The Narragansett Electric Company,
Blackstone Valley Electric Company,
and Newport Electric Corporation
Rate Plan Filing in Support of Merger
Volume 2
Testimony and Exhibits of:
James M. Molloy
James J. Bonner, Jr.
May, 1999
Submitted to:
Rhode Island Public Utilities Commission
RIPUC Docket _____
Submitted by:
Nees Logo
Eastern Utilities Associates Logo
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- -------------------------) R.I.P.U.C. No. __________
Narragansett Electric )
BVE/Newport Electric )
- -------------------------)
DIRECT TESTIMONY
OF
JAMES M. MOLLOY
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- -------------------------) R.I.P.U.C. No. __________
Narragansett Electric )
BVE/Newport Electric )
- -------------------------)
DIRECT TESTIMONY
OF
JAMES M. MOLLOY
Table of Contents
I. Introduction and Qualifications.......................................1
II. Purpose of Testimony..................................................2
III. Summary of Current Rates..............................................3
A. Narragansett......................................................3
B. Blackstone and Newport............................................5
IV. Proposed Rate Plan....................................................6
A. Overview..........................................................6
B. Distribution Rates...............................................10
C. Transmission Rates...............................................14
D. Transition Charges...............................................16
E. Standard Offer Rates.............................................18
F. Other Rate Issues................................................18
V. Revenue Effects......................................................19
A. Overall..........................................................19
B. Typical Bills....................................................19
VI. Tariffs..............................................................20
A. Terms and Conditions.............................................20
B. Tariffs..........................................................21
C. Adjustment Provisions............................................21
VIII. Conclusion...........................................................22
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 1 of 22
<S> <C> <C>
1 I. Introduction and Qualifications
2 Q. Please state your full name and business address.
3 A. James M. Molloy, 25 Research Drive, Westborough, Massachusetts 01582.
4
5 Q. Please state your position.
6 A. I am a Senior Rate Analyst for New England Power Service Company, performing rate
7 related services for the New England Electric System, including The Narragansett
8 Electric Company ("Narragansett" or "the Company").
9
10 Q. Will you describe your educational background and training?
11 A. In 1992, I graduated from Catholic University with a Bachelor of Arts degree in
12 Accounting. In 1994, I received a Masters in Business Administration with a
13 concentration in Finance from the William E. Simon Graduate School of Business
14 Administration at the University of Rochester.
15
16 Q. What is your professional background?
17 A. In 1995, I was hired by the New England Power Service Company as an Assistant Rate
18 Analyst in the Rate Department. In 1996, I was promoted to the position of Rate Analyst.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 2 of 22
1 In 1998, I was promoted to my current position of Senior Rate Analyst. In this position I
2 have been responsible for rate design analysis for various New England Electric System
3 companies. Specifically, I have conducted allocated distribution cost of service studies
4 and supported others in the development of cost allocation and rate design studies.
5 Further, I have provided analytical support for witnesses in various NEES retail company
6 regulatory proceedings on various rate design and cost allocation issues. In addition, I
7 have had primary responsibility for performing customer-specific rate impact analyses.
8 For the last two years, I have performed rate and cost allocation analytical work in the
9 unbundling of rates for the NEES retail companies in preparation of industry
10 restructuring.
11
12 Q. Have you testified in Rhode Island Public Utilities Commission proceedings?
13 A. Yes. I have testified at hearings during the past two years regarding the subject of
14 Narragansett's Standard Offer rates and other rate design matters.
15
16 II. Purpose of Testimony
17 Q. What is the purpose of your testimony?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 3 of 22
1 A. The purpose of my testimony is to present the proposed rate plan of Narragansett,
2 Blackstone Valley Electric Company ("Blackstone") and Newport Electric Company
3 ("Newport") (together, "the Companies"), in connection with the merger of NEES and
4 Eastern Utilities Associates ("EUA"). First, I will provide a brief summary of all three
5 companies' current rates. Second, I will describe the proposed rate plan, including
6 special rate mapping issues, which will serve as a means of consolidating the rates of
7 Narragansett, Blackstone and Newport. Next, I will present the anticipated effects of the
8 rate plan on revenues, both at the component level and at the total revenue level. This
9 presentation will include an analysis of typical customer bills. Finally, I will discuss
10 tariff changes made necessary by the proposed plan.
11
12 III. Summary of Current Rates
13 A. Narragansett
14 Q. Please provide a brief summary of Narragansett's current rates.
15 A. Narragansett's distribution rates were approved by the Commission in Docket No. 2290
16 effective December 15, 1996 and unbundled in Docket No. 2515. In accordance with the
17 Rhode Island Utility Restructuring Act ("URA") these rates remained frozen through
18 December, 1998 except for increases allowed through the Performance Based Rate
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 4 of 22
1 mechanism of the URA, as approved by the Commission in Docket No. 2500. Currently, the
2 average distribution charge is 2.967(cent)/kWh.
3
4 Narragansett's current average transmission rate of 0.455(cent)/kWh as approved by the
5 Commission in Docket No. 2841 collects both the base transmission rate of 0.387(cent)/kWh
6 and the transmission adjustment for calendar year 1999 of 0.068(cent)/kWh. Narragansett's
7 transmission rate recovers on a fully reconciling basis the costs it incurs to provide
8 transmission. The transmission component of Narragansett's rates is based on
9 transmission costs incurred from New England Power Company ("NEP"), the New
10 England Power Pool ("NEPOOL") and the Independent System Operator ("ISO").
11 Narragansett's base transmission rate is composed of a different rate for each rate class
12 which is based on the class demands coincident with NEP's 12 monthly transmission
13 peaks.
14
15 The Transition Charge is currently 1.15(cent)/kWh as approved in Docket No. 2771.
16 Narrangansett's transition charge recovers on a fully reconciling basis the Contract
17 Termination Charge ("CTC") billed to it by NEP.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 5 of 22
1 Narragansett's uniform Standard Offer charge of 3.5(cent)/kWh mirrors the 3.5(cent)/kWh charged
2 to the Company by its Standard Offer suppliers. The Standard Offer is scheduled to
3 increase to 3.8(cent)/kWh on January 1, 2000.
4
5 B. Blackstone and Newport
6 Q. Please provide a brief summary of Blackstone's and Newport's current rates.
7 A. Blackstone's and Newport's distribution rates were approved by the Commission in
8 Docket No. 2514 except for the increases allowed through the Performance Based Rate
9 mechanism of the URA which were approved in Docket No. 2498 for Blackstone and
10 Docket No. 2499 for Newport. Under the terms of the retail restructuring settlement in
11 consolidated Dockets 2514, 2651, and 2653 Blackstone's and Newport's distribution
12 rates are prohibited from any other increases through December 31, 2000. Currently,
13 Blackstone's average distribution charge is 3.002(cent)/kWh while Newport's average
14 distribution charge is 4.187(cent)/kWh. Finally, in Docket No. 2888 Blackstone and Newport
15 modified the distribution rates of certain rate classes as a means to hold customers
16 harmless from the implementation of a uniform, cents per kWh Standard Offer price.
17
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 6 of 22
1 Both Blackstone and Newport have a current average transmission rate of 0.267(cent)/kWh.
2 This rate collects the current annual cost of transmission for the calendar year 1999 for
3 each company. The transmission rate of each company is the transmission rate of
4 Montaup Electric Company ("Montaup") approved by FERC which recovers actual
5 transmission costs that Montaup, NEPOOL and the ISO incur to provide transmission
6 service based on a historical test year. Montaup's transmission rate, as billed to
7 customers by Blackstone and Newport, is an uniform (cent)/kWh charge applicable to all
8 retail customers of Montaup's affiliated companies.
9
10 The transition charge is currently 2.040(cent)/kWh for Blackstone and 2.060(cent)/kWh for
11 Newport. This charge was approved in Docket No. 2888.
12
13 Blackstone's and Newport's uniform Standard Offer charge of 3.5(cent)/kWh mirrors the
14 3.5(cent)/kWh charged to them by their Standard Offer suppliers. This wholesale Standard
15 Offer is scheduled to increase to 3.8(cent)/kWh on January 1, 2000.
16
17 IV. Proposed Rate Plan
18 A. Overview
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 7 of 22
1 Q. Before explaining the rate plan, are there any terms that you will be using that would be
2 helpful to define?
3 A. Yes. I believe it would be helpful to provide a definition of certain terms that I will use in
4 describing the rates. Specifically, when I refer to "distribution rates" or "distribution
5 component", I am referring to the component of rates relating to distribution that excludes
6 Transmission, Transition, Conservation and Load Management, and Standard Offer
7 charges. In contrast, when I refer to "delivery rates", I am referring to all rates,
8 excluding only Standard Offer service. Finally, when I refer to "rates" generically, I
9 intend to include all rates, including Standard Offer service.
10
11
12 Q. Please provide a general description of the Companies' proposed rate plan.
13 A. An overview of the rate plan is provided in the testimony of Mr. Jesanis. In summary,
14 the rate plan will become effective 120 days from the closing of the EUA-NEES merger
15 or April 1, 2000, whichever occurs later ("Rate Consolidation Date"). As described by
16 Mr. Jesanis, the plan creates immediate rate reductions for customers of Blackstone and
17 Newport, without increasing the delivery rates of Narragansett customers. After an
18 adjustment to the distribution rate is made on January 1, 2001, the distribution component
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 8 of 22
1 of all customers' bills will be frozen in two phases. The result would be a distribution
2 rate freeze through the year 2004. Mr. Jesanis describes the distribution rate freeze
3 proposal in greater detail, including exceptions for certain exogenous factors, as well as
4 the inflation protection provision that could only be triggered during the last two years of
5 the plan.
6
7 The plan would be implemented by placing all customers on Narragansett's rates with a
8 distribution surcharge to customers formerly served by Newport and a transition
9 surcharge to customers formerly served by Newport and BVE. However, there are three
10 exceptions to this general proposal. First, the companies are proposing special treatment
11 for the Newport C-1 rate as described below. The second exception allows an additional
12 credit to the low income customers of Blackstone and Newport during 2000 to ensure that
13 they are held harmless from the consolidation of rates during this period. A third
14 exception has been made for streetlighting customers of Blackstone and Newport who
15 would otherwise see significant increases under this proposal. Under the plan, all
16 customers of Blackstone and Newport would be moved onto the distribution rates of
17 Narragansett effective for bills rendered on the Rate Consolidation Date. However,
18 customers of Newport will be assessed a distribution surcharge as described below.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 9 of 22
1 In the case of the Navy, Newport has a special rate class C-1. The Companies would
2 retain the C-1 rate, but reduce it by 14% which is equal to the average distribution rate
3 decrease for all other Newport customers as a result of the merger. Instead of having the
4 rate function as an amendment to the antiquated 1961 contract entered into between
5 Newport and the Navy, the Company proposes a new tariff that embodies the old C-1 rate
6 reflecting the further 14% discount, with appropriate changes to the terms and conditions
7 in the tariff. The new tariff is designated as the "69kV Rate (N-01)".
8
9 Q. What impact would these proposed changes have on the customers of Narragansett,
10 Blackstone and Newport?
11 A. As shown in Exhibit JMM-1 the rate consolidation plan would reduce Blackstone's and
12 Newport's rates in 2000 by approximately $2.1 million and $3.4 million, respectively. An
13 exhibit summarizing the companies projected average rates or "rate paths" for the
14 years of the rate plan are included as Exhibit JMM-2. As shown in this exhibit, average
15 delivery rates for each of the Companies decline over the rate plan period.
16
17 Q. How would the customers of Blackstone and Newport be transferred to Narragansett's
18 rates?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 10 of 22
1 A. Rate classes of Blackstone and Newport are proposed to be mapped to Narragansett's rate
2 classes as illustrated in Exhibit JMM-3. This proposed rate mapping is determined by
3 referring to the availability provisions of Blackstone and Newport retail delivery service
4 tariffs and matching each tariff to a corresponding Narragansett retail delivery service
5 tariff. Customer usage within several Blackstone and Newport general service rate
6 classes maps to more than one Narragansett rate class because the availability provisions
7 of the Blackstone and Newport tariffs encompass a wider range of customer usage levels
8 than the Narragansett tariffs. As part of the mapping process, the billing determinants
9 under some Blackstone and Newport rate classes have been broken down into
10 subcategories in order to assign them to the correct Narragansett rate classes. The
11 testimony of Mr. Bonner supports in more detail the rate mapping process and the billing
12 determinants that the Companies are using to determine the effect on revenue.
13
14 B. Distribution Rates
15 Q. What is the proposed plan for the distribution rates of Blackstone, Newport and
16 Narragansett?
17 A. As briefly described earlier in my testimony, the Company is proposing to maintain
18 Narragansett's customers on their current distribution rates and to move Blackstone's
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 11 of 22
1 customers onto Narragansett distribution rates. In addition the Companies are proposing
2 to reduce the distribution rates of Newport's customers by half the distance to
3 Narragansett's distribution rates, with the exception of the Navy. The Navy's rate C-1
4 would be reduced by the average percentage decrease in the distribution rate of all the
5 other Newport customers. All Newport customer except for the C-1 class would be
6 moved onto Narragansett distribution rates and assessed a uniform (cent)/kWh surcharge
7 designed to cut rates equal to 50% of the difference between Narragansett's distribution
8 rates and Newport's distribution rates, as shown in Exhibit JMM-4. For purposes of the
9 tariffs, we refer to this distribution surcharge in the Newport zone as the "Zonal
10 Distribution Factor".
11
12 Q. Please explain the treatment for low income and streetlight customers.
13 A. The Companies have designed a Low Income Equalization Credit to prevent the low
14 income rate classes in Blackstone and Newport from seeing rate increases due to the rate
15 plan. The credits apply to the first 300 kWh per month and equal the difference between
16 the R-2 billing units billed at Narragansett's rates as compared to Blackstone's and
17 Newport's rates divided by the initial 300 kWh block for the R-2 rate. The credits are
18 only necessary for the first year of the plan as reductions to transition charges for
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 12 of 22
1 Blackstone and Newport in 2001 will offset any distribution rate increase to the low
2 income rate classes.
3
4 The streetlight credit is designed to maintain the current distribution revenue from the
5 Blackstone's and Newport's streetlighting rates. The credit equals the difference between
6 the streetlight billing units billed at Narragansett rates as compared to
7 Blackstone/Newport's rates divided by total streetlight kWh. The total amount of the
8 annual credit is approximately $840,000. The Company proposes to apply its annual
9 streetlight refund ($827,494 for the past year) to fund the cost of the annual credit.
10
11 Q. How does the Company plan to implement the distribution rate plan?
12 A. As discussed above, Narragansett would implement its rates for customers of Blackstone
13 and Newport on a bills rendered basis for meter readings as of the Rate Consolidation
14 Date. Due to the complexity of prorating out Blackstone and Newport distribution rates
15 and prorating in Narragansett distribution rates, the Companies believe this "flash cut"
16 method would simplify bills and avoid any unnecessary customer confusion during the
17 transition.
18
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 13 of 22
1 Q. Are the Companies proposing any other distribution rate changes?
2 A. Yes. As discussed in Mr. Webster's testimony, Narragansett is proposing to modify its
3 depreciation rates to resolve certain issues related to cost of removal. The change to
4 depreciation rates results in an ongoing annual revenue requirement of $2.7 million and a
5 deficiency in deferred tax reserves of about $19.2 million. The Company is proposing to
6 increase distribution rates to collect on an ongoing basis $2.7 million beginning January
7 1, 2001. This would be done by increasing distribution energy charges by
8 $0.00039/kWh. The Company is also proposing to use refunds due to customers from any
9 CTC reconciliations to resolve the accumulated deferred tax deficiency, as described by
10 Mr. Jesanis and Mr. Webster.
11
12 Q. What is the estimated overall impact of the Companies' proposal on distribution rates?
13 A. As shown in Exhibit JMM-5, Blackstone's and Newport's average distribution rates
14 would be reduced by approximately $2.0 million and $3.4 million, respectively.
15 Narragansett's distribution rates would remain unchanged in the year 2000. In 2001, the
16 distribution component of all customers' rates would be increased by $.00039/kWh or
17 $2.7 million. However, this would not present an increase for Narragansett customers
18 because of the transmission rate decrease described below. Similarly, because
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 14 of 22
1 Blackstone's and Newport's customers will see a significant decrease in transition charges
2 in 2001, their rates will also decrease.
3
4 C. Transmission Rates
5 Q. What is the plan for transmission rates?
6 A. Beginning on the Rate Consolidation Date, the Company is proposing to move
7 Blackstone and Newport customers to the transmission rates of Narragansett. However,
8 in order to avoid an increase in transmission rates for Blackstone and Newport customers
9 in 2000, the Companies propose to maintain separate transmission adjustment factors in
10 2000 for the Narragansett, Blackstone and Newport zones to continue the present
11 allocation of transmission costs currently assigned to each company. However,
12 beginning in the year 2001, the Companies will complete the transmission rate
13 consolidation by creating one adjustment factor for all customers to recover the
14 consolidated transmission costs incurred above and beyond the revenue collected from
15 the base transmission rates.
16
17 Q. What is the impact of this plan on the transmission revenues of each Company?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 15 of 22
1 A. On the Rate Consolidation Date, the overall transmission revenue for each company
2 remains relatively unchanged, but as Exhibit JMM-6 demonstrates, revenues shift
3 between rate classes for Blackstone and Newport. This shift, however, provides a better
4 matching between ultimate cost occurrence and revenue from each of the rate classes.
5 Although the consolidation of transmission rates in 2001 represents an increase to
6 Blackstone's and Newport's customers, any increase to those customers is more than
7 offset by decreases in transition charges. The consolidation of transmission rates in 2001
8 represents a decrease to Narragansett customers which is partially offset by the
9 distribution rate increase mentioned earlier in my testimony.
10
11 Q. How do the Companies plan to implement the transmission rate plan?
12 A. The transmission adjustment factors that would become effective on the Rate
13 Consolidation Date are illustrated in Exhibit JMM-7. In this exhibit, forecasted transmission
14 expenses of each of the three Companies are compared to the revenues from their
15 respective billing determinants billed at Narragansett's base transmission rates and the
16 difference is divided by total kWh sales of each company to produce the Transmission
17 Adjustment Factor. Exhibit JMM-7 provides only a demonstration of the calculations.
18 Actual transmission adjustment factors would be implemented based on a subsequent
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 16 of 22
1 filing by the companies in late 1999 which would incorporate the most current forecast of
2 transmission expenses. The consolidated transmission factors that would be in effect in
3 2001 are estimated on Page 7 in Exhibit JMM-7 for purposes of rate comparison.
4
5 In addition, it should be noted that Blackstone and Newport do not currently have a
6 transmission adjustment provision. Rather, both companies merely "pass-through" a
7 transmission factor charged to them by Montaup. Under the rate plan proposal, all
8 customers would fall under a transmission adjustment provision effective on the Rate
9 Consolidation Date. Thus, under the rate plan, the transmission component of the
10 Companies' rates would be set and reconciled on an annual basis.
11
12 D. Transition Charges
13 Q. What is the plan for transition charges?
14 A. The Companies are proposing to set the transition charge to Narragansett's customers at
15 1.15(cent)/kWh. Thus, transition charges collected from Narragansett's customers that are
16 above the CTC level billed by NEP will be used to reduce the transition charges of
17 Newport's and Blackstone's customers. The ultimate aim will be to keep the "Base"
18 transition charge in effect for Narragansett's customers until the transition charges of all
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 17 of 22
1 three Companies come into parity with each other and transition charges can be
2 consolidated into a single rate for all three Companies.
3
4 Q. How do the Companies propose to implement the transition rate plan?
5 A. The Companies would bill all customers in all three zones the same base transition charge
6 equal to the proposed Narragansett transition charge of 1.15 cents per kWh. However,
7 customers in the Blackstone and Newport zones will be assessed a "Zonal Transition
8 Factor". Effective on the Rate Consolidation Date, the Zonal Transition Factor will be
9 equal to the difference between the transition charge in effect prior to the Rate
10 Consolidation Date and the base transition charge of 1.15 cent per kWh. Effective on
11 January 1, 2001, the Zonal Transition Factor will collect an amount equal to the
12 difference between:
13 (1) Total projected CTC expense, including Narragansett; and
14 (2) and total kWh sales including Narragansett times the new base transition charge
15 of 1.15(cent)/kWh.
16 An illustrative example of the Zonal Transition Factor calculations is shown in Exhibit
17 JMM-8.
18
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 18 of 22
1 E. Standard Offer Rates
2 Q. Is the Company proposing any change to the Standard Offer charge?
3 A. No. Because the uniform Standard Offer for customers in Blackstone and Newport
4 proposed in RIPUC Docket No. 2888 was approved, the Company would have no need to
5 alter the rate for Standard Offer Service because the rates among the companies would
6 already match.
7
8 Q. How does the Company propose to collect any Standard Offer over/under collection?
9 A. Because of the projected small dollar value of the Standard Offer adjustment, the
10 Company is proposing to consolidate the over/under balances of Narragansett, Blackstone
11 and Newport, and apply Narragansett's current Standard Offer Adjustment Provision to
12 all three zones.
13
14 F. Other Rate Issues
15 Q. Are there any other rate issues with respect to this rate plan?
16 A. Yes. The Company needs to consolidate other generic tariff provisions including Terms
17 and Conditions for both customers and nonregulated power producers, as well as the
18 adjustment provisions. Accordingly, Narragansett's terms and conditions and adjustment
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 19 of 22
1 provisions will be applied to BVE and Newport customers. The consolidation of these
2 tariff provisions is discussed later in my testimony.
3
4 V. Revenue Effects
5 A. Overall
6 Q. What is the estimated impact on Blackstone and Newport customers from the proposed
7 rate plan?
8 A. As illustrated in Exhibit JMM-1, the impact on the Rate Consolidation Date is a decrease
9 of approximately $2.1 million for Blackstone's customers, and a decrease of
10 approximately $3.4 million for Newport's customers as illustrated in Exhibit JMM-1. As
11 discussed in more detail by Mr. Jesanis, there are additional benefits to customers after
12 the Rate Consolidation Date.
13
14 B. Typical Bills
15 Q. Has the Company provided typical bills showing the effects of the proposed rate plan on
16 the Rate Consolidation Date?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 20 of 22
1 A. Yes, the Company has provided typical bills in Exhibit JMM-9 and Exhibit JMM-10 for
2 Blackstone and Newport, respectively. The Company has not provided typical bills for
3 current Narragansett customers since their bills will not change.
4
5 Q. What is the impact on a typical 500 kWh residential customer in all service territories?
6 A. On the Rate Consolidation Date, there is no change for a current Narragansett customer, a
7 $1.35 decrease monthly or 2.3% for a current Blackstone customer and a $2.07 decrease
8 monthly or 3.3% for a current Newport customer.
9
10 VI. Tariffs
11 A. Terms and Conditions
12 Q. Under which set of Terms and Conditions will customers be served?
13 A. Blackstone and Newport customers will be moved onto the Terms and Conditions of
14 Narragansett effective on the Rate Consolidation Date.
15
16 Q. Is the Company proposing any changes to the Terms and Conditions?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 21 of 22
1 A. Yes, to facilitate the assessment of the zonal factors for transition and distribution rates,
2 the Company is proposing to add an additional definition to the Terms and Conditions.
3 The addition is shown in Exhibit JMM-11.
4
5 B. Tariffs
6 Q. Has the Company prepared updated tariff cover sheets reflecting the proposed changes.
7 A. Yes, the proposed cover sheets are included as Exhibit JMM-12.
8
9 Q. What happens if the two operating companies of EUA have not been formally merged
10 into Narragansett and retain separate legal existences because of the delay described in
11 Mr. Jesanis' testimony?
12 A. This does not substantively affect the Companies' proposal. My exhibits contemplate the
13 merger occurring. However, if there is a delay, the Companies nevertheless propose that
14 one set of tariffs apply to all three Companies. In such case, the Companies would make
15 a compliance filing to place tariffs containing the names of all three Companies on file
16 with the Commission until the merger of the three operating companies is consummated.
17
18 C. Adjustment Provisions
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Testimony of J.M. Molloy
Page 22 of 22
1 Q. Under which set of adjustment provisions will customers be served?
2 A. Similar to the proposal relating to the tariffs, Blackstone and Newport customers will be
3 moved onto the adjustment provisions of Narragansett effective on the Rate
4 Consolidation Date. To the extent that there are any outstanding balances in any of the
5 BVE or Newport adjustment provisions that are in effect prior to the Rate Consolidation
6 Date, the Companies propose to roll those balances into the appropriate corresponding
7 adjustment provisions of the consolidated company.
8
9 Q. Is the Company proposing any changes to the provisions?
10 A. Yes. The Company is updating the language of the Non-Bypassable Transition Charge
11 Adjustment Provision and the Transmission Service Cost Adjustment Provision to reflect
12 the merger of the retail companies. A red-lined copy of the proposed provisions are
13 included as Exhibit JMM-13. All the other provisions will remain unchanged.
14
15 VIII. Conclusion
16 Q. Does this complete your testimony?
17 A. Yes.
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
INDEX OF EXHIBITS
JMM-1 Impact on Total Revenue
JMM-2 Rate Mapping
JMM-3 Rate Paths
JMM-4 Calculation of Newport Zonal Distribution Factor
JMM-5 Impact on Distribution Revenue
JMM-6 Impact on Transmission Revenue
JMM-7 Merged Transmission Adjustment Factors
JMM-8 Post Merger Transition Charges
JMM-9 Blackstone Valley Typical Bills
JMM-10 Newport Typical Bills
JMM-11 Terms and Conditions
JMM-12 Tariffs
JMM-13 Adjustment Provision
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-1
Exhibit JMM-1
Impact on Total Revenue
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ____
Exhibit JMM - 1
Page 1 of 3
<TABLE>
<CAPTION>
The Narragansett Electric Company
Total Revenue Shift from Merger to BVE Customers
=================================================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
=================================================================================================================
<S> <C> <C> <C> <C> <C>
R-1 362,568,042 $40,722,906 $39,704,361 ($1,018,544) -2.50%
R-2 10,464,104 $892,790 $885,564 ($7,225) -0.81%
R-3 9,162,722 $931,422 $974,130 $42,708 4.59%
R-4 4,487,447 $437,683 $425,523 ($12,161) -2.78%
W-1 3,602,371 $324,151 $372,483 $48,333 14.91%
H-1 3,639,022 $350,069 $336,483 ($13,587) -3.88%
H-2 2,290,392 $233,468 $242,340 $8,872 3.80%
G-1 43,670,643 $5,088,566 $5,146,385 $57,819 1.14%
G-2 313,855,524 $29,719,748 $29,660,495 ($59,253) -0.20%
T-2 45,916,407 $4,263,798 $3,874,164 ($389,634) -9.14%
T-4 78,036,479 $6,721,747 $6,470,366 ($251,381) -3.74%
G-5 23,108,580 $2,025,532 $1,986,230 ($39,302) -1.94%
T-5 8,474,950 $734,846 $679,699 ($55,146) -7.50%
T-6 369,857,394 $29,787,298 $29,380,332 ($406,966) -1.37%
A-6 6,085,455 $553,736 $531,237 ($22,499) -4.06%
S-1 14,647,035 $2,399,359 $2,402,553 $3,194 0.13%
------------- ----------- ----------- ---------- -----
Total Company 1,299,866,567 $125,187,11 $123,072,346 ($2,114,773) -1.69%
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ____
Exhibit JMM - 1
Page 2 of 3
<TABLE>
<CAPTION>
The Narragansett Electric Company
Total Revenue Shift from Merger to Narragansett Customers
=================================================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
=================================================================================================================
<S> <C> <C> <C> <C> <C>
A-16 1,475,595,371 $146,179,613 $146,179,613 $0 0.00%
A-18 299,522,556 $27,232,677 $27,232,677 $0 0.00%
A-32 33,569,784 $2,847,742 $2,847,742 $0 0.00%
A-60 45,194,386 $3,572,777 $3,572,777 $0 0.00%
E-30 1,519,157 $109,772 $109,772 $0 0.00%
E-40 12,436,324 $872,223 $872,223 $0 0.00%
C-06 319,448,478 $32,857,618 $32,857,618 $0 0.00%
G-02 857,825,162 $71,725,832 $71,725,832 $0 0.00%
G-32 1,497,395,176 $108,041,029 $108,041,029 $0 0.00%
G-62 360,114,300 $23,033,841 $23,033,841 $0 0.00%
R-02 4,803,789 $308,547 $308,547 $0 0.00%
S-10 49,529,091 $9,620,076 $9,620,076 $0 0.00%
T-06 21,835,478 $1,763,248 $1,763,248 $0 0.00%
V-02 7,686,406 $718,448 $718,448 $0 0.00%
------------- ------------ ------------ -- -----
Total Company 4,986,475,458 $428,883,443 $428,883,443 $0 0.00%
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. ____
Exhibit JMM - 1
Page 3 of 3
<TABLE>
<CAPTION>
The Narragansett Electric Company
Total Revenue Shift from Merger to Newport Customers
=================================================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
=================================================================================================================
<S> <C> <C> <C> <C> <C>
R-1 167,201,036 $19,896,925 $19,237,969 ($658,956) -3.31%
R-2 1,764,819 $164,092 $162,833 ($1,259) -0.77%
R-4 7,100,991 $808,011 $718,668 ($89,343) -11.06%
W-1 13,383,268 $1,422,017 $1,474,430 $52,412 3.69%
H-1 4,908,488 $523,570 $465,875 ($57,695) -11.02%
H-2 5,723,950 $665,920 $627,794 ($38,126) -5.73%
G-1 42,449,011 $5,464,085 $5,082,244 ($381,841) -6.99%
G-2 105,080,586 $11,113,180 $10,298,594 ($814,586) -7.33%
T-2 14,361,960 $1,497,070 $1,277,833 ($219,237) -14.64%
T-4 18,430,440 $1,953,393 $1,659,268 ($294,126) -15.06%
G-5 15,075,589 $1,516,935 $1,361,051 ($155,884) -10.28%
T-5 2,964,000 $293,737 $251,626 ($42,112) -14.34%
T-6 24,547,599 $2,453,903 $2,137,672 ($316,231) -12.89%
C-1 114,919,292 $10,247,646 $9,879,737 ($367,909) -3.59%
S-1 5,614,981 $852,977 $853,283 $306 0.04%
----------- ----------- ----------- ---------- -------
Total Company 543,526,010 $58,873,463 $55,488,877 ($3,384,586) -5.75%
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-2
Exhibit JMM-2
Rate Paths
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 2
Page 1 of 4
SUMMARY TABLE
Consolidated Average (cent)/kWh
Summary of Average Rates
2000 2000 2001 2002 2003 2004
------------------------------------------------------------------------------------
January 1 April 1 January 1 January 1 January 1 January 1
--------- ------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
(1) Distribution 3.071 2.993 2.993 2.993 2.993 2.993
(1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039
(2) DSM 0.230 0.230 0.230 0.230 0.230 0.230
----- ----- ----- ----- ------ ------
(3) Total Distribution 3.301 3.223 3.262 3.262 3.262 3.262
(4) Transmission 0.415 0.415 0.415 0.415 0.415 0.415
(5) Transition 1.467 1.467 1.314 1.341 1.230 1.190
----- ----- ----- ----- ------ ------
(6) Total Delivery 5.183 5.105 4.991 5.018 4.907 4.867
(7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100
----- ----- ----- ----- ------ ------
(8) Total Average Price 8.983 8.905 8.791 9.218 9.607 9.967
(9) Total Average Price Adj for GET 9.358 9.276 9.158 9.602 10.007 10.382
(10) Percent Increase/(Decrease) -0.87% -1.28% 4.86% 4.22% 3.75%
Notes:
(1) Weighted average of Page 2, Line (1), Page 3, Line (1), and Page 4, Line (1) (6) = Line (3) + Line (4) + Line (5)
(1a) Cost of Removal impact on rates 2001 through 2004 (7) per Settlement Agreements
(2) Assumed at current level through 2004 (8) = Line (6) + Line (7)
(3) = Line (1) + Line (1a) + Line (2) (9) Line (8)/.96
(4) Weighted average of Page 2, Line (4), Page 3, Line (4), and Page 4, Line (4) (10) = (Line (9) - Line (9) prior column)/
(5) Weighted average of Page 2, Line (5), Page 3, Line (5), and Page 4, Line (5) Line (9) prior column
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 2
Page 2 of 4
BLACKSTONE VALLEY
Consolidated Average (cent)/kWh
Summary of Average Rates
2000 2000 2001 2002 2003 2004
------------------------------------------------------------------------------------
January 1 April 1 January 1 January 1 January 1 January 1
--------- ------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
(1) Distribution 3.003 2.852 2.852 2.852 2.852 2.852
(1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039
(2) DSM 0.230 0.230 0.230 0.230 0.230 0.230
----- ----- ----- ----- ------ ------
(3) Total Distribution 3.233 3.082 3.121 3.121 3.121 3.121
(4) Transmission 0.278 0.278 0.429 0.429 0.429 0.429
(5) Transition 2.320 2.320 1.759 1.859 1.446 1.298
----- ----- ----- ----- ------ ------
(6) Total Delivery 5.831 5.680 5.309 5.409 4.996 4.848
(7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100
----- ----- ----- ----- ------ ------
(8) Total Average Price 9.631 9.480 9.109 9.609 9.696 9.948
(9) Total Average Price Adj for GET 10.032 9.875 9.489 10.009 10.100 10.363
(10) Percent Increase/(Decrease) -1.57% -3.91% 5.49% 0.91% 2.60%
Notes:
(1) Base Distribution Charges - Frozen from 2001 through 2004 (6) = Line (3) + Line (4) + Line (5)
(1a) Cost of Removal impact on rates 2001 through 2004 (7) per Settlement Agreements
(2) Assumed at current level through 2004 (8) = Line (6) + Line (7)
(3) = Line (1) + Line (1a) + Line (2) (9) Line (8)/.96
(4) Projected 2000 BVE alone; Projected 2001-2004 Consolidated Companies (10) = (Line (9) - Line (9) prior column)/
(5) Projected 2000 BVE alone; Projected 2001-2004 Consolidated Companies Line (9) prior column
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 2
Page 3 of 4
NARRAGANSETT ELECTRIC
Consolidated Average (cent)/kWh
Summary of Average Rates
2000 2000 2001 2002 2003 2004
------------------------------------------------------------------------------------
January 1 April 1 January 1 January 1 January 1 January 1
--------- ------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
(1) Distribution 2.967 2.967 2.967 2.967 2.967 2.967
(1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039
(2) DSM 0.230 0.230 0.230 0.230 0.230 0.230
----- ----- ----- ----- ----- -----
(3) Total Distribution 3.197 3.197 3.236 3.236 3.236 3.236
(4) Transmission 0.466 0.466 .0409 0.409 0.409 0.409
(5) Transition 1.150 1.150 1.150 1.150 1.150 1.150
----- ----- ----- ----- ----- -----
(6) Total Delivery 4.813 4.813 4.795 4.795 4.795 4.795
(7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100
----- ----- ----- ----- ----- -----
(8) Total Average Price 8.613 8.613 8.595 8.995 9.495 9.895
(9) Total Average Price Adj for GET 8.972 8.972 8.953 9.370 9.891 10.307
(10) Percent Increase/(Decrease) 0.00% -0.21% 4.65% 5.56% 4.21%
Notes:
(1) Base Distribution Charges - Frozen from 2001 through 2004 (5) Projected 2000 Narragansett alone;
(1a) Cost of Removal impact on rates 2001 through 2004 Projected 2001-2004 Consolidated
(2) Assumed at current level through 2004 Companies
(3) = Line (1) + Line (1a) + Line (2) (6) = Line (3) + Line (4) + Line (5)
(4) Projected 2000 Narragansett alone; Projected 2001-2004 Consolidated (7) per Settlement Agreements
Companies (8) = Line (6) + Line (7)
(9) Line (8)/.96
(10) = (Line (9) - Line (9) prior column)/
Line (9) prior column
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 2
Page 4 of 4
NEWPORT ELECTRIC
Consolidated Average (cent)/kWh
Summary of Average Rates
2000 2000 2001 2002 2003 2004
------------------------------------------------------------------------------------
January 1 April 1 January 1 January 1 January 1 January 1
--------- ------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
(1) Distribution 4.189 3.568 3.568 3.568 3.568 3.568
(1a) Cost of Removal Adj. 0.039 0.039 0.039 0.039
(2) DSM 0.230 0.230 0.230 0.230 0.230 0.230
------ ------ ------ ------ ------ ------
(3) Total Distribution 4.419 3.798 3.837 3.837 3.837 3.837
(4) Transmission 0.273 0.273 0.431 0.431 0.431 0.431
(5) Transition 2.340 2.340 1.759 1.859 1.446 1.298
------ ------ ------ ------ ------ ------
(6) Total Delivery 7.032 6.411 6.027 6.127 5.714 5.566
(7) Standard Offer 3.800 3.800 3.800 4.200 4.700 5.100
------ ------ ------ ------ ------ ------
(8) Total Average Price 10.832 10.211 9.827 10.327 10.414 10.666
(9) Total Average Price Adj for GET 11.283 10.636 10.236 10.757 10.848 11.110
(10) Percent Increase/(Decrease) -5.73% -3.76% 5.09% 0.84% 2.42%
Notes:
(1) Base Distribution Charges - Frozen from 2001 through 2004 (6) = Line (3) + Line (4) + Line (5)
(1a) Cost of Removal impact on rates 2001 through 2004 (7) per Settlement Agreements
(2) Assumed at current level through 2004 (8) = Line (6) + Line (7)
(3) = Line (1) + Line (1a) + Line (2) (9) Line (8)/.96
(4) Projected 2000 Newport alone; Projected 2001-2004 Consolidated Companies (10) = (Line (9) - Line (9) prior column)/
(5) Projected 2000 Newport alone; Projected 2001-2004 Consolidated Companies Line (9) prior column
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-3
Exhibit JMM-3
Rate Mapping
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 3
Page 1 of 2
<TABLE>
<CAPTION>
Narragansett Electric Company
Blackstone Valley Electric Company
Summary of Rate Mapping
- ----------------------------------------------------------------------------------------------------
Blackstone Narragansett
Rate Description Rate Description
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
R-1 Residential Service A-16 Basic Residential
- ----------------------------------------------------------------------------------------------------
R-2 Residential Low Income Service A-60 Low Income
- ----------------------------------------------------------------------------------------------------
R-3 Residential Space Heating Service A-16 Basic Residential
- ----------------------------------------------------------------------------------------------------
R-4 Residential Time of Use Service A-32 Residential Time of Use
- ----------------------------------------------------------------------------------------------------
G-1 Small Secondary Voltage Service C-06 Small C&I
- ----------------------------------------------------------------------------------------------------
C-06 Small C&I
G-2 Medium Secondary Voltage Service G-02 General C&I
(10<kw<500, annual kWh>36,000)
G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
G-02 General C&I
G-5 Medium Primary Voltage Service
(100<kw<500) G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
G-02 General C&I
T-2 Medium TOU Secondary Voltage Service
(10<kw<500, annual kWh>36,000) G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
T-4 Large Secondary Voltage Service G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
G-02 General C&I
T-5 Medium TOU Secondary Voltage Service
(10<kw<500, annual kWh>36,000) G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
G-32 200 kW Demand
T-6 Medium TOU Secondary Voltage Service
(10<kw<500, annual kWh>36,000) G-62 3,000 kW Demand
- ----------------------------------------------------------------------------------------------------
C-06 Small C&I
H-1 Space Heating Service G-02 General C&I
(non-industrial)
G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
C-06 Small C&I
H-2 Space Heating Service G-02 General C&I
(non-industrial)
G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
A-16 Basic Residential
W-1 Controlled Water Heating Service
(all customer types) C-06 Small C&I
- ----------------------------------------------------------------------------------------------------
S-1 Lighting Service S-14 General Streetlighting
(company owned)
- ----------------------------------------------------------------------------------------------------
A-6 Auxiliary Service B-32 200 kW Back-Up
- ----------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 3
Page 2 of 2
<TABLE>
<CAPTION>
Narragansett Electric Company
Newport Electric Corporation
Summary of Rate Mapping
- ----------------------------------------------------------------------------------------------------
Newport Narragansett
Rate Description Rate Description
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
R-1 Residential Service A-16 Basic Residential
- ----------------------------------------------------------------------------------------------------
R-2 Residential Low Income Service A-60 Low Income
- ----------------------------------------------------------------------------------------------------
R-4 Residential Time of Use Service A-32 Residential Time-of-Use
- ----------------------------------------------------------------------------------------------------
G-1 Small Secondary Voltage Service C-06 Small C&I
- ----------------------------------------------------------------------------------------------------
C-06 Small C&I
G-2 Medium Secondary Voltage Service G-02 General C&I
(10<kw<500, annual kWh>36,000)
G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
G-02 General C&I
G-5 Medium Primary Voltage Service
(100<kw<500) G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
G-02 General C&I
T-2 Medium TOU Secondary Voltage Service
(10<kw<500, annual kWh>36,000) G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
T-4 Large Secondary Voltage Service G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
T-5 Medium TOU Secondary Voltage Service G-32 200 kW Demand
(10<kw<500, annual kWh>36,000)
- ----------------------------------------------------------------------------------------------------
T-6 Medium TOU Secondary Voltage Service G-32 200 kW Demand
(10<kw<500, annual kWh>36,000)
G-62 3,000 kW Demand
- ----------------------------------------------------------------------------------------------------
C-06 Small C&I
H-1 Space Heating Service G-02 General C&I
(non-industrial)
G-32 200 kW Demand
- ----------------------------------------------------------------------------------------------------
C-06 Small C&I
H-2 Space Heating Service
(non-industrial) G-02 General C&I
- ----------------------------------------------------------------------------------------------------
A-16 Basic Resident
W-1 Controlled Water Heating Service C-06 Small C&I
(all customer types)
G-02 General C&I
- ----------------------------------------------------------------------------------------------------
S-1 Lighting Service S-14 General Streetlighting
(company owned)
- ----------------------------------------------------------------------------------------------------
C-1 Transmission Voltage General Service N-01 69 KV Rate
- ----------------------------------------------------------------------------------------------------
</TABLE>
2
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-4
Exhibit JMM-4
Calculation of Newport Zonal Distribution Factor
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 4
Page 1 of 1
The Narragansett Electric Company
Calculation of Newport Zonal Distribution Factor
=====================================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
=====================================================================================================
<S> <C> <C> <C> <C> <C>
R-1 167,201,036 $8,789,761 $6,980,462 ($1,809,299) -20.58%
R-2 1,764,819 $46,855 $41,685 ($5,170) -11.03%
R-4 7,100,991 $336,292 $201,219 ($135,073) -40. 17%
W-1 13,383,268 $532,967 $493,017 ($39,950) -7.50%
H-1 4,908,488 $197,500 $109,028 ($88,471) -44.80%
H-2 5,723,950 $285,678 $201,946 ($83,733) -29.31%
G-1 42,449,011 $2,644,197 $1,927,858 ($716,339) -27.09%
G-2 105,080,586 $4,132,677 $2,663,385 ($1,469,292) -35.55%
T-2 14,361,960 $543,005 $246,665 ($296,340) -54.57%
T-4 18,430,440 $729,059 $315,676 ($413,383) -56.70%
G-5 15,075,589 $515,464 $270,179 ($245,285) -47.59%
T-5 2,964,000 $96,839 $41,850 ($54,989) -56.78%
T-6 24,547,599 $823,206 $386,545 ($436,661) -53.04%
C-1 0 $0 $0 $0 0.0%
S-1 5,614,981 $479,974 $611,896 $131,922 27.49%
--------- -------- -------- -------- ------
Total Company 428,606,718 $20,153,473 $14,491,409 ($5,662,063) -28.09%
50% of Savings $2,831,032 14.05%
Zonal Distribution Factor to Non C-1 Newport Customers $0.00661
Calculation of C-1 Rate
Pre-Merger Allocation Post Merger Adjustment Base
Rates Percentage Rates Factors Distribution
Distribution Charge
per kW $7.68 85.95% $6.60 $6.60
Distribution Charge
per kVAR $0.23 85.95% $0.20 $0.20
Distribution Charge
per kWh $0.00851 85.95% $0.00731 $0.00434 $0.00297
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-5
Exhibit JMM-5
Impact on Distribution Revenue
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 5
Page 1 of 3
The Narragansett Electric Company
Distribution Revenue Shift by Moving BVE Customers to Narragansett Rates
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
===================================================================================================================================
<S> <C> <C> <C> <C> <C>
R-1 362,568,042 $16,691,896 $15,568,207 ($1,123,689) -6.73%
R-2 10,464,104 $199,229 $199,223 ($5) -0.00%
R-3 9,162,722 $324,117 $364,168 $40,051 12.36%
R-4 4,487,447 $140,255 $128,768 ($11,488) -8.19%
W-1 3,602,371 $85,385 $132,640 $47,255 55.34%
H-1 3,639,022 $108,875 $91,618 ($17,257) -15.85%
H-2 2,290,392 $81,661 $85,917 $4,256 5.21%
G-1 43,670,643 $2,194,076 $2,195,560 $1,484 0.07%
G-2 313,855,524 $8,917,404 $8,661,946 ($255,458) -2.86%
T-2 45,916,407 $1,220,459 $855,627 ($364,831) -29.89%
T-4 78,036,479 $1,549,489 $1,328,989 ($220,500) -14.23%
G-5 23,108,580 $493,896 $446,164 ($47,732) -9.66%
T-5 8,474,950 $173,126 $129,562 ($43,564) -25.16%
T-6 369,857,394 $5,273,150 $5,336,703 $63,552 1.21%
A-6 6,085,455 $150,392 $115,434 ($34,958) -23.24%
S-1 14,647,035 $1,428,554 $1,428,459 ($95) -0.01%
Total Company 1,299,866,567 $39,031,963 $37,068,984 ($1,962,978) -5.03%
See Workpaper JMM - 1
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 5
Page 2 of 3
The Narragansett Electric Company
Distribution Revenue Shift from Merger to Narragansett Customers
===================================================================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
===================================================================================================================================
<S> <C> <C> <C> <C> <C>
A-16 1,475,595,371 $62,144,457 $62,144,457 $0 0.00%
A-18 299,522,556 $10,321,633 $10,321,633 $0 0.00%
A-32 33,569,784 $950,714 $950,714 $0 0.00%
A-60 45,194,386 $1,043,247 $1,043,247 $0 0.00%
E-30 1,519,157 $25,915 $25,915 $0 0.00%
E-40 12,436,324 $114,501 $114,501 $0 0.00%
C-06 319,448,478 $14,345,578 $14,345,578 $0 0.00%
G-02 857,825,162 $23,269,571 $23,269,571 $0 0.00%
G-32 1,497,395,176 $24,752,330 $24,752,330 $0 0.00%
G-62 360,114,300 $3,268,759 $3,268,759 $0 0.00%
R-02 4,803,789 $43,474 $43,474 $0 0.00%
S-10 49,529,091 $6,887,061 $6,887,061 $0 0.00%
T-06 21,835,478 $536,094 $536,094 $0 0.00%
V-02 7,686,406 $272,175 $272,175 $0 0.00%
Total Company 4,986,475,458 $147,975,509 $147,975,509 $0 0.00%
See Workpaper JMM - 2
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 5
Page 3 of 3
The Narragansett Electric Company
Distribution Revenue Shift by Moving Newport Customers to Narragansett Rates
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
===================================================================================================================================
<S> <C> <C> <C> <C> <C>
R-1 167,201,036 $8,789,761 $8,085,660 ($704,100) -8.01%
R-2 1,764,819 $46,855 $46,849 ($6) -0.01%
R-4 7,100,991 $336,292 $248,156 ($88,136) -26.21%
W-1 13,383,268 $532,967 $581,480 $48,513 9.10%
H-1 4,908,488 $197,500 $141,474 ($56,026) -28.37%
H-2 5,723,950 $285,678 $239,781 ($45,898) -16.07%
G-1 42,449,011 $2,644,197 $2,208,446 ($435,751) -16.48%
G-2 105,080,586 $4,132,677 $3,357,967 ($774,709) -18.75%
T-2 14,361,960 $543,005 $341,598 ($201,408) -37.09%
T-4 18,430,440 $729,059 $437,501 ($291,558) -39.99%
G-5 15,075,589 $515,464 $368,832 ($146,632) -28.45%
T-5 2,964,000 $96,839 $61,246 ($35,593) -36.75%
T-6 24,547,599 $823,206 $547,182 ($276,024) -33.53%
C-1 114,919,292 $2,613,557 $2,245,649 ($367,909) -14.08%
S-1 5,614,981 $479,974 $479,932 ($42) -0.01%
Total Company 543,526,010 $22,767,030 $19,391,754 ($3,375,276) -14.83%
See Workpaper JMM - 3
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-6
Exhibit JMM-6
Impact on Transmission Revenue
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 6
Page 1 of 3
THE NARRAGANSETT ELECTRIC COMPANY
TRANSMISSION REVENUE SHIFT BY MOVING BVE CUSTOMERS TO CONSOLIDATED TRANSMISSION RATES
===============================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
===============================================================================================
<S> <C> <C> <C> <C> <C>
R-1 362,568,042 $1,007,939 $1,113,084 $105,145 10.43%
R-2 10,464,104 $29,090 $21,870 ($7,220) -24.82%
R-3 9,162,722 $25,472 $28,130 $2,657 10.43%
R-4 4,487,447 $12,475 $11,802 ($673) -5.40%
W-1 3,602,371 $10,015 $11,093 $1,078 10.76%
H-1 3,639,022 $10,116 $13,786 $3,670 36.28%
H-2 2,290,392 $6,367 $10,983 $4,616 72.49%
G-1 43,670,643 $121,404 $177,740 $56,335 46.40%
G-2 313,855,524 $872,518 $1,068,723 $196,205 22.49%
T-2 45,916,407 $127,648 $102,845 ($24,802) -19.43%
T-4 78,036,479 $216,941 $186,061 ($30,881) -14.23%
G-5 23,108,580 $64,242 $81,984 $17,742 27.62%
T-5 8,474,950 $23,560 $15,393 ($8,167) -34.66%
T-6 369,857,394 $1,028,204 $706,737 ($321,466) -31.26%
A-6 6,085,455 $16,918 $31,829 $14,912 88.14%
S-1 14,647,035 $40,719 $19,542 ($21,177) -52.01%
---------- ------- ------- --------- -------
TOTAL COMPANY 1,299,866,567 $3,613,629 $3,601,602 ($12,027) -0.33%
<PAGE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 6
Page 2 of 3
THE NARRAGANSETT ELECTRIC COMPANY
TRANSMISSION REVENUE SHIFT FROM MERGER TO NARRAGANSETT CUSTOMERS
===============================================================================================
Percent
Pre-Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
===============================================================================================
<S> <C> <C> <C> <C> <C>
A-16 1,475,595,371 $7,599,316 $7,599,316 $0 0.00%
A-18 299,522,556 $1,395,775 $1,395,775 $0 0.00%
A-32 33,569,784 $158,114 $158,114 $0 0.00%
A-60 45,194,386 $188,461 $188,461 $0 0.00%
E-30 1,519,157 $5,165 $5,165 $0 0.00%
E-40 12,436,324 $27,360 $27,360 $0 0.00%
C-06 319,448,478 $1,964,608 $1,964,608 $0 0.00%
G-02 857,825,162 $4,020,918 $4,020,918 $0 0.00%
G-32 1,497,395,176 $6,327,079 $6,327,079 $0 0.00%
G-62 360,114,300 $1,256,287 $1,256,287 $0 0.00%
R-02 4,803,789 $16,237 $16,237 $0 0.00%
S-10 49,529,091 $167,408 $167,408 $0 0.00%
T-06 21,835,478 $96,076 $96,076 $0 0.00%
V-02 7,686,406 $48,117 $48,117 $0 0.00%
--------- ------- ------- -- -----
TOTAL COMPANY 4,986,475,458 $23,270,921 $23,270,921 $0 0.00%
<PAGE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JMM - 6
Page 3 of 3
THE NARRAGANSETT ELECTRIC COMPANY
TRANSMISSION REVENUE SHIFT BY MOVING CUSTOMERS TO CONSOLIDATED TRANSMISSION RATES
===============================================================================================
Percent
Pre Merger Post Merger Revenue Increase/
Units Revenues Revenues Shift (Decrease)
(1) (2) (3) (4) (5)
===============================================================================================
<S> <C> <C> <C> <C> <C>
R-1 167,201,036 $456,459 $501,603 $45,144 9.89%
R-2 1,764,819 $4,818 $3,565 ($1,253) -26.01%
R-4 7,100,991 $19,386 $18,179 ($1,207) -6.23%
W-1 13,383,268 $36,536 $40,435 $3,899 10.67%
H-1 4,908,488 $13,400 $11,731 ($1,669) -12.46%
H-2 5,723,950 $15,626 $23,398 $7,771 49.73%
G-1 42,449,011 $115,886 $169,796 $53,910 46.52%
G-2 105,080,586 $286,870 $246,993 ($39,877) -13.90%
T-2 14,361,960 $39,208 $21,379 ($17,829) -45.47%
T-4 18,430,440 $50,315 $47,748 ($2,568) -5.10%
G-5 15,075,589 $41,156 $37,979 ($3,177) -7.72%
T-5 2,964,000 $8,092 $2,767 ($5,324) -65.80%
T-6 24,547,599 $67,015 $36,700 ($30,315) -45.24%
C-1 114,919,292 $313,730 $313,730 $0 0.0%
S-1 5,614,981 $15,329 $7,073 ($8,256) -53.86%
--------- ------- ------ -------- -------
TOTAL COMPANY 543,526,010 $1,483,826 $1,483,075 ($751) -0.05%
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-7
Exhibit JMM-7
Merged Transmission Adjustment Factors
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit JMM-7
Page 1 of 7
The Narragansett Electric Company
Projected Year 2000 Narragansett Only Transmission Rate
Calculation of Narragansett's Projected Transmission Adjustment Factor
1 Projected Revenue on Present Rates $19,288,812
2 1998 kWh Sales less Discounted kWh 4,979,191,154
3 Average Revenue per kWh $0.00387
4 Forecasted Transmission Expenses $23,218,705
5 1998 kWh Sales less Discounted kWh 4,979,191,154
6 Average Expense per kWh $0.00466
7 Transmission Adjustment Factor per kWh $0.00079
1 Exhibit JMM - 7, Page 2 of 7
2 1998 Actual kWh Less Discounted kWh
3 Line (1) / Line (2)
4 Workpaper JMM - 4, Line (3) + Line (4)
5 Line 2
6 Line (4) / Line (5)
7 Line (6) - Line (3)
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit JMM-7
Page 2 of 7
The Narragansett Electric Company
Projected Year 2000 Narragansett Only Transmission Rate
Projected Transmission Revenue on Narragansett Base Rates
<S> <C> <C> <C> <C> <C> <C> <C>
Total A-16 A-18 A-32 A-60 E-30 C-06
Projected Billing Determinants
kW Demand
kW Demand in Excess of 10 kW
kWh Sales 1,475,595,371 299,522,556 33,569,784 45,194,386 1,519,157 319,448,478
Less: High Voltage Metering Units
Present Transmission Rate $0.00387 $0.00436 $0.00387 $0.00392 $0.00338 $0.00261 $0.00536
Projected Transmission Revenues
Demand Revenues $9,436,846 $0 $0 $0 $0 $0 $0
Energy Revenues $9,872,436 $6,433,596 $1,159,152 $131,594 $152,757 $3,965 $1,712,244
Less Discounts ($20,470) $-0 $-0 $-0 $-0 $-0 $-0
Total Projected Revenues $19,288,812 $6,433,596 $1,159,152 $131,594 $152,757 $3,965 $1,712,244
E-40 G-02 G-32 G-62 T-06 V-02 Streetlight
Projected Billing Determinants
kW Demand 4,100,824 631,081
kW Demand in Excess of 10 kW 2,393,998
kWh Sales 12,436,324 21,835,478 7,686,406 54,332,880
Less: High Voltage Metering Units 142 9,055 6,311
Present Transmission Rate $0.00141 $1.40 $1.27 $1.39 $0.00361 $0.00547 $0.00259
Projected Transmission Revenues
Demand Revenues $0 $3,351,597 $5,208,046 $877,203 $0 $0 $0
Energy Revenues $17,535 $0 $0 $0 $78,826 $42,045 $140,722
Less Discounts $-0 ($198) ($11,500) ($8,772) $-0 $-0 $-0
Total Projected Revenues $17,535 $3,351,399 $5,196,547 $868,431 $78,826 $42,045 $140,722
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit JMM-7
Page 3 of 7
The Narragansett Electric Company
Projected Year 2000 Blackstone Valley Only Transmission Rate
Calculation of Blackstone's Projected Transmission Adjustment Factor
1 Projected Revenue on Present Rates $5,273,670
2 1998 kWh Sales less Discounted kWh 1,296,176,588
3 Average Revenue per kWh $0.00407
4 Forecasted Transmission Expenses $3,600,024
5 1998 kWh Sales less Discounted kWh 1,296,176,588
6 Average Expense per kWh $0.00278
7 Transmission Adjustment Factor per kWh ($0.00129)
1 Exhibit JMM - 7, Page 4 of 7
2 1998 Actual kWh Less Discounted kWh
3 Line (1) / Line (2)
4 Workpaper JMM - 4, Line (5) + Line (6)
5 Line 2
6 Line (4) / Line (5)
7 Line (6) - Line (3)
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit JMM-7
Page 4 of 7
The Narragansett Electric Company
Projected Year 2000 Blackstone Valley Only Transmission Rate
Projected Blackstone Transmission Revenue on Narragansett Base Rates
<S> <C> <C> <C> <C> <C> <C> <C>
Total A-16 A-18 A-32 A-60 E-30 C-06
Projected Billing Determinants
kW Demand
kW Demand in Excess of 10 kW
kWh Sales 375,299,762 0 4,487,447 410,464,104 0 101,265,144
Less: High Voltage Metering Units
Present Transmission Rate $0.00407 $0.00436 $0.00387 $0.00392 $0.00338 $0.00261 $0.00536
Projected Transmission Revenues
Demand Revenues $3,016,389 $0 $0 $0 $0 $0 $0
Energy Revenues $2,270,981 $1,636,307 $0 $17,591 $35,369 $0 $542,781
Less Discounts ($13,701) $-0 $-0 $-0 $-0 $-0 $-0
Total Projected Revenues $5,273,670 $1,636,307 $0 $17,591 $35,369 $0 $542,781
E-40 G-02 G-32 G-62 T-06 V-02 Streetlight
Projected Billing Determinants
kW Demand 1,493,946 142,198
kW Demand in Excess of 10 kW 658,159
kWh Sales 0 0 0 15,032,320
Less: High Voltage Metering Units 274 8,930 1,422
Present Transmission Rate $0.00141 $1.40 $1.27 $1.39 $0.00361 $0.00547 $0.00259
Projected Transmission Revenues
Demand Revenues $0 $921,423 $1,897,311 $197,655 $0 $0 $0
Energy Revenues $0 $0 $0 $0 $0 $0 $38,934
Less Discounts $-0 ($383) ($11,341) ($1,977) $-0 $-0 $-0
Total Projected Revenues $0 $921,039 $1,885,970 $195,679 $0 $0 $38,934
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit JMM-7
Page 5 of 7
The Narragansett Electric Company
Projected Year 2000 Newport Only Transmission Rate
Calculation of Newport's Projected Transmission Adjustment Factor
1 Projected Revenue on Present Rates $2,221,874
2 1998 kWh Sales less Discounted kWh 543,235,202
3 Average Revenue per kWh $0.00409
4 Forecasted Transmission Expenses $1,483,023
5 1998 kWh Sales less Discounted kWh 543,235,202
6 Average Expense per kWh $0.00273
7 Transmission Adjustment Factor per kWh ($0.00136)
1 Exhibit JMM - 7, Page 6 of 7
2 1998 Actual kWh Less Discounted kWh
3 Line (1) / Line (2)
4 Workpaper JMM - 4, Line (7) + Line (8)
5 Line 2
6 Line (4) / Line (5)
7 Line (6) - Line (3)
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Exhibit JMM-7
Page 6 of 7
The Narragansett Electric Company
Projected Year 2000 Newport Only Transmission Rate
Projected Newport Transmission Revenue on Narragansett Base Rates
<S> <C> <C> <C> <C> <C> <C> <C>
Total A-16 A-18 A-32 A-60 C-01 C-06
Projected Billing Determinants
kW Demand
kW Demand in Excess of 10 kW
kWh Sales 180,263,882 0 7,100,991 1,764,819 114,919,292 54,074,092
Less: High Voltage Metering Units
Present Transmission Rate $0.00409 $0.00436 $0.00387 $0.00392 $0.00338 $0.00409 $0.00536
Projected Transmission Revenues
Demand Revenues $628,735 $0 $0 $0 $0 $0 $0
Energy Revenues $1,594,501 $785,951 $0 $27,836 $5,965 $470,020 $289,837
Less Discounts ($1,361) $-0 $-0 $-0 $-0 $-0 $-0
Total Projected Revenues $2,221,874 $785,951 $0 $27,836 $5,965 $470,020 $289,837
E-40 G-02 G-32 G-62 T-06 V-02 Streetlight
Projected Billing Determinants
kW Demand 177,940 36,233
kW Demand in Excess of 10 kW 251,705
kWh Sales 0 0 0 5,750,045
Less: High Voltage Metering Units 148 512 362
Present Transmission Rate $0.00141 $1.40 $1.27 $1.39 $0.00361 $0.00547 $0.00259
Projected Transmission Revenues
Demand Revenues $0 $352,387 $225,984 $50,364 $0 $0 $0
Energy Revenues $0 $0 $0 $0 $0 $0 $14,893
Less Discounts $-0 ($208) ($650) ($504) $-0 $-0 $-0
Total Projected Revenues $0 $352,179 $225,334 $49,860 $0 $0 $14,893
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. DocketNo. _____
Exhibit JMM-7
Page 7 of 7
The Narragansett Electric Company
Projected Consolidated Transmission Rate
Calculation of Projected Consolidated Transmission Adjustment Factor
1 Projected Revenue on Present Rates $26,784,356
2 1998 kWh Sales less Discounted kWh 6,818,602,945
3 Average Revenue per kWh $0.00393
4 Forecasted Transmission Expenses $28,301,752
5 1998 kWh Sales less Discounted kWh 6,818,602,945
6 Average Expense per kWh $0.00415
7 Transmission Adjustment Factor per kWh $0.00022
1 Page 1, Line (1) + Page 3, Line (1) + Page 5, Line (1)
2 Page 1, Line (2) + Page 3, Line (2) + Page 5, Line (2)
3 Line (1) / Line (2)
4 Page 1, Line (4) + Page 3, Line (4) + Page 5, Line (4)
5 Line 2
6 Line (4) / Line (5)
7 Line (6) - Line (3)
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-8
Exhibit JMM-8
Post Merger Transition Charges
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Exhibit JMM - 8
Page 1 of 2
The Narragansett Electric Company
Illustrative Calculation of Projected Zonal Transition Factors
as of the Rate Consolidation Date
Narragansett Blackstone Newport
<S> <C> <C> <C> <C>
1 Pre Merger Transition Charge $0.01150 $0.02320 $0.02340
2 Base Transition $0.01150 $0.01150 $0.01150
-------- -------- --------
3 Zonal Transition Factor $0.00000 $0.01170 $0.01190
1 Estimated Pre Merger Transition Charges in 2000
2 Minimum Line (1)
3 Line (1) - Line (2)
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No.
Exhibit JMM - 8
Page 2 of 2
The Narragansett Electric Company
Illustrative Calculation of Projected Zonal Transition Factors
Effective January 1, 2001
Narragansett Blackstone Newport Total
<S> <C> <C> <C> <C> <C>
1 Contract Termination Charge $0.0103 $0.0208 $0.02090
2 Estimated MWh Sales 5,000,000 1,300,000 550,000
3 Total CTC Expense $51,500,000 $27,040,000 $11,495,000 $90,035,000
4 Base Transition Charge $0.0115 $0.0115 $0.01150
5 Estimated MWh Sales 5,000,000 1,300,000 550,000
6 Base Transition Revenue $57,500,000 $14,950,000 $6,325,000 $78,775,000
7 Residual CTC Expense $11,260,000
8 Blackstone and Newport MWH Sales 1,850,000
9 Zonal Transition Factor $0.00609 $0.00609 $0.00609
10 Total Nonbypassable Transition Charges $0.0115 $0.01759 $0.01759
1 From CTC Filings
2 Estimated
3 Line (1)*Line (2)* 1000
4 Set at 1.15(cent)/kWh
5 Line (2)
6 Line (4)*Line (5)* 1000
7 Line (3) less Line (6)
8 Line (2) Blackstone plus Newport columns
9 Line (7)/(Line (8)* 1000)
10 Line (4) + Line (9)
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-9
Exhibit JMM-9
Blackstone Valley Typical Bills
<PAGE>
<TABLE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on R-1 Rate Customers Page 1 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
120 $16.33 $4.75 $11.58 $15.57 $4.75 $10.82 ($0.76) -4.7%
240 $29.43 $9.50 $19.93 $28.49 $9.50 $18.99 ($0.94) -3.2%
480 $55.64 $19.00 $36.64 $54.33 $19.00 $35.33 ($1.31) -2.4%
700 $79.67 $27.71 $51.96 $78.02 $27.71 $50.31 ($1.65) -2.1%
950 $106.97 $37.60 $69.37 $104.93 $37.60 $67.33 ($2.04) -1.9%
500 $57.83 $19.79 $38.04 $56.48 $19.79 $36.69 ($1.35) -2.3%
Blackstone Valley Rates: R-1 Narragansett Rates: A-16
Customer Charge $3.09 Customer Charge $2.54
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00436
Distribution Energy Char kWh x $0.03857 Distribution Energy Char kWh x $0.03246
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on R-3 Rate Customers Page 2 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
280 $31.69 $11.08 $20.61 $32.79 $11.08 $21.71 $1.10 3.5%
550 $59.34 $21.77 $37.57 $61.87 $21.77 $40.10 $2.53 4.3%
1,100 $115.64 $43.54 $72.10 $121.09 $43.54 $77.55 $5.45 4.7%
1,650 $171.95 $65.31 $106.64 $180.31 $65.31 $115.00 $8.36 4.9%
2,200 $228.25 $87.08 $141.17 $239.53 $87.08 $152.45 $11.28 4.9%
Blackstone Valley Rates: R-3 Narragansett Rates A-16
Customer Charge $2.91 Customer Charge $2.54
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00436
Distribution Energy Char kWh x $0.03200 Distribution Energy Char kWh x $0.03246
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
FAS 106 kWh x $0.00278 FAX 106 kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on W-1 Rate Customers Page 3 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
750 $67.16 $29.69 $37.47 $80.76 $29.69 $51.07 $13.60 20.3%
1,500 $132.94 $59.38 $73.56 $161.52 $59.38 $102.14 $28.58 21.5%
3,000 $264.50 $118.75 $145.75 $323.03 $118.75 $204.28 $58.53 22.1%
4,600 $404.83 $182.08 $222.75 $495.31 $182.08 $313.23 $90.48 22.4%
6,000 $527.63 $237.50 $290.13 $646.06 $237.50 $408.56 $118.43 22.4%
Blackstone Valley Rates: W-1 Narragansett Rates: A-16
Customer Charge $1.32 Customer Charge $0.00
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00436
Distribution Energy Char kWh x $0.01792 Distribution Energy Char kWh x $0.03246
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on R-4 Rate Customers Page 4 of 26
KWH SPLIT: -ON-PEAK 18%
-OFF-PEAK 82%
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2,000 $203.74 $79.17 $124.57 $198.88 $79.17 $119.71 ($4.86) -2.4%
2,500 $253.46 $98.96 $154.50 $246.84 $98.96 $147.88 ($6.62) -2.6%
3,000 $303.17 $118.75 $184.42 $294.80 $118.75 $176.05 ($8.37) -2.8%
4,000 $402.59 $158.33 $244.26 $390.73 $158.33 $232.40 ($11.86) -2.9%
5,000 $502.03 $197.92 $304.11 $486.66 $197.92 $288.74 ($15.37) -3.1%
Blackstone Valley Rates: R-4 Narragansett Rates: A-32
Customer Charge $4.69 Customer Charge $2.30
Meter Charge $0.00 Meter Charge $4.44
Transmission Energy Char kWh x $0.00000 Transmission Energy Charge kWh x $0.00392
Dist Peak Energy Charge kWh x $0.11500 Distribution Energy Charge kWh x $0.02162
Dist Off Peak Energy Cha kWh x $0.01033
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on R-4 Rate Customers Page 5 of 26
KWH SPLIT: -ON-PEAK 22%
-OFF-PEAK 78%
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
3,000 $316.25 $118.75 $197.50 $294.80 $118.75 $176.05 ($21.45) -6.8%
4,000 $420.04 $158.33 $261.71 $390.73 $158.33 $232.40 ($29.31) -7.0%
5,000 $523.83 $197.92 $325.91 $486.66 $197.92 $288.74 ($37.17) -7.1%
6,000 $627.62 $237.50 $390.12 $582.58 $237.50 $345.08 ($45.04) -7.2%
7,000 $731.40 $277.08 $454.32 $678.51 $277.08 $401.43 ($52.89) -7.2%
Blackstone Valley Rates: R-4 Narragansett Rates: A-32
Customer Charge $4.69 Customer Charge $2.30
Meter Charge $0.00 Meter Charge $4.44
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00392
Dist Peak Energy Charge kWh x $0.11500 Dist Peak Energy Charge kWh x $0.02162
Dist Off Peak Energy Cha kWh x $0.01033
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on R-2 Rate Customers Page 6 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
100 $9.18 $3.96 $5.22 $8.53 $3.96 $4.57 ($0.65) -7.1%
300 $23.34 $11.88 $11.46 $25.59 $11.88 $13.71 $2.25 9.6%
500 $44.37 $19.79 $24.58 $44.17 $19.79 $24.38 ($0.20) -0.5%
700 $65.41 $27.71 $37.70 $62.76 $27.71 $35.05 ($2.65) -4.1%
1,000 $96.97 $39.58 $57.39 $90.63 $39.58 $51.05 ($6.34) -6.5%
Blackstone Valley Rates: R-2 Narragansett Rates: A-60
Customer Charge $2.01 Customer Charge $0.00
Transmission Energy Charge kWh x $0.00000 Transmission Energy Char kWh x $0.00338
Dist Energy Charge first 300 kWh x $0.00170 Distribution Energy Char kWh x $0.02521
Dist Energy Charge excess 300 kWh x $0.03470 FAS 106 kWh x $0.00068
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
Credit First 300 kWh kWh x ($0.00733)
A-60 Rate Credit kWh x $0.00000 A-60 Rate Credit kWh x ($0.00227)
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on H-1 Rate Customers Page 7 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
500 $53.15 $19.79 $33.36 $61.46 $19.79 $41.67 $8.31 15.6%
1,500 $153.19 $59.38 $93.81 $172.46 $59.38 $113.08 $19.27 12.6%
2,500 $253.22 $98.96 $154.26 $283.44 $98.96 $184.48 $30.22 11.9%
3,500 $353.24 $138.54 $214.70 $394.43 $138.54 $255.89 $41.19 11.7%
4,500 $453.28 $178.13 $275.15 $505.43 $178.13 $327.30 $52.15 11.5%
Blackstone Valley Rates: H-1 Narragansett Rates: C-06
Customer Charge $3.01 Customer Charge $5.73
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536
Distribution Energy Char kWh x $0.02975 Distribution Energy Char kWh x $0.03464
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on H-2 Rate Customers Page 8 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
500 $55.91 $19.79 $36.12 $55.49 $19.79 $35.70 ($0.42) -.08%
1,000 $108.25 $39.58 $68.67 $110.99 $39.58 $71.41 $2.74 2.5%
1,500 $160.59 $59.38 $101.21 $166.49 $59.38 $107.11 $5.90 3.7%
2,000 $212.93 $79.17 $133.76 $221.98 $79.17 $142.81 $9.05 4.3%
2,500 $265.27 $98.96 $166.31 $227.48 $98.96 $178.52 $12.21 4.6%
Blackstone Valley Rates: H-2 Narragansett Rates: C-06
Customer Charge $3.43 Customer Charge $0.00
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536
Distribution Energy Char kWh x $0.03421 Distribution Energy Char kWh x $0.03464
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on G-1 Rate Customers Page 9 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 $32.10 $9.90 $22.20 $33.72 $9.90 $23.82 $1.62 5.0%
500 $60.68 $19.79 $40.89 $61.46 $19.79 $41.67 $0.78 1.3%
750 $89.26 $26.69 $59.57 $89.21 $29.69 $59.52 ($0.05) -0.1%
1,000 $117.84 $39.58 $78.26 $116.96 $39.58 $77.38 ($0.88) -0.7%
1,250 $146.43 $49.48 $96.95 $144.71 $49.48 $95.23 ($1.72) -1.2%
Blackstone Valley Rates: G-1 Narragansett Rates: C-06
Customer Charge $3.37 Customer Charge $5.73
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536
Distribution Energy Char kWh x $0.04348 Distribution Energy Char kWh x $0.03464
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on W-1 Rate Customers Page 10 of 26
Blackstone Valley Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
------- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
125 $12.34 $4.95 $7.39 $13.88 $4.95 $8.93 $1.54 12.5%
250 $23.31 $9.90 $13.41 $27.75 $9.90 $17.85 $4.44 19.0%
375 $34.26 $14.84 $19.42 $41.62 $14.84 $26.78 $7.36 21.5%
500 $45.23 $19.79 $25.44 $55.49 $19.79 $35.70 $10.26 22.7%
1,000 $89.08 $39.58 $49.50 $110.99 $39.58 $71.41 $21.91 24.6%
Blackstone Valley Rates: W-1 Narragansett Rates: C-06
Customer Charge $1.32 Customer Charge $0.00
Transmission Energy Char kWh x $0.00000 Transmission Energy Char kWh x $0.00536
Distribution Energy Char kWh x $0.01792 Distribution Energy Char kWh x $0.03464
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Ad kWh x $0.00278 Transmission and S.O. Ad kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on H-1 Rate Customers Page 11 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 6,000 $603.32 $237.50 $365.82 $605.80 $237.50 $368.30 $2.48 0.4%
50 15,000 $1,503.60 $593.75 $909.85 $1,420.27 $593.75 $826.52 ($83.33) -5.5%
100 30,000 $3,004.07 $1,187.50 $1,816.57 $2,777.72 $1,187.50 $1,590.22 ($226.35) -7.5%
150 45,000 $4,504.54 $1,781.25 $2,723.29 $4,135.17 $1,781.25 $2,353.92 ($369.37) -8.2%
Blackstone Valley Rates: H-1 Narragansett Rates: G-02
Customer Charge $3.01 Customer Charge $103.41
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $0.00 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh x $0.02975 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on H-2 Rate Customers Page 12 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 6,000 $631.64 $237.50 $394.14 $498.08 $237.50 $260.58 ($133.56) -21.1%
50 15,000 $1,573.73 $593.75 $979.98 $1,312.55 $593.75 $718.80 ($261.18) -16.6%
100 30,000 $3,143.89 $1,187.50 $1,956.39 $2,670.00 $1,187.50 $1,482.50 ($473.89) -15.1%
150 45,000 $4,714.04 $1,781.25 $2,932.79 $4,027.45 $1,781.25 $2,246.20 ($686.59) -14.6%
Blackstone Valley Rates: H-2 Narragansett Rates: G-02
Customer Charge $3.43 Customer Charge $0.00
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $0.00 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh x $0.03421 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on G-2 te Customers Page 13 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 6,000 $589.00 $237.50 $351.50 $605.80 $237.50 $368.30 $16.80 2.9%
50 15,000 $1,472.50 $593.75 $878.75 $1,420.27 $593.75 $826.52 ($52.23) -3.5%
100 30,000 $2,945.00 $1,187.50 $1757.50 $2,777.72 $1,187.50 $1,590.22 ($167.28) -5.7%
150 45,000 $4,417.50 $1,781.25 $2,636.25 $4,135.17 $1,781.25 $2,353.92 ($282.33) -6.4%
Blackstone Valley Rates: G-2 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $1.50 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh x $0.02296 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-2 Rate Customers Page 14 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 6,000 $589.00 $237.50 $351.50 $605.80 $237.50 $368.30 $16.80 2.9%
50 15,000 $1,472.50 $593.75 $878.75 $1,420.27 $593.75 $826.52 ($52.23) -3.5%
100 30,000 $2,945.00 $1,187.50 $1757.50 $2,777.72 $1,187.50 $1,590.22 ($167.28) -5.7%
150 45,000 $4,417.50 $1,781.25 $2,636.25 $4,135.17 $1,781.25 $2,353.92 ($282.33) -6.4%
Blackstone Valley Rates: T-2 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $1.50 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh x $0.02296 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on G-5 Rate Customers Page 15 of 26
Hours Use: 400
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 8,000 $722.96 $316.67 $406.29 $756.87 $316.67 $440.20 $33.91 4.7%
50 20,000 $1,807.40 $791.67 $1,015.73 $1,797.93 $791.67 $1,006.26 ($9.47) -0.5%
100 40,000 $3,614.79 $1,583.33 $2,031.46 $3,533.03 $1,583.33 $1,949.70 ($81.76) -2.3%
150 60,000 $5,422.19 $2,375.00 $3,047.19 $5,268.14 $2,375.00 $2,893.14 ($154.05) -2.8%
Blackstone Valley Rates: G-5 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $1.35 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-5 Rate Customers Page 16 of 26
Hours Use: 350
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
20 7,000 $636.10 $277.08 $359.02 $681.33 $277.08 $404.25 $45.23 7.1%
50 17,500 $1,590.26 $692.71 $897.55 $1,609.10 $692.71 $916.39 $18.84 1.2%
100 35,000 $3,180.52 $1,385.42 $1,795.10 $3,155.38 $1,385.42 $1,769.96 ($25.14) -0.8%
150 52,500 $4,770.79 $2,078.13 $2,692.66 $4,701.66 $2,078.13 $2,623.53 ($69.13) -1.4%
Blackstone Valley Rates: T-5 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $1.35 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh $0.01710 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on W-1Rate Customers Page 17 of 26
Hours Use: 100
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1 100 $10.15 $3.96 $6.19 $7.55 $3.96 $3.59 ($2.60) -25.6%
3 300 $27.69 $11.88 $15.81 $22.66 $11.88 $10.78 ($5.03) -18.2%
5 500 $45.23 $19.79 $25.44 $37.76 $19.79 $17.97 ($7.47) -16.5%
10 1,000 $89.08 $39.58 $49.50 $75.53 $39.58 $35.95 ($13.55) -15.2%
Blackstone Valley Rates: W-1 Narragansett Rates: G-02
Customer Charge $1.32 Customer Charge $0.00
Transmission Demand Charge kW x $0.00 Transmission Demand Charge-xcs 10 kW kW x $1.40
Distribution Demand Charge kW x $0.00 Distribution Demand Charge-xcs 10 kW kW x $2.91
Distribution Energy Charge kWh x $0.01792 Distribution Energy Charge kWh x $0.00596
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on H-1 Rate Customers Page 18 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
200 60,000 $6,005.01 $2,375.00 $3,630.01 $5,435.86 $2,375.00 $3,060.86 ($569.15) -9.5%
300 90,000 $9,005.95 $3,562.50 $5,443.45 $8,030.66 $3,562.50 $4,468.16 ($975.29) -10.8%
400 120,000 $12,006.89 $4,750.00 $7,256.89 $10,625.45 $4,750.00 $5,875.45 ($1,381.44) -11.5%
500 150,000 $15,007.82 $5,937.50 $9,070.32 $13,220.24 $5,937.50 $7,282.74 ($1,787.58) -11.9%
600 180,000 $18,008.76 $7,125.00 $10,883.76 $15,815.03 $7,125.00 $8,690.03 ($2,193.73) -12.2%
Blackstone Valley Rates: H-1 Narragansett Rates: G-32
Customer Charge $3.01 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27
Distribution Demand Charge kW x $0.00 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.02975 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on H-2 Rate Customers Page 19 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
200 60,000 $6,284.20 $2,375.00 $3,909.20 $5,435.86 $2,375.00 $3,060.86 ($848.34) -13.5%
300 90,000 $9,424.51 $3,562.50 $5,862.01 $8,030.66 $3,562.50 $4,468.16 ($1,393.85) -14.8%
400 120,000 $12,564.82 $4,750.00 $7,814.82 $10,625.45 $4,750.00 $5,875.45 ($1,939.37) -15.4%
500 150,000 $15,705.14 $5,937.50 $9,767.64 $13,220.24 $5,937.50 $7,282.7 ($2,484.90) -15.8%
600 180,000 $18,845.45 $7,125.00 $11,720.45 $15,815.03 $7,125.00 $8,690.03 ($3,030.42) -16.1%
Blackstone Valley Rates: H-2 Narragansett Rates: G-32
Customer Charge $3.43 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Char kW x $1.27
Distribution Demand Charge kW x $0.00 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.03421 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on G-2 Rate Customers Page20 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
200 60,000 $5,523.75 $2,375.00 $3,148.75 $5,435.86 $2,375.00 $3,060.86 ($ 87.89) -1.6%
300 90,000 $8,285.63 $3,562.50 $4,723.13 $8,030.66 $3,562.50 $4,468.16 ($254.97) -3.1%
400 120,000 $11,047.50 $4,750.00 $6,297.50 $10,625.45 $4,750.00 $5,875.45 ($422.05) -3.8%
500 150,000 $13,809.38 $5,937.50 $7,871.88 $13,220.24 $5,937.50 $7,282.74 ($589.14) -4.3%
600 180,000 $16,571.25 $7,125.00 $9,446.25 $15,815.03 $7,125.00 $8,690.03 ($756.22) -4.6%
Blackstone Valley Rates: G-2 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27
Distribution Demand Charge kW x $1.50 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-2 Rate Customers Page 21 of 26
Hours Use: 400
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
500 200,000 $19,372.92 $7,916.67 $11,456.25 $17,053.58 $7,916.67 $9,136.91 ($2,319.34) -12.0%
1,000 400,000 $38,745.83 $15,833.33 $22,912.50 $33,860.86 $15,833.33 $18,027.53 ($4,884.97) -12.6%
1,500 600,000 $58,118.75 $23,750.00 $34,368.75 $50,668.16 $23,750.00 $26,918.16 ($7,450.59) -12.8%
2,000 800,000 $77,491.67 $31,666.67 $45,825.00 $67,475.45 $31,666.67 $35,808.78 ($10,016.22) -12.9%
2,500 1,000,000 $96,864.58 $39,583.33 $57,281.25 $84,282.74 $39,583.33 $44,699.41 ($12,581.84) -13.0%
Blackstone Valley Rates: T-2 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27
Distribution Demand Charge kW x $1.50 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.02296 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-4 Rate Customers Page 22 of 26
Hours Use: 400
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
500 200,000 $17,943.75 $7,916.67 $10,027.08 $17,053.58 $7,916.67 $9,136.91 ($890.17) -5.0%
1,000 400,000 $35,887.50 $15,833.33 $20,054.17 $33,860.86 $15,833.33 $18,027.53 ($2,026.64) -5.6%
1,500 600,000 $53,831.25 $23,750.00 $30,081.25 $50,668.16 $23,750.00 $26,918.16 ($3,163.09) -5.9%
2,000 800,000 $71,775.00 $31,666.67 $40,108.33 $67,475.45 $31,666.67 $35,808.78 ($4,299.55) -6.0%
2,500 1,000,000 $89,718.75 $39,583.33 $50,135.42 $84,282.74 $39,583.33 $44,699.41 ($5,436.01) -6.1%
Blackstone Valley Rates: T-4 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27
Distribution Demand Charge kW x $1.44 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.01625 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on G-5 Rate Customers Page 23 of 26
Hours Use: 300
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
200 60,000 $5,492.50 $2,375.00 $3,117.50 $5,435.86 $2,375.00 $3,060.86 ($56.64) -1.0%
300 90,000 $8,238.75 $3,562.50 $4,676.25 $8,030.66 $3,562.50 $4,468.16 ($208.09) -2.5%
400 120,000 $10,985.00 $4,750.00 $6,235.00 $10,625.45 $4,750.00 $5,875.45 ($359.55) -3.3%
500 150,000 $13,731.25 $5,937.50 $7,793.75 $13,220.24 $5,937.50 $7,282.74 ($511.01) -3.7%
600 180,000 $16,477.50 $7,125.00 $9,352.50 $15,815.03 $7,125.00 $8,690.03 ($662.47) -4.0%
Blackstone Valley Rates: G-5 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27
Distribution Demand Charge kW x $1.35 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-5 Rate Customers Page 24 of 26
Hours Use: 400
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
200 80,000 $7,229.59 $3,166.67 $4,062.92 $6,969.20 $3,166.67 $3,802.53 ($260.39) -3.6%
300 120,000 $10,844.38 $4,750.00 $6,094.38 $10,330.66 $4,750.00 $ 5,580.66 ($513.72) -4.7%
400 160,000 $14,459.16 $6,333.33 $8,125.83 $13,692.11 $ 6,333.33 $ 7,358.78 ($767.05) -5.3%
500 200,000 $18,073.96 $7,916.67 $10,157.29 $17,053.58 $ 7,916.67 $9,136.91 ($1,020.38) -5.6%
600 240,000 $21,688.75 $9,500.00 $12,188.75 $20,415.03 $ 9,500.00 $ 10,915.03 ($1,273.72) -5.9%
Blackstone Valley Rates: T-5 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Char kW x $1.27
Distribution Demand Charge kW x $1.35 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.01710 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-6 Rate Customers Page 25 of 26
Hours Use: 450
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
500 225,000 $18,900.78 $8,906.25 $9,994.53 $18,970.24 $8,906.25 $10,063.99 $69.46 0.4%
1,000 450,000 $37,801.56 $17,812.50 $19,989.06 $37,694.20 $17,812.50 $19,881.70 ($107.36) -0.3%
1,500 675,000 $56,702.34 $26,718.75 $29,983.59 $56,418.16 $26,718.75 $29,699.41 ($284.18) -0.5%
2,000 900,000 $75,603.13 $35,625.00 $39,978.13 $75,142.11 $35,625.00 $39,517.11 ($461.02) -0.6%
2,500 1,125,000 $94,503.91 $44,531.25 $49,972.66 $93,866.07 $44,531.25 $49,334.82 ($637.84) -0.7%
Blackstone Valley Rates:T-6 Narragansett RatesG-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.27
Distribution Demand Charge kW x $1.32 Distribution Demand Charge kW x $1.56
Distribution Energy Charge kWh x $0.01143 Distribution Energy Charge kWh x $0.00705
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
<PAGE>
<CAPTION>
The Narragansett Electric Company The Narragansett Electric Company
Calculation of Monthly Typical Bill R.I.P.U.C. Docket
Shifting BVE Customers to Narragansett Rates Exhibit JMM - 9
Impact on T-6 Rate Customers Page 26 of 26
Hours Use: 600
Blackstone Valley Rates Narragansett Rates Difference
Monthly Power Standard Standard
kWh kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
--- --- ----- -------- ------- ------ -------- ------- ------------- -------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
3,000 1,800,000 $149,831.25 $71,250.00 $78,581.25 $149,300.75 $71,250.00 $78,050.75 ($530.50) -0.4%
4,000 2,400,000 $199,775.00 $95,000.00 $104,775.00 $193,123.67 $95,000.00 $98,123.67 ($6,651.33) -3.3%
5,000 3,000,000 $249,718.75 $118,750.00 $130,968.75 $236,946.58 $118,750.00 $118,196.58 ($12,772.17) -5.1%
6,000 3,600,000 $299,662.50 $142,500.00 $157,162.50 $280,769.50 $142,500.00 $138,269.50 ($18,893.00) -6.3%
7,000 4,200,000 $349,606.25 $166,250.00 $183,356.25 $324,592.42 $166,250.00 $158,342.42 ($25,013.83) -7.2%
Blackstone Valley Rates: T-6 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $17,118.72
Transmission Demand Charge kW x $0.00 Transmission Demand Charge kW x $1.39
Distribution Demand Charge kW x $1.32 Distribution Demand Charge kW x $0.75
Transition Demand Charge kWh x $0.00 Transition Demand Charge kWh x $0.00
Distribution Energy Charge kWh x $0.01143 Distribution Energy Charge kWh x $0.00000
Transition Energy Charge kWh x $0.02320 Transition Energy Charge kWh x $0.02320
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00278 Transmission and S.O. Adjs. kWh x ($0.00129)
PBR Adjustment & FAS 106 kWh x $0.00000 PBR Adjustment & FAS 106 kWh x $0.00434
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JMM-10
Exhibit JMM-10
Newport Typical Bills
<PAGE>
<TABLE>
<CAPTION>
The Narragansett Electric Company
Range: A-10 THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 1 of 23
IMPACT ON R-1 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
120 $17.35 $4.75 $12.60 $16.41 $4.75 $11.66 ($0.94) -5.4%
240 $31.47 $9.50 $21.97 $30.17 $9.50 $20.67 ($1.30) -4.1%
480 $59.71 $19.00 $40.71 $57.70 $19.00 $38.70 ($2.01) -3.4%
700 $85.60 $27.71 $57.89 $82.94 $27.71 $55.23 ($2.66) -3.1%
950 $115.01 $37.60 $77.41 $111.60 $37.60 $74.00 ($3.41) -3.0%
500 $62.06 $19.79 $42.27 $59.99 $19.79 $40.20 ($2.07) -3.3%
Newport Rates: R-1 Narragansett Rates: A-16
Customer Charge $3.10 Customer Charge $2.54
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00436
Distribution Energy Charge kWh x $0.04653 Distribution Energy Charge kWh x $0.03246
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 1 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: TA THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 2 of 23
IMPACT ON W-1 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
750 $74.07 $29.69 $44.38 $86.03 $29.69 $56.34 $11.96 16.1%
1,500 $144.71 $59.38 $85.33 $172.05 $59.38 $112.67 $27.34 18.9%
3,000 $285.99 $118.75 $167.24 $344.09 $118.75 $225.34 $58.10 20.3%
4,600 $436.69 $182.08 $254.61 $527.61 $182.08 $345.53 $90.92 20.8%
6,000 $568.55 $237.50 $331.05 $688.19 $237.50 $450.69 $119.64 21.0%
Newport Rates: W-1 Narragansett Rates: A-16
Customer Charge $3.29 Customer Charge $0.00
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00436
Distribution Energy Charge kWh x $0.02399 Distribution Energy Charge kWh x $0.03246
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 2 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: A-30A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 3 of 23
IMPACT ON R-4 RATE CUSTOMERS
KWH SPLIT: -ON-PEAK 23%
-OFF-PEAK 77%
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
2,000 $248.04 $79.17 $168.87 $212.92 $79.17 $133.75 ($35.12) -14.2%
2,500 $308.29 $98.96 $209.33 $264.39 $98.96 $165.43 ($43.90) -14.2%
3,000 $368.53 $118.75 $249.78 $315.86 $118.75 $197.11 ($52.67) -14.3%
4,000 $489.01 $158.33 $330.68 $418.81 $158.33 $260.48 ($70.20) -14.4%
5,000 $609.51 $197.92 $411.59 $521.76 $197.92 $323.84 ($87.75) -14.4%
Newport Rates: R-4 Narragansett Rates: A-32
Customer Charge $6.78 Customer Charge $2.30
Meter Charge $0.00 Meter Charge $4.44
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00392
Dist Peak Energy Charge kWh x $0.11000 Distribution Energy Charge kWh x $0.02162
Dist Off Peak Energy Charge kWh x $0.03109
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 3 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: A-30B THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 4 of 23
IMPACT ON R-4 RATE CUSTOMERS
KWH SPLIT: -ON-PEAK 26%
-OFF-PEAK 77%
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
3,000 $375.93 $118.75 $257.18 $315.86 $118.75 $197.11 ($60.07) -16.0%
4,000 $498.88 $158.33 $340.55 $418.81 $158.33 $260.48 ($80.07) -16.0%
5,000 $621.84 $197.92 $423.92 $521.76 $197.92 $323.84 ($100.08) -16.1%
6,000 $744.79 $237.50 $507.29 $624.71 $237.50 $387.21 ($120.08) -16.1%
7,000 $867.74 $277.08 $590.66 $727.65 $277.08 $450.57 ($140.09) -16.1%
Newport Rates: R-4 Narragansett Rates: A-32
Customer Charge $6.78 Customer Charge $2.30
Meter Charge $0.00 Meter Charge $4.44
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00392
Dist Peak Energy Charge kWh x $0.11000 Distribution Energy Charge kWh x $0.02162
Dist Off Peak Energy Charge kWh x $0.03109
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 4 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: A-65A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:49 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 5 of 23
IMPACT ON R-2 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
100 $9.94 $3.96 $5.98 $9.35 $3.96 $5.39 ($0.59) -5.9%
300 $25.37 $11.88 $13.49 $28.06 $11.88 $16.18 $2.69 10.6%
500 $47.96 $19.79 $28.17 $48.05 $19.79 $28.26 $0.09 0.2%
700 $70.57 $27.71 $42.86 $68.04 $27.71 $40.33 ($2.53) -3.6%
1,000 $104.46 $39.58 $64.88 $98.02 $39.58 $58.44 ($6.44) -6.2%
Newport Rates: R-2 Narragansett Rates: A-60
Customer Charge $2.14 Customer Charge $0.00
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00338
Dist. Energy Charge first 300 kWh kWh x $0.00759 Distribution Energy Charge kWh x $0.02521
Dist. Energy Charge excess 300 kWh kWh x $0.04206 Dist. Surcharge & FAS 106 kWh x $0.00729
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
Credit First 300 kWh kWh x ($0.00616)
A-60 Rate Credit kWh x $0.00000 A-60 Rate Credit kWh x ($0.00227)
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 5 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: A-02A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 6 of 23
IMPACT ON H1 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
500 $67.80 $19.79 $48.01 $64.97 $19.79 $45.18 ($2.83) -4.2%
1,500 $178.33 $59.38 $118.95 $182.99 $59.38 $123.61 $4.66 -2.6%
2,500 $288.86 $98.96 $189.90 $301.00 $98.96 $202.04 $12.14 4.2%
3,500 $399.39 $138.54 $260.85 $419.00 $138.54 $280.46 $19.61 4.9%
4,500 $509.93 $178.13 $331.80 $537.02 $178.13 $358.89 $27.09 5.3%
Newport Rates: H-1 Narragansett Rates: C-06
Customer Charge $12.03 Customer Charge $5.73
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536
Distribution Energy Charge kWh x $0.03968 Distribution Energy Charge kWh x $0.03464
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 6 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: A-02B THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 7 of 23
IMPACT ON H-2 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
500 $63.76 $19.79 $43.97 $59.00 $19.79 $39.21 ($4.76) -7.5%
1,000 $122.74 $39.58 $83.16 $118.01 39.58 $78.43 ($4.73) -3.9%
1,500 $181.72 $59.38 $122.34 $117.02 $59.38 $117.64 ($4.70) -2.6%
2,000 $240.70 $79.17 $161.53 $236.02 $79.17 $156.85 ($4.68) -1.9%
2,500 $299.68 $98.96 $200.72 $295.03 $98.96 $196.07 ($4.65) -1.6%
Newport Rates: H-2 Narragansett Rates: C-06
Customer Charge $4.59 Customer Charge $0.00
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536
Distribution Energy Charge kWh x $0.04681 Distribution Energy Charge kWh x $0.03464
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 7 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: C-02C THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 8 of 23
IMPACT ON G-1 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
250 $36.08 $9.90 $26.18 $35.48 $9.90 $25.58 ($0.60) -1.7%
500 $68.57 $19.79 $48.78 $64.97 $19.79 $45.18 ($3.60) -5.3%
750 $101.06 $29.69 $71.37 $94.48 $29.69 $64.79 ($6.58) -6.5%
1,000 $133.54 $39.58 $93.96 $123.98 $39.58 $84.40 ($9.56) -7.2%
1,250 $166.03 $49.48 $116.55 $153.48 $49.48 $104.00 ($12.55) -7.6%
Newport Rates: G-1 Narragansett Rates: C-06
Customer Charge $3.45 Customer Charge $5.73
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536
Distribution Energy Charge kWh x $0.05832 Distribution Energy Charge kWh x $0.03464
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 8 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: C-02D THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 9 of 23
IMPACT ON W-1 RATE CUSTOMERS
Newport Rates Narragansett Rates Difference
Monthly Standard Standard
kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
125 $15.20 $4.95 $10.25 $14.75 $4.95 $9.80 ($0.45) -3.0%
250 $26.98 $9.90 $17.08 $29.51 $9.90 $19.61 $2.53 9.4%
375 $38.74 $14.84 $23.90 $44.25 $14.84 $29.41 $5.51 14.2%
500 $50.52 $19.79 $30.73 $59.00 $19.79 $39.21 $8.48 16.8%
1,000 $97.61 $39.58 $58.03 $118.01 $39.58 $78.43 $20.40 20.9%
Newport Rates: W-1 Narragansett Rates: C-06
Customer Charge $3.29 Customer Charge $0.00
Transmission Energy Charge kWh x $0.00000 Transmission Energy Charge kWh x $0.00536
Distribution Energy Charge kWh x $0.02399 Distribution Energy Charge kWh x $0.03464
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 9 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-00 THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 10 of 23
IMPACT ON H-1 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
20 6,000 $675.72 $237.50 $438.22 $647.93 $237.50 $410.43 ($27.29) -4.1%
50 15,000 $1,670.50 $593.75 $1,076.75 $1,525.58 $593.75 $931.83 ($144.92) -8.7%
100 30,000 $3,328.47 $1,187.50 $2,140.97 $2,988.34 $1,187.50 $1,800.84 ($340.13) -10.2%
150 45,000 $4,986.44 $1,781.25 $3,205.19 $4,451.10 $1,781.25 $2,669.85 ($535.34) -10.7%
Newport Rates: H-1 Narragansett Rates: G-02
Customer Charge $12.03 Customer Charge $103.41
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40
Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $2.91
Distribution Energy Charge kWh x $0.03968 Distribution Energy charge kWh x $0.00596
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 10 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-00A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 11 of 23
IMPACT ON H-2 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
20 6,000 $712.53 $237.50 $475.03 $540.21 $237.50 $302.71 ($172.32) -24.2%
50 15,000 $1,774.16 $593.75 $1,180.41 $1,417.86 $593.75 $824.11 ($356.30) -20.1%
100 30,000 $3,543.53 $1,187.50 $2,356.03 $2,880.63 $1,187.50 $1,693.13 ($662.90) -18.7%
150 45,000 $5,312.91 $1,781.25 $3,531.66 $4,343.39 $1,781.25 $2,562.14 ($969.52) -18.2%
Newport Rates: H-2 Narragansett Rates: G-02
Customer Charge $4.59 Customer Charge $0.00
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40
Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $2.91
Distribution Energy Charge kWh x $0.04681 Distribution Energy charge kWh x $0.00596
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 11 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-00B THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 12 of 23
IMPACT ON G-2 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
20 6,000 $663.71 $237.50 $426.21 $647.93 $237.50 $410.43 ($15.78) -2.4%
50 15,000 $1,659.27 $593.75 $1,065.52 $1,525.58 $593.75 $931.83 ($133.69) -8.1%
100 30,000 $3,318.54 $1,187.50 $2,131.04 $2,988.34 $1,187.50 $1,800.84 ($330.20) -10.0%
150 45,000 $4,977.81 $1,781.25 $3,196.56 $4,451.10 $1,781.25 $2,669.85 ($526.71) -10.6%
Newport Rates: G-2 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40
Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $2.91
Distribution Energy Charge kWh x $0.03443 Distribution Energy charge kWh x $0.00596
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 12 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-00C THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 13 of 23
IMPACT ON T-2 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
20 6,000 $663.71 $237.50 $426.21 $647.93 $237.50 $410.43 ($15.78) -2.4%
50 15,000 $1,659.27 $593.75 $1,065.52 $1,525.58 $593.75 $931.83 ($133.69) -8.1%
100 30,000 $3,318.54 $1,187.50 $2,131.04 $2,988.34 $1,187.50 $1,800.84 ($330.20) -10.0%
150 45,000 $4,977.81 $1,781.25 $3,196.56 $4,451.10 $1,781.25 $2,669.85 ($526.71) -10.6%
Newport Rates: T-2 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40
Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $2.91
Distribution Energy Charge kWh x $0.03443 Distribution Energy charge kWh x $0.00596
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 13 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-00D THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 14 of 23
IMPACT ON G-5 RATE CUSTOMERS
Hours Use: 400
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
20 8,000 $835.92 $316.67 $519.25 $813.03 $316.67 $496.36 ($22.89) -2.7%
50 20,000 $2,089.80 $791.67 $1,298.13 $1,938.35 $791.67 $1,146.68 ($151.45) -7.2%
100 40,000 $4,179.58 $1,583.33 $2,596.25 $3,813.66 $1,583.33 $2,230.53 ($365.72) -8.8%
150 60,000 $6,269.38 $2,375.00 $3,894.38 $5,689.39 $2,375.00 $3,314.39 ($579.99) -9.3%
Newport Rates: G-5 Narragansett Rates: G-02
Customer Charge $0.00 Customer Charge $103.41
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40
Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $2.91
Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00596
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 14 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-00F THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 15 of 23
IMPACT ON W-1 RATE CUSTOMERS
Hours Use: 100
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
1 100 $12.85 $3.96 $8.89 $8.26 $3.96 $4.30 ($4.59) -35.7%
3 300 $31.69 $11.88 $19.81 $24.77 $11.88 $12.89 ($6.92) -21.8%
5 500 $50.52 $19.79 $30.73 $41.27 $19.79 $21.48 ($9.25) -18.3%
10 1,000 $97.61 $39.58 $58.03 $82.55 $39.58 $42.97 ($15.06) -15.4%
Newport Rates: W-1 Narragansett Rates: G-02
Customer Charge $3.29 Customer Charge $0.00
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.40
Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $2.91
Distribution Energy Charge kWh x $0.02399 Distribution Energy charge kWh x $0.00596
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 15 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-30A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 16 of 23
IMPACT ON H-1 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
200 60,000 $6,644.41 $2,375.00 $4,269.41 $5,857.11 $2,375.00 $3,482.11 ($787.30) -11.8%
300 90,000 $9,960.34 $3,562.50 $6,397.84 $8,662.53 $3,562.50 $5,100.03 ($1,297.81) -13.0%
400 120,000 $13,276.28 $4,750.00 $8,526.28 $11,467.95 $4,750.00 $6,717.95 ($1,808.33) -13.6%
500 150,000 $16,592.22 $5,937.50 $10,654.72 $14,273.36 $5,937.50 $8,335.86 ($2,318.86) -14.0%
500 180,000 $19,908.16 $7,125.00 $12,783.16 $17,078.78 $7,125.00 $9,953.78 ($2,829.38) -14.2%
Newport Rates: H-1 Narragansett Rates: G-32
Customer Charge $12.03 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $0.00 Distribution Demand Charge-xcs 10 kW kWh x $1.56
Distribution Energy Charge kWh x $0.03968 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 16 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-30C THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 17 of 23
IMPACT ON G-2 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
200 60,000 $6,327.71 $2,375.00 $3,952.71 $5,857.11 $2,375.00 $3,482.11 ($470.60) -7.4%
300 90,000 $9,491.56 $3,562.50 $5,929.06 $8,662.53 $3,562.50 $5,100.03 ($829.03) -8.7%
400 120,000 $12,655.42 $4,750.00 $7,905.42 $11,467.95 $4,750.00 $6,717.95 ($1,187.47) -9.4%
500 150,000 $15,819.27 $5,937.50 $9,881.77 $14,273.36 $5,937.50 $8,335.86 ($1,545.91) -9.8%
600 180,000 $18,983.13 $7,125.00 $11,858.13 $17,078.78 $7,125.00 $9,953.78 ($1,904.35) -10.0%
Newport Rates: G-2 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $156
Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 17 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-30D THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 18 of 23
IMPACT ON T-2 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
500 200,000 $21,845.84 $7,916.67 $13,929.17 $18,457.74 $7,916.67 $10,541.07 ($3,388.10) -15.5%
1,000 400,000 $43,691.66 $15,833.33 $27,858.33 $36,669.19 $15,833.33 $20,835.86 ($7,022.47) -16.1%
1,500 600,000 $65,537.50 $23,750.00 $41,787.50 $54,880.66 $23,750.00 $31,130.66 ($10,656.84) -16.3%
2,000 800,000 $87,383.34 $31,666.67 $55,716.67 $73,092.12 $31,666.67 $41,425.45 ($14,291.22) -16.4%
2,500 1,000,000 $109,229.16 $39,583.33 $69,645.83 $91,303.57 $39,583.33 $51,720.24 ($17,925.59) -16.4%
Newport Rates: T-2 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $1.60 Distribution Demand Charge-xcs 10 kW kWh x $1.56
Distribution Energy Charge kWh x $0.03443 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 18 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G -30E THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 19 of 23
IMPACT ON T-4 RATE CUSTOMERS
Hours Use: 400
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
500 200,000 $22,182.30 $7,916.67 $14,265.63 $18,457.74 $7,916.67 $10,541.07 ($3,724.56) -16.8%
1,000 400,000 $44,364.58 $15,833.33 $28,531.25 $36,669.19 $15,833.33 $20,835.86 ($7,695.39) -17.3%
1,500 600,000 $66,546.88 $23,750.00 $42,796.88 $54,880.66 $23,750.00 $31,130.66 ($11,666.22) -17.5%
2,000 800,000 $88,729.17 $31,666.67 $57,062.50 $73,092.12 $31,666.67 $41,425.45 ($15,637.05) -17.6%
2,500 1,000,000 $110,911.46 $39,583.33 $71,328.13 $91,303.57 $39,583.33 $51,720.24 ($19,607.89) -17.7%
Newport Rates: T-4 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $1.95 Distribution Demand Charge-xcs 10 kW kWh x $1.56
Distribution Energy Charge kWh x $0.03517 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 19 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-30F THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 20 of 23
IMPACT ON G-5 RATE CUSTOMERS
Hours Use: 300
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
200 60,000 $6,361.04 $2,375.00 $3,986.04 $5,857.11 $2,375.00 $3,482.11 ($503.93) -7.9%
300 90,000 $9,541.56 $3,562.50 $5,979.06 $8,662.53 $3,562.50 $5,100.03 ($879.03) -9.2%
400 120,000 $12,722.08 $4,750.00 $7,972.08 $11,467.95 $4,750.00 $6,717.95 ($1,254.13) -9.9%
500 150,000 $15,902.60 $5,937.50 $9,965.10 $14,273.36 $5,937.50 $8,335.86 ($1,629.24) -10.2%
600 180,000 $19,083.13 $7,125.00 $11,958.13 $17,078.78 $7,125.00 $9,953.78 ($2,004.35) -10.5%
Newport Rates: G-5 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $1.56
Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 20 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-30G THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 21 of 23
IMPACT ON T-5 RATE CUSTOMERS
Hours Use: 400
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
200 80,000 $8,359.17 $3,166.67 $5,192.50 $7,530.87 $3,166.67 $4,364.20 ($828.30) -9.9%
300 120,000 $12,538.75 $4,750.00 $7,788.75 $11,173.16 $4,750.00 $6,423.16 ($13,365.59) -10.9%
400 160,000 $16,718.33 $6,333.33 $10,385.00 $14,815.44 $6,333.33 $8,482.11 ($1,902.89) -11.4%
500 200,000 $20,897.92 $7,916.67 $12,981.25 $18,457.74 $7,916.67 $10,541.07 ($2,440.18) -11.7%
600 240,000 $25,077.50 $9,500.00 $15,577.50 $22,100.03 $9,500.00 $12,600.03 ($2,977.47) -11.9%
Newport Rates: T-5 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $1.56
Distribution Energy Charge kWh x $0.02948 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 21 of 23
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-30H THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 22 of 23
IMPACT ON T-6 RATE CUSTOMERS
Hours Use: 450
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
500 225,000 $23,501.04 $8,906.25 $14,594.79 $20,549.93 $8,906.25 $11,643.68 ($2,951.11) -12.6%
1,000 450,000 $47,002.08 $17,812.50 $29,189.58 $40,853.57 $17,812.50 $23,041.07 ($6,148.51) -13.1%
1,500 675,000 $70,503.13 $26,718.75 $43,784.38 $61,157.22 $26,718.75 $34,438.47 ($9,345.91) -13.3%
2,000 900,000 $94,004.17 $35,625.00 $58,379.17 $81,460.86 $35,625.00 $45,835.86 ($12.543.31) -13.3%
2,500 1,125,000 $117,505.21 $44,531.25 $72,973.96 $101,764.51 $44,531.25 $57,233.26 ($15,740.70) -13.4%
Newport Rates: T-6 Narragansett Rates: G-32
Customer Charge $0.00 Customer Charge $236.43
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.27
Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $1.56
Distribution Energy Charge kWh x $0.02993 Distribution Energy charge kWh x $0.00705
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
File: C:\123data\JAMES\M&A\BASE\Necbill4.wk4 The Narragansett Electric Company
Range: G-60A THE NARRAGANSETT ELECTRIC COMPANY R.I.P.U.C. Docket
Date: 14-May-99 CALCULATION OF MONTHLY TYPICAL BILL Exhibit JMM - 10
Time: 12:35 PM SHIFTING NEC CUSTOMERS TO NARRAGANSETT RATES Page 23 of 23
IMPACT ON T-6 RATE CUSTOMERS
Hours Use: 600
Monthly Newport Rates Narragansett Rates Difference
Power Standard Standard
kW kWh Total Offer "Wires" Total Offer "Wires" Amount % of Total
3,000 1,800,000 $186,175.00 $71,250.00 $114,925.00 $161,938.25 $71,250.00 $90,688.25 ($24,236.75) -13.0%
4,000 2,400,000 $248,233.33 $95,000.00 $153,233.33 $209,973.67 $95,000.00 $114,973.67 ($38,259.66) -15.4%
5,000 3,000,000 $310,291.67 $118,750.00 $191,541.67 $258,009.08 $118,750.00 $139,259.08 ($52,282.59) -16.8%
6,000 3,600,000 $372,350.00 $142,500.00 $229,850.00 $306,044.50 $142,500.00 $163,544.50 ($66,305.50) -17.8%
7,000 4,200,000 $434,408.33 $166,250.00 $268,158.33 $354,079.92 $166,250.00 $187,829.92 ($80,328.41) -18.5%
Newport Rates: T-6 Narragansett Rates: G-62
Customer Charge $0.00 Customer Charge $17,118.72
Transmission Demand Charge kWh x $0.00 Transmission Demand Charge-xcs 10 kW kWh x $1.39
Distribution Demand Charge kWh x $1.76 Distribution Demand Charge-xcs 10 kW kWh x $0.75
Transition Demand Charge kWh x $0.00 Transition Demand Charge kWh x $0.00
Distribution Energy Charge kWh x $0.02993 Distribution Energy charge kWh x $0.00000
Transition Energy Charge kWh x $0.02340 Transition Energy Charge kWh x $0.02340
DSM Adjustment kWh x $0.00230 DSM Adjustment kWh x $0.00230
Transmission and S.O. Adjs. kWh x $0.00273 Transmission and S.O. Adjs. kWh x ($0.00136)
PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.00000 PBR Adj, FAS 106 & Dist. Surcharge kWh x $0.01095
Gross Earnings Tax 4.00% Gross Earnings Tax 4.00%
Standard Offer Charge kWh x $0.03800 Standard Offer Charge kWh x $0.03800
The Narragansett Electric Company
R.I.P.U.C. Docket
Exhibit JMM - 10
Page 23 of 23
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Exhibit JMM-11
Addition to Narragansett Terms and Conditions
Definitions of Zones
34. For purposes of interpreting rates, tariffs and Terms and Conditions,
the following terms will have the meanings as follows:
Narragansett Zone is the cities and towns of: Providence, North
Providence, East Providence, Cranston, Johnston, Smithfield, Scituate,
Foster, Gloucester, Warren, Barrington, Bristol, Tiverton, Little
Compton, Warwick, West Warwick, East Greenwich, Coventry, North
Kingstown, Westerly, Richmond, Charlestown, Exeter, Hopkinton,
Narragansett, South Kingstown and West Greenwich.
Blackstone Valley Zone is the cities and towns of: Pawtucket, Central
Falls, Cumberland, Lincoln, Woonsocket, North Smithfield, and
Burrillville.
Newport Zone is the cities and towns of: Newport, Middletown,
Portsmouth, and Jamestown.
<PAGE>
<TABLE>
<CAPTION>
Exhibit JMM-12
THE NARRAGANSETT ELECTRIC COMPANY Effective
Basic Residential Rate (A-16) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1100-A
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Customer Charge per month $2.54
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Charge per kWh 0.436 cents
Transmission Adjustment Factor per kWh 0.079 cents
Distribution Charge per kWh * 3.708 cents
Minimum Charge per month $2.54
Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit 12 per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable,
will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
Residential Time-Of-Use Rate (A-32) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1102-A
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Customer Charge per month $2.30
Time-of-use Metering Charge per month $4.44
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Charge per kWh 0.392 cents
Transmission Adjustment Factor per kWh 0.079 cents
Distribution Charge per kWh * 2.624 cents
Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable,
will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
Low Income Rate (A-60) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1103-A
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Charge per kWh 0.338 cents
Transmission Adjustment Factor per kWh 0.073 cents
Distribution Charge per kWh * 2.617 cents
Water Heater Credit per kWh for the first 750 kWh per month 0.661 cents
Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997)
A-60 Rate Credit 0.227 cents
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Blackstone Equalization Credit per first 300 kWh 0.733 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Newport Equalization Credit per first 300 kWh 0.616 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998) and 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999).
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable,
will appear on bills sent to customers. Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
General C&I Back-Up Service Rate (B-02) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1117-A
Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for Retail Delivery Service
<S> <C> <C> <C>
Customer Charge per month $103.41 n/a
Distribution Demand Charge per kW in excess 10 kW $2.91 $2.91
Transmission Demand Charge per kW in excess 10 kW $1.40 $1.40
Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents,
Distribution Energy Charge per kWh* 1.058 cents 1.058 cents
Non-bypassable Transition Charge per kWh n/a 1.150 cents
C&LM Adjustment per kWh n/a 0.230 cents
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh n/a 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh n/a 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh n/a 3.800 cents
Last Resort per kWh n/a per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when applicable,
will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
Small C&I Back-Up Service Rate (B-06) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1118-A
Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for Retail Delivery Service
<S> <C> <C> <C>
Customer Charge per month $5.73 n/a
Transmission Energy Charge per kWh 0.536 cents 0.536 cents
Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents
Distribution Energy Charge per kWh* 3.926 cents 3.926 cents
Non-bypassable Transition Charge per kWh n/a 1.150 cents
C&LM Adjustment per kWh n/a 0.230 cents
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh n/a 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh n/a 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh n/a 3.800 cents
Last Resort per kWh n/a per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes when applicable,
will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
200 kW Back-Up Service Rate (B-32) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1119-A
Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for Retail Delivery Service
<S> <C> <C> <C>
Customer Charge per month $236.43 n/a
Transmission Demand Charge per kW $1.27 $1.27
Distribution Demand Charge per kW $1.56 $1.56
Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents
Distribution Energy Charge per kWh * 1.167 cents 1.167 cents
Non-bypassable Transition Charge per kWh n/a 1.150 cents
C&LM Adjustment per kWh n/a 0.230 cents
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh n/a 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh n/a 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh n/a 3.800 cents
Last Resort per kWh n/a per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when
applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
3,000 kW Back-Up Service Rate (B-62) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1120-A
Monthly Charge As Adjusted
Rates for Rates for
Back-Up Service Supplemental Service
Rates for Retail Delivery Service
<S> <C> <C> <C>
Customer Charge per month $17,118.72 n/a
Distribution Demand Charge per kW $0.75 $0.75
Transmission Demand Charge per kW $1.39 $1.39
Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents
Distribution Energy Charge per kWh * 0.462 cents 0.462 cents
Non-bypassable Transition Charge per kWh n/a 1.150 cents
C&LM Adjustment per kWh n/a 0.230 cents
Additional Delivery for Blackstone Valley Zone
Zonal Transition Factor per kWh n/a 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh n/a 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh n/a 3.800 cents
Last Resort per kWh n/a per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustment effective Jan. 1, 1997 and Jan. 1, 1998 respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when
applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
Small C&I Rate (C-06) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1104-A
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Customer Charge per month $5.73
Unmetered Charge per month $1.83
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Charge per kWh 0.536 cents
Transmission Adjustment Factor per kWh 0.079 cents (Eff. Jan. 1, 1999)
Distribution Charge per kWh* 3.926 cents
Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when
applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
General C&I Rate (G-02) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1107-A
Monthly Charge As Adjusted
Rates for Retail Delivery Service
<S> <C> <C>
Customer Charge per month $103.41
Transmission Charge per kW in excess of 10 kW $1.40
Distribution Charge per kW in excess of 10 kW $2.91
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Adjustment Factor per kWh 0.079 cents
Distribution Charge per kWh* 1.058 cents
Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes. However, such taxes, when
applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
200 kW Demand Rate (G-32) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1108-A
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Customer Charge per month $236.43
Transmission Charge per kW $1.27
Distribution Charge per kW $1.56
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Adjustment Factor per kWh 0.079 cents(Eff. Jan. 1, 1999)
Distribution Charge per kWh* 1.167 cents
Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such
taxes, when applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
3000 kW Demand Rate (G-62) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1109-A
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Customer Charge per month $17,118.72
Transmission Charge per kW $1.39
Distribution Charge per kW $0.75
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Adjustment Factor per kWh 0.079 cents (Eff. Jan. 1, 1999)
Distribution Charge per kWh* 0.462 cents
Conservation and Load Management Adjustment per kWh 0.230 cents (Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Zonal Distribution Factor per kWh 0.661 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such
taxes, when applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
General Streetlighting Service (S-14) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No. 1113-A
Luminaire
Type/Lumens Code Annual kWh
<S> <C> <C>
Incandescent
1,000 10 440
Mercury Vapor
8,000 02 908
4,000 03 561
8,000 04 908
22,000 05 1,897
63,000 06 4,569
Sodium Vapor
4,000 70 248
9,600 72,79 490
27,500 74 1,284
50,000 75 1,968
27,500 (24 hr) 84 2,568
50,000 FL 78 1,968
Narragansett Blackstone Newport
Zone Zone Zone
<S> <C> <C> <C>
Non-Bypassable Transition Charge per kWh 1.150 cents 1.150 cents 1.150 cents
Zonal Transition Factor per kWh 0.000 cents 0.962 cents 1.008 cents
Distribution Energy Charge per kWh* 0.462 cents 0.462 cents 0.462 cents
Transmission Charge per kWh 0.259 cents 0.259 cents 0.259 cents
Transmission Adjustment Factor per kWh 0.079 cents 0.079 cents 0.079 cents
Transmission Adjustment Credit per kWh 0.000 cents 0.208 cents 0.215 cents
Conservation & Load Management Adj. Per kWh 0.230 cents 0.230 cents 0.230 cents
Zonal Distribution Factor per kWh 0.000 cents 0.000 cents 0.661 cents
Streetlight Credit per kWh 0.000 cents 4.458 cents 2.956 cents
Plus 3.800 cents per kWh for Standard Offer (Eff. April 1, 2000) (Optional)
Plus Last Resort per Last Resort Service tariff (Optional)
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard 0ffer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Based Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such
taxes, when applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
<PAGE>
THE NARRAGANSETT ELECTRIC COMPANY Effective
69kV Rate (N-01) April 1, 2000
Retail Delivery Service
R.I.P.U.C. No.
Monthly Charge As Adjusted
<S> <C> <C>
Rates for Retail Delivery Service
Distribution Charge per kW $6.60
Distribution Charge per kVAR $0.20
Non-Bypassable Transition Charge per kWh 1.150 cents
Transmission Charge per kWh 0.409 cents
Transmission Adjustment Factor per kWh 0.079 cents
Distribution Charge per kWh* 0.731 cents
Conservation and Load Management Adjustment per kWh 0.230 cents(Eff. Jan. 1, 1997)
Additional Delivery Rates for Blackstone Valley Zone
Zonal Transition Factor per kWh 0.962 cents
Transmission Adjustment Credit per kWh 0.208 cents
Additional Delivery Rates for Newport Zone
Zonal Transition Factor per kWh 1.008 cents
Transmission Adjustment Credit per kWh 0.215 cents
Rates for Standard Offer Service or Last Resort Service (Optional)
Standard Offer per kWh 3.800 cents(Eff. January 1, 2000)
----------------------
Last Resort per kWh per Last Resort Service tariff
* Includes 0.068 cents per kWh for phase-in of FAS 106 (Eff. Jan. 1, 1998), 0.028 cents per kWh for Standard Offer
Adjustment Provision (Eff. Jan. 1, 1999) and 0.214 cents per kWh and 0.152 cents per kWh for Performance Base Rate
Adjustments effective Jan. 1, 1997 and Jan. 1, 1998, respectively.
Tax Note: The rates listed above do not reflect gross earnings tax or sales taxes (when applicable). However, such
taxes, when applicable, will appear on bills sent to customers.
Other Rate Clauses apply as usual.
</TABLE>
<PAGE>
R.I.P.U.C. No.
Sheet 1
Cancelling R.I.P.U.C. No.
THE NARRAGANSETT ELECTRIC COMPANY
69kV Rate (N-01)
RETAIL DELIVERY SERVICE
AVAILABILITY
This rate is available to customers taking service at a nominal
voltage of 69,000 volts and is mandatory for the Department of the Navy, its
successors, or assigns, for electric power service to the Naval Education and
Training Center, Newport, Rhode Island.
Electric retail delivery service supplied hereunder shall be three
phase, alternating current, at a nominal frequency of sixty Hertz, and at a
nominal voltage of 69,000 volts.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
Charges set forth in the cover sheet this tariff.
DETERMINATION OF BILLING PERIODS
The Billing Period consists of the days between consecutive meter
readings. Service under this Rate is rendered on a full calendar day basis. The
first day of any billing period is included in its entirety and the last day of
any billing period is excluded in its entirety.
DETERMINATION OF BILLING DEMANDS
I. Billing Demand
A. Requirements Service
The Demand in kilowatts for each month is the maximum metered
fifteen-minute demand during the Billing Period.
B. Partial Requirements Service
The Demand in kilowatts for each month is the maximum fifteen-minute
total demand during the month where the total demand is the combined of the
Partial Requirements Service delivered by the Company and the service supplied
by the customer's other power source.
The Billing Demand in kilowatts for each month shall be the largest
of:
<PAGE>
R.I.P.U.C. No.
Sheet 2
THE NARRAGANSETT ELECTRIC COMPANY
69kV Rate (N-01)
RETAIL DELIVERY SERVICE
1. the Demand,
2. Seventy-five percent (75%) of the highest Demand recorded during
the previous eleven months, or
3. Fifty percent (50%) of the highest Demand recorded by the customer
since 1961, where:
For the purposes of determining the Billing Demand, all demands
recorded before December 1, 1994, shall be deemed Demands, all Standby Demands
recorded after December 1, 1994, through June 30, 1997 shall be deemed Demands,
and all Distribution Demands recorded after June 30, 1997, shall be deemed
Demands.
II. Reactive Billing Demand
The Reactive Billing Demand in kilovars for each month shall be the
Reactive Demand in excess of seventeen and one-half percent (17.5%) of the
Demand, where the Reactive Demand in kilovars for each month is the metered
fifteen-minute reactive demand coincident with the Demand.
DETERMINATION OF BILLING DEMAND CHARGES
I. Billing Demand Charge
The Billing Demand Charge shall be the Billing Demand times the Demand
Rate.
I. Reactive Billing Demand Charge
The Reactive Billing Demand Charge shall be the Reactive Billing
Demand times the Reactive Demand Rate.
DETERMINATION OF MINIMUM BILLING ENERGY CHARGE
The Minimum Billing Energy Charge shall be the Total Energy
Requirements times the Transition Charge For the purposes of the foregoing,
Total Energy Requirements shall mean the sum of the energy delivered by the
Company and the energy supplied by the Navy's other power sources other than
electrically isolated emergency power sources.
RATE ADJUSTMENT PROVISIONS
Transmission Service Charge Adjustment
The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's Transmission
Service Cost Adjustment Provision.
Transition Charge Adjustment
The prices under this rate as set forth under "Monthly Charge" may be
adjusted from time to time in the manner described in the Company's
Non-Bypassable Transition Charge Adjustment Provision.
<PAGE>
R.I.P.U.C. No.
Sheet 3
THE NARRAGANSETT ELECTRIC COMPANY
69kV Rate (N-01)
RETAIL DELIVERY SERVICE
Standard Offer Adjustment
All Customers served on this rate must pay any charges required
pursuant to the terms of the Company's Standard Offer Adjustment Provisions,
whether or not the Customer is taking or has taken Standard Offer Service.
Conservation and Load Management Adjustment
The amount determined under the preceding provisions shall be adjusted
in accordance with the Company's Conservation and Load Management Adjustment
Provision as from time to time effective in accordance with law.
Performance Based Rate Adjustment
The amount determined under the preceding provisions shall be adjusted
periodically in accordance with Section 39-1-27.5 of the Rhode Island General
Laws.
STANDARD OFFER SERVICE
Any Customer served under this rate who is eligible for Standard Offer
Service shall receive such service pursuant to the Standard Offer Service
tariff.
LAST RESORT SERVICE
Any Customer served under this rate who does not take its power supply
from a non-regulated power producer and is ineligible for Standard Offer Service
will receive Last Resort Service pursuant to the Last Resort Service tariff.
GROSS EARNINGS TAX
A Rhode Island Gross Earnings Tax adjustment will be applied to the
charges determined above in accordance with Rhode Island General Laws.
GROSS EARNINGS TAX CREDIT FOR MANUFACTURERS
Consistent with the gross receipts tax exemption provided in Section
44-13-35 of Rhode Island General Laws, eligible manufacturing customers will be
exempt from the Gross Earnings Tax to the extent allowed by the Division of
Taxation.
Eligible manufacturing customers are those customers who have on file
with the Company a valid certificate of exemption from the Rhode Island sales
tax (under section 44-18-30(H) of Rhode Island General Laws) indicating the
customer's status as a manufacturer. If the Division of Taxation (or other Rhode
Island taxing authority with jurisdiction) disallows any part or all of the
exemption as it applies to a customer, the custome be required to reimburse the
Company in the amount of the credits provided to such customer which were
disallowed, including any interest required to be paid by the Company to such
authority.
<PAGE>
R.I.P.U.C. No.
Sheet 2
THE NARRAGANSETT ELECTRIC COMPANY
69kV Rate (N-01)
RETAIL DELIVERY SERVICE
DEFINITIONS OF TERMS
"Requirements Service" means that the Company delivers all the energy
and capacity necessary to meet the total electric service requirements of the
Navy, other than electric service requirements provided by electrically isolated
emergency power sources.
"Partial Requirements Service" means Supplementary Service, Backup
Service, and Maintenance Service either individually or in any combination.
"Supplementary Service" means electric energy and capacity delivered
by the Company on a regular basis in addition to that which is normally provided
by the Navy's other power source.
"Backup Service" means electric energy and capacity delivered by the
Company to replace energy and capacity ordinarily provided by the Navy's other
power source during an unscheduled outage of the power source.
"Maintenance Service" means electric energy and capacity delivered by
the Company to replace energy and capacity ordinarily provided by the Navy's
other power source during a scheduled outage of the power source.
TERMS AND CONDITIONS
The Company's Terms and Conditions in effect from time to time, where
not inconsistent with any specific provisions hereof, are a part of this rate.
Effective: April 1, 2000
<PAGE>
Exhibit JMM-13
R.I.P.U.C. No. [[1116]]
Sheet 1
Cancelling R.I.P.U.C. No. [[1074]] [1116]
THE NARRAGANSETT ELECTRIC COMPANY NON-BYPASSABLE
TRANSITION CHARGE ADJUSTMENT PROVISION
The Non-Bypassable Transition Charge shall [[be a pass through of the
cents per kilowatthour contract termination charge that New England Power
Company (NEP) bills to The Narragansett Electric Company (Company). The
Non-Bypassable Transition Charge shall be adjusted each time that NEP's contract
termination charge changes. The Non-Bypassable Transition Charge shall be
computed to the nearest thousandth of a cent.]] [be designed to collect from
customers all Contract Termination Charges billed to the Narragansett Electric
Company (the Company) by the New England Power Company or Montaup Electric
Company. The Non-Bypassable Transition Charge may be subject to adjustment each
time any Contract Termination Charge changes].
Modifications to the Non-Bypassable Transition Charge shall be in
accordance with a notice filed with the Public Utilities Commission (Commission)
setting forth the revised charge and the amount of the increase or decrease. The
notice shall further specify the effective date of the change.
[A Base Transition Charge shall be established at 1.15 cents per
kilowatt-hour and charged to all Customers. In the Blackstone and Newport zones,
Zonal Transition Factors also shall apply. On the Effective Date of this
adjustment provision, the Zonal Transition Factor shall be calculated as the
difference between the Non-Bypassable Transition Charge in effect prior to the
Effective Date of this adjustment provision and the Base Transition Charge.
Effective on January 1, 2001, the Zonal Transition Factors shall be designed to
recover the positive difference, if any, between the amount to be recovered from
Customers through the Base Transition Charge and the total Non-Bypassable
Transition Charge revenues to be recovered. At such time that the Base
Transition Charge recovers the entire cost of Contract Termination Charges or
over collects Contract Termination Charges, the Company may make a filing to
adjust the Base Transition Charge and eliminate the Zonal Transition Factors.
Legend: [ ] = insertion
[[ ]] = deletion
<PAGE>
To the extent that there are any refunds made by New England Power
Company or Montaup Electric Power Company to the Company in connection with
Contract Termination Charges, such refunds shall be applied consistent with the
methodology set forth in Attachment 1.]
On an annual basis, the Company shall reconcile its total cost of
Contract Termination Charges against its total transition charge revenue
(appropriately adjusted to reflect the Rhode Island Gross Receipts Tax), and the
excess or deficiency ("Transition Charge Adjustment Balance") shall be refunded
to, or collected from, customers through the rate recovery/refund methodology
approved by the Commission at the time the Company files its annual
reconciliation. Any positive or negative balance will accrue interest calculated
at the rate in effect for customer deposits.
<PAGE>
Exhibit JMM-13
R.I.P.U.C. No. [[1116]]
Sheet 2
Cancelling R.I.P.U.C. No. [[1074]] [1116]
THE NARRAGANSETT ELECTRIC COMPANY
NON-BYPASSABLE TRANSITION CHARGE
ADJUSTMENT PROVISION
For purposes of the above reconciliation, total transition charge
revenues shall mean all revenue collected from customers through the transition
charges for the applicable reconciliation period. If there is a positive or
negative balance in the then current Transition Charge Adjustment Balance
outstanding from the prior period, the balance shall be credited against or
added to the new reconciliation amount, as appropriate, in establishing the
Transition Charge Adjustment Balance for the new reconciliation period.
The Company shall annually determine the Transition Charge Adjustment
Balance, if any, for the prior calendar year and make a filing with the
Commission. The Company will propose at that time a rate recovery/refund
methodology to recover or refund the balance, as appropriate, over a twelve
month period. The Commission may order the Company to collect or refund the
balance over any reasonable time period from (i) all customers, (ii) only from
those customer classes that underpaid or overpaid transition charges, or (iii)
through any other reasonable method.
This provision is applicable to all Retail Delivery Service rates of
the Company.
Effective [[January 1, 1999]] [April 1, 2000]
3
<PAGE>
Exhibit JMM-13
R.I.P.U.C. No. [[1116]]
Sheet 3
Cancelling R.I.P.U.C. No. [[1074]] [1116]
THE NARRAGANSETT ELECTRIC COMPANY
NON-BYPASSABLE TRANSITION CHARGE ADJUSTMENT PROVISION
[Attachment I]
[Refunds received by the Company in connection with Contract Termination Charges
shall first be applied to offset the deficiency in the Company's deferred tax
reserves in an amount not to exceed the total balance of the deficiency as of
December 31, 2000. If any refunds are received in excess of the revenue
requirement associated with the deficiency, the Commission may order the Company
to refund such amounts to Customers or otherwise use the funds to offset other
charges to Customers.]
<PAGE>
Exhibit JMM-13
R.I.P.U.C. No.[[1054]]
Sheet 1
[Cancelling R.I.P.U.C. No. 1054]
THE NARRAGANSETT ELECTRIC COMPANY
TRANSMISSION SERVICE COST ADJUSTMENT PROVISION
The Transmission Service Cost Adjustment (TCA) shall collect from
customers transmission costs billed to The Narragansett Electric Company
(Narragansett or the Company) by entities such as the New England Power Company,
by any other transmission provider, and by regional transmission entities such
as the New England Power Pool, a regional transmission group, an independent
system operator or any other entity that is authorized to bill Narragansett
Electric directly for transmission services.
[On the Effective Date of this adjustment provision, the TCA shall be
separately determined for the Customers in the Narragansett, Blackstone and
Newport zones to reflect the transmission costs of those companies prior to the
Effective Date as determined by a filing made by the Companies at least 30 days
prior to the Effective Date.]
[Effective on January 1, 2001, t][[T]]he transmission service cost
adjustment shall be a uniform cents per kilowatthour factor applicable to all
kilowatthours delivered by the Company. The factor shall be established
annually based on a forecast of transmission costs, taking into account revenues
that will be received from base rate transmission charges, and shall include a
full reconciliation and adjustment for any over- or under-recoveries of
transmission costs incurred during the prior year. The Company may file to
change the factor adjustment at any time should significant over- or
under-recoveries occur. The reconciliation shall calculate all revenues received
by the Company through the base rate transmission charges and this TCA, compare
these revenues to all transmission costs incurred during the corresponding year,
and pass through the resulting credit or charge, as appropriate, on a uniform
per kWh basis, as provided above.
Modifications to the Transmission Service Cost Adjustment Factor shall
be in accordance with a notice filed with the Public Utilities Commission (the
<PAGE>
Commission) setting forth the amount of the revised factor and the amount of the
increase or decrease. The notice shall further specify the effective date of
such charges.
[Effective April 1, 2000]
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Workpaper JMM-1
Workpaper JMM-1
Blackstone Valley Back-up
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 1 of 29
The Narragansett Electric Company
Shifting BVE Rate R-1 to Narragansett Rate A-16
=============================================================================================================================
BVE Rate R-1 Narragansett Rate A-16
R-1/A-16 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 876,261 $3.09 $2,707,646 876,261 $2.54 $2,225,703
2 Energy Charges:
Distribution Energy 362,568,042 $0.03857 $13,984,249 362,568,042 $0.03680 $13,342,504
Transmission Energy $0.00278 $1,007,939 $0.00307 $1,113,084
Transition Energy $0.02320 $8,411,579 $0.02320 $8,411,579
Standard Offer $0.03800 $13,777,586 $0.03800 $13,777,586
DSM $0.00230 $833,906 $0.00230 $833,906
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $40,722,906 $39,704,361
4 Total Revenue Shift: ($1,018,544)
5 Revenue Shift by Function:
Distribution Revenue ($1,123,689)
Transmission Revenue $105,145
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 2 of 29
The Narragansett Electric Company
Shifting BVE Rate R-2 to Narragansett Rate A-60
=============================================================================================================================
BVE Rate R-2 Narragansett Rate A-60
R-2/A-60 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 25,844 $2.01 $51,946 25,844 $0.00 $0
2 Energy Charges:
Distribution Energy first 300 kWh 6,540,065 $0.00170 $11,118 6,540,065 ($0.00733) ($47,939)
Distribution Energy over 300 kWh 3,924,039 $0.03470 $136,164
Distribution Energy 10,464,104 $0.02362 $247,162
Transmission Energy $0.00278 $29,090 $0.00209 $21,870
Transition Energy $0.02320 $242,767 $0.02320 $242,767
Standard Offer $0.03800 $397,636 $0.03800 $397,636
DSM $0.00230 $24,067 $0.00230 $24,067
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $892,790 $885,564
4 Total Revenue Shift: ($7,225)
5 Revenue Shift by Function:
Distribution Revenue ($5)
Transmission Revenue ($7,220)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 3 of 29
The Narragansett Electric Company
Shifting BVE Rate R-3 to Narragansett Rate A-16
=============================================================================================================================
BVE Rate R-3 Narragansett Rate A-16
R-3/A-16 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 10,622 $2.91 $30,910 10,622 $2.54 $26,980
2 Energy Charges:
Distribution Energy 9,162,722 $0.03200 $293,207 9,162,722 $0.03680 $337,188
Transmission Energy $0.00278 $25,472 $0.00307 $28,130
Transition Energy $0.02320 $212,575 $0.02320 $212,575
Standard Offer $0.03800 $348,183 $0.03800 $348,183
DSM $0.00230 $21,074 $0.00230 $21,074
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $931,422 $974,130
4 Total Revenue Shift: $42,708
5 Revenue Shift by Function:
Distribution Revenue $40,051
Transmission Revenue $2,657
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 4 of 29
The Narragansett Electric Company
Shifting BVE Rate R-4 to Narragansett Rate A-32
=============================================================================================================================
BVE Rate R-4 Narragansett Rate A-32
R-4/A-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 1,821 $4.69 $8,540 1,821 $6.74 $12,274
2 Energy Charges:
Distribution Peak 815,510 $0.11500 $93,784 815,510 $0.02596 $21,171
Distribution Off Peak 3,671,937 $0.01033 $37,931 3,671,937 $0.02596 $95,323
Transmission Energy 4,487,447 $0.00278 $12,475 4,487,447 $0.00263 $11,802
Transition Energy $0.02320 $104,109 $0.02320 $104,109
Standard Offer $0.03800 $170,523 $0.03800 $170,523
DSM $0.00230 $10,321 $0.00230 $10,321
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $437,683 $425,523
4 Total Revenue Shift: ($12,161)
5 Revenue Shift by Function:
Distribution Revenue ($11,488)
Transmission Revenue ($673)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 5 of 29
The Narragansett Electric Company
Shifting BVE Rate W-1 to Narragansett Rate A-16
=============================================================================================================================
BVE Rate W-1 Narragansett Rate A-16
W-1/A-16 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 15,594 $1.32 $20,584 15,594 $0.00 $0
2 Energy Charges:
Distribution Energy 3,568,998 $0.01792 $63,956 3,568,998 $0.03680 $131,339
Transmission Energy $0.00278 $9,922 $0.00307 $10,957
Transition Energy $0.02320 $82,801 $0.02320 $82,801
Standard Offer $0.03800 $135,622 $0.03800 $135,622
DSM $0.00230 $8,209 $0.00230 $8,209
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $321,094 $368,927
4 Total Revenue Shift: $47,834
5 Revenue Shift by Function:
Distribution Revenue $46,799
Transmission Revenue $1,035
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 6 of 29
The Narragansett Electric Company
Shifting BVE Rate W-1 to Narragansett Rate C-06
=============================================================================================================================
BVE Rate W-1 Narragansett Rate C-06
W-1/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge:
Customer Charge 187 $1.32 $247 187 $0.00 $0
Unmetered Charge 0 $0.00 $0
2 Energy Charges:
Distribution Energy 33,373 $0.01792 $598 33,373 $0.03898 $1,301
Transmission Energy $0.00278 $93 $0.00407 $136
Transition Energy $0.02320 $774 $0.02320 $774
Standard Offer $0.03800 $1,268 $0.03800 $1,268
DSM $0.00230 $77 $0.00230 $77
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $3,057 $3,556
4 Total Revenue Shift: $499
5 Revenue Shift by Function:
Distribution Revenue $456
Transmission Revenue $43
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate H1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 7 of 29
The Narragansett Electric Company
Shifting BVE Rate H-1 to Narragansett Rate C-06
======================================================================================================================
BVE Rate H-1 Narragansett Rate C-06
H-1/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
======================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 85 $3.01 $256 85 $5.73 $487
2 Energy Charges:
Distribution Energy 225,822 $0.02975 $6,718 225,822 $0.03898 $8,803
Transmission Energy $0.00278 $628 $0.00407 $919
Transition Energy $0.02320 $5,239 $0.02320 $5,239
Standard Offer $0.03800 $8,581 $0.03800 $8,581
DSM $0.00230 $519 $0.00230 $519
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $21,942 $24,548
4 Total Revenue Shift: $2,607
5 Revenue Shift by Function:
Distribution Revenue $2,316
Transmission Revenue $291
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate H1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 8 of 29
The Narragansett Electric Company
Shifting BVE Rate H-1 to Narragansett Rate G-02
======================================================================================================================
BVE Rate H-1 Narragansett Rate G-02
H-1/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
======================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 104 $3.01 $313 104 $103.41 $10,755
2 Demand Charge:
Distribution Demand 8,848 $0.00 $0 8,848 $2.91 $25,748
Transmission Demand $1.40 $12,387
3 Energy Charges:
Distribution Energy 2,380,400 $0.02975 $70,817 2,380,400 $0.01030 $24,518
Transmission Energy $0.00278 $6,618 ($0.00129) ($3,071)
Transition Energy $0.02320 $55,225 $0.02320 $55,225
Standard Offer $0.03800 $90,455 $0.03800 $90,455
DSM $0.00230 $5,475 $0.00230 $5,475
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $228,903 $221,492
5 Total Revenue Shift: ($7,411)
6 Revenue Shift by Function:
Distribution Revenue ($10,110)
Transmission Revenue $2,699
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate H1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 9 of 29
The Narragansett Electric Company
Shifting BVE Rate H-1 to Narragansett Rate G-32
======================================================================================================================
BVE Rate H-1 Narragansett Rate G-32
H-1/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
======================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 15 $3.01 $45 15 $236.43 $3,546
2 Demand Charge:
Distribution Demand 3,845 $0.00 $0 3,845 $1.56 $5,998
Transmission Demand $1.27 $4,883
3 Energy Charges:
Distribution Energy 1,032,800 $0.02975 $30,726 1,032,800 $0.01139 $11,764
Transmission Energy $0.00278 $2,871 ($0.00129) ($1,332)
Transition Energy $0.02320 $23,961 $0.02320 $23,961
Standard Offer $0.03800 $39,246 $0.03800 $39,246
DSM $0.00230 $2,375 $0.00230 $2,375
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $99,225 $90,442
5 Total Revenue Shift: ($8,783)
6 Revenue Shift by Function:
Distribution Revenue ($9,463)
Transmission Revenue $680
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate H2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 10 of 29
The Narragansett Electric Company
Shifting BVE Rate H-2 to Narragansett Rate C-06
=============================================================================================================================
BVE Rate H-2 Narragansett Rate C-06
H-2/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 940 $3.43 $3,224 940 $0.00 $0
2 Energy Charges:
Distribution Energy 2,034,902 $0.03421 $69,614 2,034,902 $0.03898 $79,320
Transmission Energy $0.00278 $5,657 $0.00407 $8,282
Transition Energy $0.02320 $47,210 $0.02320 $47,210
Standard Offer $0.03800 $77,326 $0.03800 $77,326
DSM $0.00230 $4,680 $0.00230 $4,680
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $207,712 $216,819
4 Total Revenue Shift: $9,107
5 Revenue Shift by Function:
Distribution Revenue $6,482
Transmission Revenue $2,625
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate H2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 11 of 29
The Narragansett Electric Company
Shifting BVE Rate H-2 to Narragansett Rate G-02
=============================================================================================================================
BVE Rate H-2 Narragansett Rate G-02
H-2/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $3.43 $41 12 $0.00 $0
2 Demand Charge:
Distribution Demand 0 $0.00 $0 0 $2.91 $0
Transmission Demand $1.40 $0
3 Energy Charges:
Distribution Energy 33,090 $0.03421 $1,132 33,090 $0.01030 $341
Transmission Energy $0.00278 $92 ($0.00129) ($43)
Transition Energy $0.02320 $768 $0.02320 $768
Standard Offer $0.03800 $1,257 $0.03800 $1,257
DSM $0.00230 $76 $0.00230 $76
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $3,366 $2,399
5 Total Revenue Shift: ($967)
6 Revenue Shift by Function:
Distribution Revenue ($832)
Transmission Revenue ($135)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate H2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 12 of 29
The Narragansett Electric Company
Shifting BVE Rate H-2 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate H-2 Narragansett Rate G-32
H-2/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $3.43 $41 12 $0.00 $0
2 Demand Charge:
Distribution Demand 2,386 $0.00 $0 2,386 $1.56 $3,722
Transmission Demand $1.27 $3,030
3 Energy Charges:
Distribution Energy 222,400 $0.03421 $7,608 222,400 $0.01139 $2,533
Transmission Energy $0.00278 $618 ($0.00129) ($287)
Transition Energy $0.02320 $5,160 $0.02320 $5,160
Standard Offer $0.03800 $8,451 $0.03800 $8,451
DSM $0.00230 $512 $0.00230 $512
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $22,390 $23,122
5 Total Revenue Shift: $731
6 Revenue Shift by Function:
Distribution Revenue ($1,394)
Transmission Revenue $2,125
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate G1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 13 of 29
The Narragansett Electric Company
Shifting BVE Rate G-1 to Narragansett Rate C-06
=============================================================================================================================
BVE Rate G-1 Narragansett Rate C-06
G-1/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge:
Customer Charge 87,619 $3.37 $295,276 85,368 $5.73 $489,159
Unmetered Charge 2,251 $1.83 $4,119
2 Energy Charges:
Distribution Energy 43,670,643 $0.04348 $1,898,800 43,670,643 $0.03898 $1,702,282
Transmission Energy $0.00278 $121,404 $0.00407 $177,740
Transition Energy $0.02320 $1,013,159 $0.02320 $1,013,159
Standard Offer $0.03800 $1,659,484 $0.03800 $1,659,484
DSM $0.00230 $100,442 $0.00230 $100,442
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $5,088,566 $5,146,385
4 Total Revenue Shift: $57,819
5 Revenue Shift by Function:
Distribution Revenue $1,484
Transmission Revenue $56,335
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate G2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 14 of 29
The Narragansett Electric Company
Shifting BVE Rate G-2 to Narragansett Rate C-06
=============================================================================================================================
BVE Rate G-2 Narragansett Rate C-06
G-2/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 17,427 $0.00 $0 17,427 $5.73 $99,857
2 Demand Charge:
Distribution Demand 293,038 $1.50 $439,557 0 $0.00 $0
Transmission Demand $0.00 $0 $0.00 $0
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 55,207,092 $0.02296 $1,267,555 55,207,092 $0.03898 $2,151,972
Transmission Energy $0.00278 $153,476 $0.00407 $224,693
Transition Energy $0.02320 $1,280,805 $0.02320 $1,280,805
Standard Offer $0.03800 $2,097,869 $0.03800 $2,097,869
DSM $0.00230 $126,976 $0.00230 $126,976
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $5,366,238 $5,982,172
5 Total Revenue Shift: $615,934
6 Revenue Shift by Function:
Distribution Revenue $544,717
Transmission Revenue $71,217
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate G2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 15 of 29
The Narragansett Electric Company
Shifting BVE Rate G-2 to Narragansett Rate G-02
=============================================================================================================================
BVE Rate G-2 Narragansett Rate G-02
G-2/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12,852 $0.00 $0 12,852 $103.41 $1,329,025
2 Demand Charge:
Distribution Demand 621,666 $1.50 $932,499 597,149 $2.91 $1,737,704
Transmission Demand $0.00 $0 $1.40 $836,009
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 189,662,772 $0.02296 $4,354,657 189,662,772 $0.01030 $1,953,527
Transmission Energy $0.00278 $527,263 ($0.00129) ($244,665)
Transition Energy $0.02320 $4,400,176 $0.02320 $4,400,176
Standard Offer $0.03800 $7,207,185 $0.03800 $7,207,185
DSM $0.00230 $436,224 $0.00230 $436,224
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $17,858,005 $17,655,185
5 Total Revenue Shift: ($202,820)
6 Revenue Shift by Function:
Distribution Revenue ($266,901)
Transmission Revenue $64,081
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate G2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 16 of 29
The Narragansett Electric Company
Shifting BVE Rate G-2 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate G-2 Narragansett Rate G-32
G-2/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 780 $0.00 $0 780 $236.43 $184,415
2 Demand Charge:
Distribution Demand 226,150 $1.50 $339,225 269,038 $1.56 $419,699
Transmission Demand $0.00 $0 $1.27 $341,678
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 68,985,660 $0.02296 $1,583,911 68,985,660 $0.01139 $785,747
Transmission Energy $0.00278 $191,780 ($0.00129) ($88,992)
Transition Energy $0.02320 $1,600,467 $0.02320 $1,600,467
Standard Offer $0.03800 $2,621,455 $0.03800 $2,621,455
DSM $0.00230 $158,667 $0.00230 $158,667
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $6,495,505 $6,023,138
5 Total Revenue Shift: ($472,368)
6 Revenue Shift by Function:
Distribution Revenue ($533,274)
Transmission Revenue $60,907
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 17 of 29
The Narragansett Electric Company
Shifting BVE Rate T-2 to Narragansett Rate C-06
=============================================================================================================================
BVE Rate T-2 Narragansett Rate C-06
T-2/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 54 $0.00 $0 54 $5.73 $309
2 Demand Charge:
Distribution Demand 707 $1.50 $1,061 1,888 $0.00 $0
Transmission Demand $0.00 $0 $0.00 $0
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 93,312 $0.02296 $2,142 93,312 $0.03898 $3,637
Transmission Energy $0.00278 $259 $0.00407 $380
Transition Energy $0.02320 $2,165 $0.02320 $2,165
Standard Offer On Peak 13,722 $0.03800 $521 $0.03800 $3,546
Standard Offer Off Peak 79,590 $0.03800 $3,024
DSM $0.00230 $215 $0.00230 $215
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $9,388 $10,252
5 Total Revenue Shift: $864
6 Revenue Shift by Function:
Distribution Revenue $744
Transmission Revenue $120
Transition Revenue $0
Standard Offer Revenue ($0)
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 18 of 29
The Narragansett Electric Company
Shifting BVE Rate T-2 to Narragansett Rate G-02
=============================================================================================================================
BVE Rate T-2 Narragansett Rate G-02
T-2/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 551 $0.00 $0 551 $103.41 $56,979
2 Demand Charge:
Distribution Demand 31,864 $1.50 $47,796 24,796 $2.91 $72,156
Transmission Demand $0.00 $0 $1.40 $34,714
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 13,353,435 $0.02296 $306,595 13,353,435 $0.01030 $137,540
Transmission Energy $0.00278 $37,123 ($0.00129) ($17,226)
Transition Energy $0.02320 $309,800 $0.02320 $309,800
Standard Offer On Peak 2,692,710 $0.03800 $102,323 $0.03800 $507,431
Standard Offer Off Peak 10,660,725 $0.03800 $405,108
DSM $0.00230 $30,713 $0.00230 $30,713
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $1,239,457 $1,132,107
5 Total Revenue Shift: ($107,349)
6 Revenue Shift by Function:
Distribution Revenue ($87,715)
Transmission Revenue ($19,634)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 19 of 29
The Narragansett Electric Company
Shifting BVE Rate T-2 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate T-2 Narragansett Rate G-32
T-2/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 251 $0.00 $0 251 $236.43 $59,344
2 Demand Charge:
Distribution Demand 78,241 $1.50 $117,362 99,892 $1.56 $155,832
Transmission Demand $0.00 $0 $1.27 $126,863
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 32,469,660 $0.02296 $745,503 32,469,660 $0.01139 $369,829
Transmission Energy $0.00278 $90,266 ($0.00129) ($41,886)
Transition Energy $0.02320 $753,296 $0.02320 $753,296
Standard Offer On Peak 6,866,980 $0.03800 $260,945 $0.03800 $1,233,847
Standard Offer Off Peak 25,602,680 $0.03800 $972,902
DSM $0.00230 $74,680 $0.00230 $74,680
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $3,014,954 $2,731,805
5 Total Revenue Shift: ($283,149)
6 Revenue Shift by Function:
Distribution Revenue ($277,860)
Transmission Revenue ($5,289)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T4 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 20 of 29
The Narragansett Electric Company
Shifting BVE Rate T-4 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate T-4 Narragansett Rate G-32
T-4/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 372 $0.00 $0 372 $236.43 $87,952
2 Demand Charge:
Distribution Demand 195,414 $1.44 $281,396 225,770 $1.56 $352,201
Transmission Demand $0.00 $0 $1.27 $286,728
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 78,036,479 $0.01625 $1,268,093 78,036,479 $0.01139 $888,835
Transmission Energy $0.00278 $216,941 ($0.00129) ($100,667)
Transition Energy $0.02320 $1,810,446 $0.02320 $1,810,446
Standard Offer On Peak 18,111,219 $0.03800 $688,226 $0.03800 $2,965,386
Standard Offer Off Peak 59,925,260 $0.03800 $2,277,160
DSM $0.00230 $179,484 $0.00230 $179,484
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $6,721,747 $6,470,366
5 Total Revenue Shift: ($251,381)
6 Revenue Shift by Function:
Distribution Revenue ($220,500)
Transmission Revenue ($30,881)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate G5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 21 of 29
The Narragansett Electric Company
Shifting BVE Rate G-5 to Narragansett Rate G-02
=============================================================================================================================
BVE Rate G-5 Narragansett Rate G-02
G-5/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 228 $0.00 $0 228 $103.41 $23,577
2 Demand Charge:
Distribution Demand 20,540 $1.35 $27,729 27,078 $2.91 $78,797
Transmission Demand $0.00 $0 $1.40 $37,909
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 7,714,640 $0.01710 $131,920 7,714,640 $0.01030 $79,461
Transmission Energy $0.00278 $21,447 ($0.00129) ($9,952)
Transition Energy $0.02320 $178,980 $0.02320 $178,980
Standard Offer $0.03800 $293,156 $0.03800 $293,156
DSM $0.00230 $17,744 $0.00230 $17,744
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 27,078 ($0.37) ($10,019)
Primary Metering $699,672 -1% ($6,997)
4 Total Revenue before GET: $670,976 $682,657
5 Total Revenue Shift: $11,681
6 Revenue Shift by Function:
Distribution Revenue $8,559
Transmission Revenue $6,231
Transition Revenue $0
Standard Offer Revenue ($2,932)
DSM ($177)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate G5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 22 of 29
The Narragansett Electric Company
Shifting BVE Rate G-5 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate G-5 Narragansett Rate G-32
G-5/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 166 $0.00 $0 166 $236.43 $39,247
2 Demand Charge:
Distribution Demand 52,600 $1.35 $71,010 58,829 $1.56 $91,773
Transmission Demand $0.00 $0 $1.27 $74,713
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 15,393,940 $0.01710 $263,236 15,393,940 $0.01139 $175,337
Transmission Energy $0.00278 $42,795 ($0.00129) ($19,858)
Transition Energy $0.02320 $357,139 $0.02320 $357,139
Standard Offer $0.03800 $584,970 $0.03800 $584,970
DSM $0.00230 $35,406 $0.00230 $35,406
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 58,829 ($0.37) ($21,767)
Primary Metering $1,338,727 -1% ($13,387)
4 Total Revenue before GET: $1,354,557 $1,303,573
5 Total Revenue Shift: ($50,983)
6 Revenue Shift by Function:
Distribution Revenue ($56,290)
Transmission Revenue $11,511
Transition Revenue $0
Standard Offer Revenue ($5,850)
DSM ($354)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 23 of 29
The Narragansett Electric Company
Shifting BVE Rate T-5 to Narragansett Rate G-02
=============================================================================================================================
BVE Rate T-5 Narragansett Rate G-02
T-5/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 7 $0.00 $0 7 $103.41 $724
2 Demand Charge:
Distribution Demand 358 $1.35 $483 288 $2.91 $838
Transmission Demand $0.00 $0 $1.40 $403
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 114,950 $0.01710 $1,966 114,950 $0.01030 $1,184
Transmission Energy $0.00278 $320 ($0.00129) ($148)
Transition Energy $0.02320 $2,667 $0.02320 $2,667
Standard Offer On Peak 27,650 $0.03800 $1,051 $0.03800 $4,368
Standard Offer Off Peak 87,300 $0.03800 $3,317
DSM $0.00230 $264 $0.00230 $264
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 288 ($0.37) ($107)
Primary Metering $10,300 -1% ($103)
5 Total Revenue before GET: $10,068 $10,091
6 Total Revenue Shift: $23
7 Revenue Shift by Function:
Distribution Revenue $136
Transmission Revenue ($67)
Transition Revenue $0
Standard Offer Revenue ($44)
DSM ($3)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 24 of 29
The Narragansett Electric Company
Shifting BVE Rate T-5 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate T-5 Narragansett Rate G-32
T-5/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 45 $0.00 $0 45 $236.43 $10,639
2 Demand Charge:
Distribution Demand 20,534 $1.35 $27,721 20,534 $1.56 $32,033
Transmission Demand $0.00 $0 $1.27 $26,078
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 8,360,000 $0.01710 $142,956 8,360,000 $0.01139 $95,220
Transmission Energy $0.00278 $23,241 ($0.00129) ($10,784)
Transition Energy $0.02320 $193,952 $0.02320 $193,952
Standard Offer On Peak 1,979,450 $0.03800 $75,219 $0.03800 $317,680
Standard Offer Off Peak 6,380,550 $0.03800 $242,461
DSM $0.00230 $19,228 $0.00230 $19,228
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 20,534 ($0.37) ($7,598)
Primary Metering $684,047 -1% ($6,840)
4 Total Revenue before GET: $724,778 $669,609
5 Total Revenue Shift: ($55,169)
6 Revenue Shift by Function:
Distribution Revenue ($43,700)
Transmission Revenue ($8,100)
Transition Revenue $0
Standard Offer Revenue ($3,177)
DSM ($192)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T6 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 25 of 29
The Narragansett Electric Company
Shifting BVE Rate T-6 to Narragansett Rate G-32
=============================================================================================================================
BVE Rate T-6 Narragansett Rate G-32
T-6/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 656 $0.00 $0 656 $236.43 $155,098
2 Demand Charge:
Distribution Demand 682,889 $1.32 $901,413 782,155 $1.56 $1,220,162
Transmission Demand $0.00 $0 $1.27 $993,337
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 300,621,894 $0.01143 $3,436,108 300,621,894 $0.01139 $3,424,083
Transmission Energy $0.00278 $835,729 ($0.00129) ($387,802)
Transition Energy $0.02320 $6,974,428 $0.02320 $6,974,428
Standard Offer On Peak 66,237,289 $0.03800 $2,517,017 $0.03800 $11,423,632
Standard Offer Off Peak 234,384,605 $0.03800 $8,906,615
DSM $0.00230 $691,430 $0.00230 $691,430
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 782,155 ($0.37) ($289,397)
Primary Metering $24,494,368 -1% ($244,944)
4 Total Revenue before GET: $24,262,741 $23,960,027
5 Total Revenue Shift: ($302,714)
6 Revenue Shift by Function:
Distribution Revenue $54,686
Transmission Revenue ($236,250)
Transition Revenue $0
Standard Offer Revenue ($114,236)
DSM ($6,914)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate T6 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 26 of 29
The Narragansett Electric Company
Shifting BVE Rate T-6 to Narragansett Rate G-62
=============================================================================================================================
BVE Rate T-6 Narragansett Rate G-62
T-6/G-62 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 36 $0.00 $0 36 $17,118.72 $616,274
2 Demand Charge:
Distribution Demand 109,293 $1.32 $144,267 142,198 $0.75 $106,649
Transmission Demand $0.00 $0 $1.39 $197,655
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 69,235,500 $0.01143 $791,362 69,235,500 $0.00434 $300,482
Transmission Energy $0.00278 $192,475 ($0.00129) ($89,314)
Transition Energy $0.02320 $1,606,264 $0.02320 $1,606,264
Standard Offer On Peak 11,791,499 $0.03800 $448,077 $0.03800 $2,630,949
Standard Offer Off Peak 57,444,001 $0.03800 $2,182,872
DSM $0.00230 $159,242 $0.00230 $159,242
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 142,198 ($0.37) ($52,613)
Primary Metering $5,528,200 -1% ($55,282)
4 Total Revenue before GET: $5,524,557 $5,420,305
5 Total Revenue Shift: ($104,253)
6 Revenue Shift by Function:
Distribution Revenue $8,866
Transmission Revenue ($85,217)
Transition Revenue $0
Standard Offer Revenue ($26,309)
DSM ($1,592)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: Rate A6 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 27 of 29
The Narragansett Electric Company
Shifting BVE Rate A-6 to Narragansett Rate B-32
=============================================================================================================================
BVE Rate A-6 Narragansett Rate B-32
A-6/B-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
=============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 48 $14.17 $680 48 $236.43 $11,349
2 Demand Charge:
Distribution Demand 31,497 $2.00 $62,994 31,497 $1.56 $49,135
Transmission Demand $0.00 $0 $1.27 $40,001
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 6,085,455 $0.01425 $86,718 6,085,455 $0.01139 $69,313
Transmission Energy $0.00278 $16,918 ($0.00129) ($7,850)
Transition Energy $0.02320 $141,183 $0.02320 $141,183
Standard Offer On Peak 1,172,792 $0.03800 $44,566 $0.03800 $231,247
Standard Offer Off Peak 4,912,663 $0.03800 $186,681
DSM $0.00230 $13,997 $0.00230 $13,997
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 31,497 ($0.37) ($11,654)
Primary Metering $548,375 -1% ($5,484)
4 Total Revenue before GET: $553,736 $531,237
5 Total Revenue Shift: ($22,499)
6 Revenue Shift by Function:
Distribution Revenue ($34,958)
Transmission Revenue $14,912
Transition Revenue $0
Standard Offer Revenue ($2,312)
DSM ($140)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: BVE BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 28 of 29
Shifting BVE Rate S-1 to Narragansett Rate S-14
Total
Number Annual Annual Annual Distribution Transmission
of Units kWh Price kWh Sales Revenues Revenues
<S> <C> <C> <C> <C> <C> <C>
Overhead $0.00278
Sodium Vapor Lamp
Existing or Prepaid Wood Poles
3300 Streetlight 14 240 $53.29 3,360 $746 $9
5800 Streetlight 10,859 334 $54.80 3,626,906 $595,073 $10,083
5800 Flood 9 334 $67.92 3,006 $611 $8
9500 Streetlight 2,289 476 $56.38 1,089,564 $129,054 $3,029
9500 T&C 3 476 $58.29 1,428 $175 $4
16000 Streetlight 31 692 $58.36 21,452 $1,809 $60
16000 Flood 78 692 $72.14 53,976 $5,627 $150
25000 Streetlight 1,079 1,274 $69.73 1,374,646 $75,239 $3,822
25000 Flood 892 1,274 $77.44 1,136,408 $69,076 $3,159
50000 Streetlight 102 1,966 $80.57 200,532 $8,218 $557
50000 Flood 1,916 1,966 $88.32 3,766,856 $169,221 $10,472
Lighting only Wood Poles
16000 Streetlight 1 692 $140.04 692 $140 $2
16000 Flood 1 692 $154.25 692 $154 $2
25000 Flood 7 1,274 $159.13 8,918 $1,114 $25
50000 Streetlight 1 1,966 $162.28 1,966 $162 $5
50000 Flood 72 1,966 $170.02 141,552 $12,241 $394
Lighting only Metal Poles
25000 Streetlight 24 1,274 $254.90 30,576 $6,118 $85
25000 Flood 1 1,274 $266.39 1,274 $266 $4
50000 Streetlight 1 1,966 $265.71 1,966 $266 $5
50000 Flood 5 1,966 $277.03 9,830 $1,385 $27
Mercury Vapor Lamp
Existing or Prepaid Wood Poles
4200 Streetlight 2,280 511 $44.44 1,165,080 $101,323 $3,239
8600 Streetlight 467 822 $47.05 383,874 $21,972 $1,067
8600 T&C 16 822 $45.87 13,152 $734 $37
22500 Streetlight 105 1,864 $64.97 195,720 $6,822 $544
22500 Flood 99 1,864 $63.52 184,536 $6,288 $513
63000 Flood 23 4,463 $98.19 102,649 $2,258 $285
Lighting only Metal Poles
22500 Streetlight 3 1,864 $198.77 5,592 $596 $16
22500 Flood 2 1,864 $200.07 3,728 $400 $10
Metal Halide Lamp
Existing or Prepaid Wood Poles
20000 Flood 5 1,180 $94.69 5,900 $473 $16
40000 Flood 28 1,832 $124.67 51,296 $3,491 $143
Total Overhead 20,413 13,587,127 $1,221,055 $37,772
Shifting BVE Rate S-1 to Narragansett Rate S-14
Standard Total
Transition Offer DSM Total Annual Annual Annual
Revenues Revenues Revenues Revenues kWh Price kWh Sale
<S> <C> <C> <C> <C> <C> <C> <C>
Overhead $0.02320 $0.03800 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Wood Poles
3300 Streetlight $78 $128 $8 $969 248 $62.78 3,472
5800 Streetlight $84,144 $137,822 $8,342 $835,465 349 $66.28 3,789,791
5800 Flood $70 $114 $7 $811 349 $66.28 3,141
9500 Streetlight $25,278 $41,403 $2,506 $201,270 490 $72.63 1,121,610
9500 T&C $33 $54 $3 $270 490 $72.63 1,470
16000 Streetlight $498 $815 $49 $3,231 490 $72.63 15,190
16000 Flood $1,252 $2,051 $124 $9,204 490 $72.63 38,220
25000 Streetlight $31,892 $52,237 $3,162 $166,350 1284 $120.39 1,385,436
25000 Flood $26,365 $43,184 $2,614 $144,398 1284 $143.14 1,145,328
50000 Streetlight $4,652 $7,620 $461 $21,509 1968 $163.46 200,736
50000 Flood $87,391 $143,141 $8,664 $418,888 1968 $181.37 3,770,688
Lighting only Wood Poles
16000 Streetlight $16 $26 $2 $186 490 $128.08 490
16000 Flood $16 $26 $2 $200 490 $128.08 490
25000 Flood $207 $339 $21 $1,705 1284 $198.59 8,988
50000 Streetlight $46 $75 $5 $293 1968 $218.91 1,968
50000 Flood $3,284 $5,379 $326 $21,624 1968 $236.82 141,696
Lighting only Metal Poles
25000 Streetlight $709 $1,162 $70 $8,144 1284 $429.21 30,816
25000 Flood $30 $48 $3 $351 1284 $451.96 1,284
50000 Streetlight $46 $75 $5 $396 1968 $472.28 1,968
50000 Flood $228 $374 $23 $2,037 1968 $490.19 9,840
Mercury Vapor Lamp
Existing or Prepaid Wood Poles
4200 Streetlight $27,030 $44,273 $2,680 $178,545 561 $54.40 1,279,080
8600 Streetlight $8,906 $14,587 $883 $47,416 908 $70.77 424,036
8600 T&C $305 $500 $30 $1,606 908 $70.77 14,528
22500 Streetlight $4,541 $7,437 $450 $19,794 1897 $122.31 199,185
22500 Flood $4,281 $7,012 $424 $18,520 1897 $152.08 187,803
63000 Flood $2,381 $3,901 $236 $9,062 4569 $262.72 105,087
Lighting only Metal Poles
22500 Streetlight $130 $212 $13 $967 1897 $375.68 5,691
22500 Flood $86 $142 $9 $647 1897 $405.45 3,794
Metal Halide Lamp
Existing or Prepaid Wood Poles
20000 Flood $137 $224 $14 $865 1284 $143.14 6,420
40000 Flood $1,190 $1,949 $118 $6,891 1968 $181.37 55,104
Total Overhead $315,221 $516,311 $31,250 $2,121,610 13,953,350
Standard
Distribution Transmission Transition Offer DSM Total
Revenues Revenues Revenues Revenues Revenues Revenues
<S> <C> <C> <C> <C> <C> <C>
Overhead ($0.04024) $0.00130 $0.02320 $0.03800 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Wood Poles
3300 Streetlight $739 $5 $81 $132 $8 $964
5800 Streetlight $567,233 $4,927 $87,923 $144,012 $8,717 $812,812
5800 Flood $470 $4 $73 $119 $7 $674
9500 Streetlight $121,116 $1,458 $26,021 $42,621 $2,580 $193,797
9500 T&C $159 $2 $34 $56 $3 $254
16000 Streetlight $1,640 $20 $352 $577 $35 $2,625
16000 Flood $4,127 $50 $887 $1,452 $88 $6,604
25000 Streetlight $74,151 $1,801 $32,142 $52,647 $3,187 $163,927
25000 Flood $81,593 $1,489 $26,572 $43,522 $2,634 $155,810
50000 Streetlight $8,595 $261 $4,657 $7,628 $462 $21,603
50000 Flood $195,772 $4,902 $87,480 $143,286 $8,673 $440,113
Lighting only Wood Poles
16000 Streetlight $108 $1 $11 $19 $1 $140
16000 Flood $108 $1 $11 $19 $1 $140
25000 Flood $1,028 $12 $209 $342 $21 $1,611
50000 Streetlight $140 $3 $46 $75 $5 $267
50000 Flood $11,349 $184 $3,287 $5,384 $326 $20,531
Lighting only Metal Poles
25000 Streetlight $9,061 $40 $715 $1,171 $71 $11,058
25000 Flood $400 $2 $30 $49 $3 $483
50000 Streetlight $393 $3 $46 $75 $5 $521
50000 Flood $2,055 $13 $228 $374 $23 $2,693
Mercury Vapor Lamp
Existing or Prepaid Wood Poles
4200 Streetlight $72,562 $1,663 $29,675 $48,605 $2,942 $155,446
8600 Streetlight $15,986 $551 $9,838 $16,113 $975 $43,464
8600 T&C $548 $19 $337 $552 $33 $1,489
22500 Streetlight $4,827 $259 $4,621 $7,569 $458 $17,735
22500 Flood $7,499 $244 $4,357 $7,137 $432 $19,668
63000 Flood $1,814 $137 $2,438 $3,993 $242 $8,623
Lighting only Metal Poles
22500 Streetlight $898 $7 $132 $216 $13 $1,267
22500 Flood $658 $5 $88 $144 $9 $904
Metal Halide Lamp
Existing or Prepaid Wood Poles
20000 Flood $457 $8 $149 $244 $15 $873
40000 Flood $2,861 $72 $1,278 $2,094 $127 $6,432
Total Overhead 1,188,351 $18,139 $323,718 $530,227 $32,093 $2,092,528
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\123data\JAMES\M&A\BASE\Bvepla10.wk4 Narragansett Electric
Range: BVE BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 1
Page 29 of 29
Total
Number Annual Annual Annual Distribution Transmission Transition
of Units kWh Price kWh Sales Revenues Revenues Revenues
<S> <C> <C> <C> <C> <C> <C> <C>
Underground $0.00278 $0.02320
Sodium Vapor Lamp
Existing or Prepaid Standard Metal Poles
16000 Flood 1 692 $83.98 692 $84 $2 $16
25000 Streetlight 4 1,274 $77.37 5,096 $309 $14 $118
25000 Flood 1 1,274 $88.86 1,274 $89 $4 $30
50000 Flood 11 1,966 $99.76 21,626 $1,097 $60 $502
Lighting only Standard Metal Poles
9500 Streetlight 95 476 $227.66 45,220 $21,628 $126 $1,049
9500 PBU 2 952 $283.46 1,904 $567 $5 $44
25000 Streetlight 354 1,274 $240.95 450,996 $85,296 $1,254 $10,463
25000 Streetlight-Twin 16 2,548 $318.71 40,768 $5,099 $113 $946
25000 Flood 18 1,274 $252.43 22,932 $4,544 $64 $532
50000 Streetlight 9 1,966 $251.76 17,694 $2,266 $49 $411
50000 Flood 10 1,966 $263.32 19,660 $2,633 $55 $456
Lighting only Poles less than 15 ft.
5800 T&C 129 334 $148.75 43,086 $19,189 $120 $1,000
9500 T&C 36 476 $150.96 17,136 $5,435 $48 $398
Lighting only Poles greater than 15 ft.
5800 Streetlight 38 334 $215.36 12,692 $8,184 $35 $294
9500 Shoe Box 26 476 $214.01 12,376 $5,564 $34 $287
Lighting only Wood Poles
5800 Streetlight 1 334 $174.47 334 $174 $1 $8
Mercury Vapor Lamp
Lighting only Standard Metal Poles
8600 Streetlight 28 822 $170.78 23,016 $4,782 $64 $534
8600 Streetlight-Twin 18 1,644 $223.65 29,592 $4,026 $82 $687
22500 Streetlight 33 1,864 $188.70 61,512 $6,227 $171 $1,427
22500 Streetlight-Twin 3 3,728 $252.74 11,184 $758 $31 $259
Lighting only Poles less than 15 ft.
8600 T&C 269 822 $109.84 221,118 $29,547 $615 $5,130
Total Underground 1,102 1,059,908 $207,498 $2,947 $24,590
Total Overhead and Underground 21,515 14,647,035 $1,428,554 $40,719 $339,811
Standard Total
Offer DSM Total Annual Annual Annual
Revenues Revenues Revenues kWH Price kWh Sales
<S> <C> <C> <C> <C> <C> <C>
Underground $0.03800 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Standard Metal Poles
16000 Flood $26 $2 $130 980 $145.26 980
25000 Streetlight $194 $12 $647 1284 $120.39 5,136
25000 Flood $48 $3 $173 1284 $143.14 1,284
50000 Flood $822 $50 $2,531 1968 $181.37 21,648
Lighting only Standard Metal Poles
9500 Streetlight $1,718 $104 $24,625 490 $326.00 46,550
9500 PBU $72 $4 $693 1960 $398.63 3,920
25000 Streetlight $17,138 $1,037 $115,188 1284 $373.76 454,536
25000 Streetlight-Twin $1,549 $94 $7,801 2568 $494.15 41,088
25000 Flood $871 $53 $6,064 1284 $396.51 23,112
50000 Streetlight $672 $41 $3,439 1968 $416.83 17,712
50000 Flood $747 $45 $3,936 1968 $434.74 19,680
Lighting only Poles less than 15 ft.
5800 T&C $1,637 $99 $22,044 349 $123.62 45,021
9500 T&C $651 $39 $6,570 490 $129.97 17,640
Lighting only Poles greater than 15 ft.
5800 Streetlight $482 $29 $9,025 349 $123.62 13,262
9500 Shoe Box $470 $28 $6,385 490 $129.97 12,740
Lighting only Wood Poles
5800 Streetlight $13 $1 $197 349 $121.73 349
Mercury Vapor Lamp
Lighting only Standard Metal Poles
8600 Streetlight $875 $53 $6,307 908 $324.14 25,424
8600 Streetlight-Twin $1,124 $68 $5,987 908 $394.91 16,344
22500 Streetlight $2,337 $141 $10,304 1897 $375.68 62,601
22500 Streetlight-Twin $425 $26 $1,499 1897 $557.53 5,691
Lighting only Poles less than 15 ft.
8600 T&C $8,402 $509 $44,203 908 $128.11 244,252
Total Underground $40,277 $2,438 $277,749 1,078,970
Total Overhead and Underground $556,587 $33,688 $2,399,359 $15,032,320
Standard
Distribution Transmission Transition Offer DSM Total
Revenues Revenues Revenues Revenues Revenues Revenues
<S> <C> <C> <C> <C> <C> <C>
Underground ($0.04024) $0.00130 $0.02320 $0.03800 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Standard Metal Poles
16000 Flood $106 $1 $23 $37 $2 $169
25000 Streetlight $275 $7 $119 $195 $12 $608
25000 Flood $91 $2 $30 $49 $3 $175
50000 Flood $1,124 $28 $502 $823 $50 $2,527
Lighting only Standard Metal Poles
9500 Streetlight $29,097 $61 $1,080 $1,769 $107 $32,113
9500 PBU $640 $5 $91 $149 $9 $894
25000 Streetlight $114,021 $591 $10,545 $17,272 $1,045 $143,474
25000 Streetlight-Twin $6,253 $53 $953 $1,561 $95 $8,916
25000 Flood $6,207 $30 $536 $878 $53 $7,705
50000 Streetlight $3,039 $23 $411 $673 $41 $4,186
50000 Flood $3,555 $26 $457 $748 $45 $4,831
Lighting only Poles less than 15 ft.
5800 T&C $14,135 $59 $1,044 $1,711 $104 $17,053
9500 T&C $3,969 $23 $409 $670 $41 $5,112
Lighting only Poles greater than 15 ft.
5800 Streetlight $4,164 $17 $308 $504 $31 $5,023
9500 Shoe Box $2,867 $17 $296 $484 $29 $3,692
Lighting only Wood Poles
5800 Streetlight $108 $0 $8 $13 $1 $130
Mercury Vapor Lamp
Lighting only Standard Metal Poles
8600 Streetlight $8,053 $33 $590 $966 $58 $9,700
8600 Streetlight-Twin $6,451 $21 $379 $621 $38 $7,510
22500 Streetlight $9,878 $81 $1,452 $2,379 $144 $13,935
22500 Streetlight-Twin $1,444 $7 $132 $216 $13 $1,812
Lighting only Poles less than 15 ft.
8600 T&C $24,633 $318 $5,667 $9,282 $562 $40,460
Total Underground $240,108 $1,403 $25,032 $41,001 $2,482 $310,026
Total Overhead and Underground $1,428,459 $19,542 $348,750 $571,228 $34,574 $2,402,553
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate A16 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 1 of 14
The Narragansett Electric Company
Rate A-16
===========================================================================================================================
Pre Merger Rate A-16 Post Merger Rate A-16
A-16 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 3,087,617 $2.54 $7,842,547 3,087,617 $2.54 $7,842,547
2 Energy Charges:
Distribution Energy 1,475,595,371 $0.03680 $54,301,910 1,475,595,371 $0.03680 $54,301,910
Transmission Energy $0.00515 $7,599,316 $0.00515 $7,599,316
Transition Energy $0.01150 $16,969,347 $0.01150 $16,969,347
Standard Offer $0.03800 $56,072,624 $0.03800 $56,072,624
DSM $0.00230 $3,393,869 $0.00230 $3,393,869
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $146,179,613 $146,179,613
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate A18 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 2 of 14
The Narragansett Electric Company
Rate A-18
===========================================================================================================================
Pre Merger Rate A-18 Post Merger Rate A-18
A-18 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 366,803 $2.52 $924,344 366,803 $2.52 $924,344
2 Energy Charges:
Distribution Energy 299,522,556 $0.03602 $10,788,802 299,522,556 $0.03602 $10,788,802
Transmission Energy $0.00466 $1,395,775 $0.00466 $1,395,775
Transition Energy $0.01150 $3,444,509 $0.01150 $3,444,509
Standard Offer $0.03800 $11,381,857 $0.03800 $11,381,857
DSM $0.00230 $688,902 $0.00230 $688,902
Water Heater Credit 210,516,280 ($0.00661) ($1,391,513) 210,516,280 ($0.00661) ($1,391,513)
3 Total Revenue before GET: $27,232,677 $27,232,677
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate A32 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 3 of 14
The Narragansett Electric Company
Rate A-32
===========================================================================================================================
Pre Merger Rate A-32 Post Merger Rate A-32
A-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 11,757 $6.74 $79,242 11,757 $6.74 $79,242
2 Energy Charges:
Distribution Energy 33,569,784 $0.02596 $871,472 33,569,784 $0.02596 $871,472
Transmission Energy $0.00471 $158,114 $0.00471 $158,114
Transition Energy $0.01150 $386,053 $0.01150 $386,053
Standard Offer On Peak 7,649,055 $0.03800 $290,664 7,649,055 $0.03800 $290,664
Standard Offer Off Peak 25,920,729 $0.03800 $984,988 25,920,729 $0.03800 $984,988
DSM $0.00230 $77,211 $0.00230 $77,211
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $2,847,742 $2,847,742
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate A60 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 4 of 14
The Narragansett Electric Company
Rate A-60
===========================================================================================================================
Pre Merger Rate A-60 Post Merger Rate A-60
A-60 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 100,072 $0.00 $0 100,072 $0.00 $0
2 Energy Charges:
Distribution Energy 45,194,386 $0.02362 $1,067,491 45,194,386 $0.02362 $1,067,491
Transmission Energy $0.00417 $188,461 $0.00417 $188,461
Transition Energy $0.01150 $519,735 $0.01150 $519,735
Standard Offer $0.03800 $1,717,387 $0.03800 $1,717,387
DSM $0.00230 $103,947 $0.00230 $103,947
Water Heater Credit 3,667,794 ($0.00661) ($24,244) 3,667,794 ($0.00661) ($24,244)
3 Total Revenue before GET: $3,572,777 $3,572,777
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate C06 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 5 of 14
The Narragansett Electric Company
Rate C-06
===========================================================================================================================
Pre Merger Rate C-06 Post Merger Rate C-06
C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge:
Customer Charge 327,918 $5.73 $1,878,970 327,918 $5.73 $1,878,970
Unmetered Charge 7,927 $1.83 $14,506 7,927 $1.83 $14,506
2 Energy Charges:
Distribution Energy 319,448,478 $0.03898 $12,452,102 319,448,478 $0.03898 $12,452,102
Transmission Energy $0.00615 $1,964,608 $0.00615 $1,964,608
Transition Energy $0.01150 $3,673,657 $0.01150 $3,673,657
Standard Offer $0.03800 $12,139,042 $0.03800 $12,139,042
DSM $0.00230 $734,731 $0.00230 $734,731
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $32,857,618 $32,857,618
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate E30 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 6 of 14
The Narragansett Electric Company
Rate E-30
====================================================================================================================
Pre Merger Rate E-30 Post Merger Rate E-30
E-30 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
====================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 173 $7.54 $1,304 173 $7.54 $1,304
2 Energy Charges:
Distribution Energy 1,519,157 $0.01620 $24,610 1,519,157 $0.01620 $24,610
Transmission Energy $0.00340 $5,165 $0.00340 $5,165
Transition Energy $0.01150 $17,470 $0.01150 $17,470
Standard Offer $0.03800 $57,728 $0.03800 $57,728
DSM $0.00230 $3,494 $0.00230 $3,494
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $109,772 $109,772
4 Total Revenue Shift: ($0)
5 Revenue Shift by Function:
Distribution Revenue ($0)
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate E40 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 7 of 14
The Narragansett Electric Company
Rate E-40
===========================================================================================================================
Pre Merger Rate E-40 Post Merger Rate E-40
E-40 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 254 $75.15 $19,088 254 $75.15 $19,088
2 Energy Charges:
Distribution On/Shoulder Energy 3,706,802 $0.02574 $95,413 3,706,802 $0.02574 $95,413
Distribution Off Peak Energy 8,729,522 $0.00987 $86,160 8,729,522 $0.00987 $86,160
Transmission Energy $0.00220 $27,360 $0.00220 $27,360
Transition Energy $0.01150 $143,018 $0.01150 $143,018
Standard Offer $0.03800 $472,580 $0.03800 $472,580
DSM $0.00230 $28,604 $0.00230 $28,604
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $872,223 $872,223
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate G02 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 8 of 14
The Narragansett Electric Company
Rate G-02
===========================================================================================================================
Pre Merger Rate G-02 Post Merger Rate G-02
G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 72,380 $103.41 $7,484,816 72,380 $103.41 $7,484,816
2 Demand Charge:
Distribution Demand 2,388,026 $2.91 $6,949,156 2,388,026 $2.91 $6,949,156
Transmission Demand $1.40 $3,343,236 $1.40 $3,343,236
3 Energy Charges:
Distribution Energy 857,825,162 $0.01030 $8,835,599 857,825,162 $0.01030 $8,835,599
Transmission Energy $0.00079 $677,682 $0.00079 $677,682
Transition Energy $0.01150 $9,864,989 $0.01150 $9,864,989
Standard Offer $0.03800 $32,597,356 $0.03800 $32,597,356
DSM $0.00230 $1,972,998 $0.00230 $1,972,998
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $71,725,832 $71,725,832
5 Total Revenue Shift: $0
6 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate G32 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 9 of 14
The Narragansett Electric Company
Rate G-32
===========================================================================================================================
Pre Merger Rate G-32 Post Merger Rate G-32
G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 8,554 $236.43 $2,022,422 8,554 $236.43 $2,022,422
2 Demand Charge:
Distribution Demand 4,100,824 $1.56 $6,397,285 4,100,824 $1.56 $6,397,285
Transmission Demand $1.27 $5,208,046 $1.27 $5,208,046
3 Energy Charges:
Distribution Energy 1,497,395,176 $0.01139 $17,055,331 1,497,395,176 $0.01139 $17,055,331
Transmission Energy $0.00079 $1,182,942 $0.00079 $1,182,942
Transition Energy $0.01150 $17,220,045 $0.01150 $17,220,045
Standard Offer $0.03800 $56,901,017 $0.03800 $56,901,017
DSM $0.00230 $3,444,009 $0.00230 $3,444,009
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 799,345 ($0.37) ($295,758) 799,345 ($0.37) ($295,758)
Primary Metering $109,431,098 -1% ($1,094,311) $109,431,098 -1% ($1,094,311)
5 Total Revenue before GET: $108,041,029 $108,041,029
6 Total Revenue Shift: $0
7 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate G62 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 10 of 14
The Narragansett Electric Company
Rate G-62
===========================================================================================================================
Pre Merger Rate G-62 Post Merger Rate G-62
G-62 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 84 $17,118.72 $1,437,972 84 $17,118.72 $1,437,972
2 Demand Charge:
Distribution Demand 631,081 $0.75 $473,311 631,081 $0.75 $473,311
Transmission Demand $1.56 $984,486 $1.56 $984,486
3 Energy Charges:
Distribution Energy 360,114,300 $0.00434 $1,562,896 360,114,300 $0.00434 $1,562,896
Transmission Energy $0.00079 $284,490 $0.00079 $284,490
Transition Energy $0.01150 $4,141,314 $0.01150 $4,141,314
Standard Offer $0.03800 $13,684,343 $0.03800 $13,684,343
DSM $0.00230 $828,263 $0.00230 $828,263
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 349,366 ($0.37) ($129,265) 349,366 ($0.37) ($129,265)
Primary Metering $23,397,077 -1% ($233,971) $23,397,077 -1% ($233,971)
5 Total Revenue before GET: $23,033,841 $23,033,841
6 Total Revenue Shift: $0
7 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate R02 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 11 of 14
The Narragansett Electric Company
Rate R-02
===========================================================================================================================
Pre Merger Rate R-02 Post Merger Rate R-02
R-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 7,642 $0.00 $0 7,642 $0.00 $0
2 Energy Charges:
Distribution Energy 4,803,789 $0.00905 $43,474 4,803,789 $0.00905 $43,474
Transmission Energy $0.00338 $16,237 $0.00338 $16,237
Transition Energy $0.01150 $55,244 $0.01150 $55,244
Standard Offer $0.03800 $182,544 $0.03800 $182,544
DSM $0.00230 $11,049 $0.00230 $11,049
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $308,547 $308,547
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\JMM\[worjmm2a.wk4]A Narragansett Electric
STREETLIGHTS BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 12 of 14
The Narragansett Electric Company
Normalized Streetlight Revenue
==================================================================================================================================
Pre-merger Rate Streetlights
Lumen Annual Standard
Code Rate kWh Units kWh Sales Distribution DSM Transmission Transition Offer Total
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
$0.00434 $0.00230 $0.00338 $0.01150 $0.03800
INCANDESCENT
1,000 10 $75.22 440 107 47,080 $8,253 $108 $159 $541 $1,789 $10,851
1,000 50 $75.22 440 4 1,760 $309 $4 $6 $20 $67 $406
2,500 11 $67.45 845 3 2,535 $213 $6 $9 $29 $96 $353
MERCURY VAPOR
8,000 (Post Top) 2 $108.85 908 23 20,884 $2,594 $48 $71 $240 $794 $3,747
4,000 3 $58.40 561 6,614 3,710,454 $402,361 $8,534 $12,541 $42,670 $140,997 $607,104
8,000 4 $70.77 908 1,792 1,627,136 $133,882 $3,742 $5,500 $18,712 $61,831 $223,667
15,000 (Providence) 17 $122.97 1,874 115 215,510 $15,077 $496 $728 $2,478 $8,189 $26,969
15,000 (Outside) 18 $122.97 1,874 114 213,636 $14,946 $491 $722 $2,457 $8,118 $26,734
22,000 5 $122.31 1,897 2,201 4,175,297 $287,325 $9,603 $14,113 $48,016 $158,661 $517,718
22,000 - 24 HR. 64 $222.87 3,794 0 $0 $0 $0 $0 $0 $0
63,000 6 $234.25 4,569 116 530,004 $29,473 $1,219 $1,791 $6,095 $20,140 $58,719
Flood lights
22,000 23 $152.08 1,897 910 1,726,270 $145,885 $3,970 $5,835 $19,852 $65,598 $241,140
63,000 24 $262.72 4,569 588 2,686,572 $166,139 $6,179 $9,081 $30,896 $102,090 $314,384
SODIUM VAPOR
4,000 70 $62.78 248 24,157 5,990,936 $1,542,577 $13,779 $20,249 $68,896 $227,656 $1,873,15
4,000 750 $62.78 248 248 61,504 $15,836 $141 $208 $707 $2,337 $19,230
4,000 755 $62.78 248 2,411 597,928 $153,958 $1,375 $2,021 $6,876 $22,721 $186,951
4,000 756 $62.78 248 458 113,584 $29,246 $261 $384 $1,306 $4,316 $35,514
4,000 711 $62.78 248 248 61,504 $15,836 $141 $208 $707 $2,337 $19,230
4,000 710 $62.78 248 10,698 2,653,104 $683,135 $6,102 $8,967 $30,511 $100,818 $829,533
5,800 71 $66.28 349 385 134,365 $26,101 $309 $454 $1,545 $5,106 $33,515
9,600 72 $72.63 490 11,786 5,775,140 $881,081 $13,283 $19,520 $66,414 $219,455 $1,199,75
27,500 74 $120.39 1,284 12,641 16,231,044 $1,592,293 $37,331 $54,861 $186,657 $616,780 $2,487,92
27,500(24 HR) 84 $172.21 2,568 0 $0 $0 $0 $0 $0 $0
50,000 75 $163.46 1,968 466 917,088 $80,153 $2,109 $3,100 $10,547 $34,849 $130,757
50,000 (Flood) 78 $181.37 1,968 718 1,413,024 $136,356 $3,250 $4,776 $16,250 $53,695 $214,327
27,500 (Flood) 77 $143.14 1,284 298 382,632 $44,316 $880 $1,293 $4,400 $14,540 $65,430
9,600 (Post top) 79 $78.56 490 490 240,100 $39,536 $552 $812 $2,761 $9,124 $52,785
UNDERGROUND
Providence (In) / (Out) $110.86 3,298 $365,616 $365,616
Wood Poles P $55.45 32 $1,774 $1,774
Fiberglass without base R $57.34 368 $21,101 $21,101
Fiberglass with base < 25 f C $111.04 $0 $0
Fiberglass with base >= 25 D $185.67 $0 $0
Metal Poles with base T $253.37 204 $51,687 $51,687
Total 49,529,091 $6,887,061 $113,917 $167,408 $569,585 $1,882,105 $9,620,076
==================================================================================================================================
Post-merger Streetlights
Standard
Distribution DSM Transmission Transition Offer Total
==================================================================================================================================
$0.00434 $0.00230 $0.00338 $0.01150 $0.03800
INCANDESCENT
1,000 $8,253 $108 $159 $541 $1,789 $10,851
1,000 $309 $4 $6 $20 $67 $406
2,500 $213 $6 $9 $29 $96 $353
MERCURY VAPOR
8,000 (Post Top) $2,594 $48 $71 $240 $794 $3,747
4,000 $402,361 $8,534 $12,541 $42,670 $140,997 $607,104
8,000 $133,882 $3,742 $5,500 $18,712 $61,831 $223,667
15,000 (Providence) $15,077 $496 $728 $2,478 $8,189 $26,969
15,000 (Outside) $14,946 $491 $722 $2,457 $8,118 $26,734
22,000 $287,325 $9,603 $14,113 $48,016 $158,661 $517,718
22,000 - 24 HR. $0 $0 $0 $0 $0 $0
63,000 $29,473 $1,219 $1,791 $6,095 $20,140 $58,719
Flood lights
22,000 $145,885 $3,970 $5,835 $19,852 $65,598 $241,140
63,000 $166,139 $6,179 $9,081 $30,896 $102,090 $314,384
SODIUM VAPOR
4,000 $1,542,577 $13,779 $20,249 $68,896 $227,656 $1,873,157
4,000 $15,836 $141 $208 $707 $2,337 $19,230
4,000 $153,958 $1,375 $2,021 $6,876 $22,721 $186,951
4,000 $29,246 $261 $384 $1,306 $4,316 $35,514
4,000 $15,836 $141 $208 $707 $2,337 $19,230
4,000 $683,135 $6,102 $8,967 $30,511 $100,818 $829,533
5,800 $26,101 $309 $454 $1,545 $5,106 $33,515
9,600 $881,081 $13,283 $19,520 $66,414 $219,455 $1,199,754
27,500 $1,592,293 $37,331 $54,861 $186,657 $616,780 $2,487,922
27,500(24 HR) $0 $0 $0 $0 $0 $0
50,000 $80,153 $2,109 $3,100 $10,547 $34,849 $130,757
50,000 (Flood) $136,356 $3,250 $4,776 $16,250 $53,695 $214,327
27,500 (Flood) $44,316 $880 $1,293 $4,400 $14,540 $65,430
9,600 (Post top) $39,536 $552 $812 $2,761 $9,124 $52,785
UNDERGROUND
Providence (In) / (Out) $365,616 $365,616
Wood Poles $1,774 $1,774
Fiberglass without base $21,101 $21,101
Fiberglass with base < 25 f $0 $0
Fiberglass with base >= 25 $0 $0
Metal Poles with base $51,687 $51,687
Total $6,887,061 $113,917 $167,408 $569,585 $1,882,106 $9,620,076
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate T06 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 13 of 14
The Narragansett Electric Company
Rate T-06
===========================================================================================================================
Pre Merger Rate T-06 Post Merger Rate T-06
T-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 4,739 $7.84 $37,154 4,739 $7.84 $37,154
2 Energy Charges:
Distribution Energy 21,835,478 $0.02285 $498,941 21,835,478 $0.02285 $498,941
Transmission Energy $0.00440 $96,076 $0.00440 $96,076
Transition Energy $0.01150 $251,108 $0.01150 $251,108
Standard Offer $0.03800 $829,748 $0.03800 $829,748
DSM $0.00230 $50,222 $0.00230 $50,222
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $1,763,248 $1,763,248
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm2.wk4]Rate V02 Narragansett Electric
Range: STREETLIGHTS BVE/Newport Electric
Date: 31-Jul-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 2
Page 14 of 14
The Narragansett Electric Company
Rate V-02
===========================================================================================================================
Pre Merger Rate V-02 Post Merger Rate V-02
V-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 4,553 $7.85 $35,741 4,553 $7.85 $35,741
2 Energy Charges:
Distribution Energy 7,686,406 $0.03076 $236,434 7,686,406 $0.03076 $236,434
Transmission Energy $0.00626 $48,117 $0.00626 $48,117
Transition Energy $0.01150 $88,394 $0.01150 $88,394
Standard Offer $0.03800 $292,083 $0.03800 $292,083
DSM $0.00230 $17,679 $0.00230 $17,679
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $718,448 $718,448
4 Total Revenue Shift: $0
5 Revenue Shift by Function:
Distribution Revenue $0
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. __________
Workpaper JMM-3
Workpaper JMM-3
Newport Back-up
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate R1 Narragansett Electric
Range: Rate R1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 1 of 26
The Narragansett Electric Company
Shifting NEC Rate R-1 to Narragansett Rate A-16
===================================================================================================================================
NEC Rate R-1 Narragansett Rate A-16
R-1/A-16 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 325,773 $3.10 $1,009,896 325,773 $2.54 $827,463
2 Energy Charges:
Distribution Energy 167,201,036 $0.04653 $7,779,864 167,201,036 $0.04341 $7,258,197
Transmission Energy $0.00273 $456,459 $0.00300 $501,603
Transition Energy $0.02340 $3,912,504 $0.02340 $3,912,504
Standard Offer $0.03800 $6,353,639 $0.03800 $6,353,639
DSM $0.00230 $384,562 $0.00230 $384,562
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $19,896,925 $19,237,969
4 Total Revenue Shift: ($658,956)
5 Revenue Shift by Function:
Distribution Revenue ($704,100)
Transmission Revenue $45,144
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate R2 Narragansett Electric
Range: Rate R2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 2 of 26
The Narragansett Electric Company
Shifting NEC Rate R-2 to Narragansett Rate A-60
==================================================================================================================================
NEC Rate R-2 Narragansett Rate A-60
R-2/A-60 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 4,208 $2.14 $9,005 4,208 $0.00 $0
2 Energy Charges:
Distribution Energy first 300 kWh 1,055,362 $0.00759 $8,010 1,055,362 ($0.00616) (6,501)
Distribution Energy over 300 kWh 709,457 $0.04206 $29,840
Distribution Energy 1,764,819 $0.03023 $53,350
Transmission Energy $0.00273 $4,818 $0.00202 $3,565
Transition Energy $0.02340 $41,297 $0.02340 $41,297
Standard Offer $0.03800 $67,063 $0.03800 $67,063
DSM $0.00230 $4,059 $0.00230 $4,059
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $164,092 $162,833
4 Total Revenue Shift: ($1,259)
5 Revenue Shift by Function:
Distribution Revenue ($6)
Transmission Revenue ($1,253)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate R4 Narragansett Electric
Range: Rate R4 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 3 of 26
The Narragansett Electric Company
Shifting NEC Rate R-4 to Narragansett Rate A-32
==================================================================================================================================
NEC Rate R-4 Narragansett Rate A-32
R-4/A-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 2,504 $6.78 $16,977 2,504 $6.74 $16,877
2 Energy Charges:
Distribution Peak 1,248,828 $0.11000 $137,371 1,248,828 $0.03257 $40,674
Distribution Off Peak 5,852,163 $0.03109 $181,944 5,852,163 $0.03257 $190,605
Transmission Energy 7,100,991 $0.00273 $19,386 7,100,991 $0.00256 $18,179
Transition Energy $0.02340 $166,163 $0.02340 $166,163
Standard Offer $0.03800 $269,838 $0.03800 $269,838
DSM $0.00230 $16,332 $0.00230 $16,332
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $808,011 $718,668
4 Total Revenue Shift: ($89,343)
5 Revenue Shift by Function:
Distribution Revenue ($88,136)
Transmission Revenue ($1,207)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate W1 Narragansett Electric
Range: Rate W1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 4 of 26
The Narragansett Electric Company
Shifting NEC Rate W-1 to Narragansett Rate A-16
==================================================================================================================================
NEC Rate W-1 Narragansett Rate A-16
W-1/A-16 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 63,065 $3.29 $207,484 63,065 $0.00 $0
2 Energy Charges:
Distribution Energy 13,062,846 $0.02399 $313,378 13,062,846 $0.04341 $567,058
Transmission Energy $0.00273 $35,662 $0.00300 $39,189
Transition Energy $0.02340 $305,671 $0.02340 $305,671
Standard Offer $0.03800 $496,388 $0.03800 $496,388
DSM $0.00230 $30,045 $0.00230 $30,045
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $1,388,626 $1,438,350
4 Total Revenue Shift: $49,724
5 Revenue Shift by Function:
Distribution Revenue $46,197
Transmission Revenue $3,527
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate W1 Narragansett Electric
Range: Rate W1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 5 of 26
The Narragansett Electric Company
Shifting NEC Rate W-1 to Narragansett Rate C-06
==================================================================================================================================
NEC Rate W-1 Narragansett Rate C-06
W-1/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge:
Customer Charge 1,303 $3.29 $4,287 1,303 $0.00 $0
Unmetered Charge 0 $0.00 $0
2 Energy Charges:
Distribution Energy 313,931 $0.02399 $7,531 313,931 $0.04559 $14,312
Transmission Energy $0.00273 $857 $0.00400 $1,256
Transition Energy $0.02340 $7,346 $0.02340 $7,346
Standard Offer $0.03800 $11,929 $0.03800 $11,929
DSM $0.00230 $722 $0.00230 $722
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $32,673 $35,565
4 Total Revenue Shift: $2,893
5 Revenue Shift by Function:
Distribution Revenue $2,494
Transmission Revenue $399
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate W1 Narragansett Electric
Range: Rate W1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 6 of 26
The Narragansett Electric Company
Shifting NEC Rate W-1 to Narragansett Rate G-02
==================================================================================================================================
NEC Rate W-1 Narragansett Rate G-02
W-1/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 40 $3.29 $132 40 $0.00 $0
2 Demand Charge:
Distribution Demand 0 $0.00 $0 0 $2.91 $0
Transmission Demand $1.40 $0
3 Energy Charges:
Distribution Energy 6,491 $0.02399 $156 6,491 $0.01691 $110
Transmission Energy $0.00273 $18 ($0.00136) ($9)
Transition Energy $0.02340 $152 $0.02340 $152
Standard Offer $0.03800 $247 $0.03800 $247
DSM $0.00230 $15 $0.00230 $15
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $719 $514
5 Total Revenue Shift: ($204)
6 Revenue Shift by Function:
Distribution Revenue ($178)
Transmission Revenue ($27)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate H1 Narragansett Electric
Range: Rate H1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 7 of 26
The Narragansett Electric Company
Shifting NEC Rate H-1 to Narragansett Rate C-06
==============================================================================================================================
NEC Rate H-1 Narragansett Rate C-06
H-1/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 36 $12.03 $433 36 $5.73 $206
2 Energy Charges:
Distribution Energy 146,940 $0.03968 $5,831 146,940 $0.04559 $6,699
Transmission Energy $0.00273 $401 $0.00400 $588
Transition Energy $0.02340 $3,438 $0.02340 $3,438
Standard Offer $0.03800 $5,584 $0.03800 $5,584
DSM $0.00230 $338 $0.00230 $338
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $16,025 $16,853
4 Total Revenue Shift: $828
5 Revenue Shift by Function:
Distribution Revenue $642
Transmission Revenue $187
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate H1 Narragansett Electric
Range: Rate H1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 8 of 26
The Narragansett Electric Company
Shifting NEC Rate H-1 to Narragansett Rate G-02
==============================================================================================================================
NEC Rate H-1 Narragansett Rate G-02
H-1/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==============================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 179 $12.03 $2,153 179 $103.41 $18,510
2 Demand Charge:
Distribution Demand 7,866 $0.00 $0 7,866 $2.91 $22,890
Transmission Demand $1.40 $11,012
3 Energy Charges:
Distribution Energy 3,203,948 $0.03968 $127,133 3,203,948 $0.01691 $54,179
Transmission Energy $0.00273 $8,747 ($0.00136) ($4,357)
Transition Energy $0.02340 $74,972 $0.02340 $74,972
Standard Offer $0.03800 $121,750 $0.03800 $121,750
DSM $0.00230 $7,369 $0.00230 $7,369
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $342,124 $306,326
5 Total Revenue Shift: ($35,799)
6 Revenue Shift by Function:
Distribution Revenue ($33,707)
Transmission Revenue ($2,092)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate H1 Narragansett Electric
Range: Rate H1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 9 of 26
The Narragansett Electric Company
Shifting NEC Rate H-1 to Narragansett Rate G-32
===========================================================================================================================
NEC Rate H-1 Narragansett Rate G-32
H-1/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $12.03 $144 12 $236.43 $2,837
2 Demand Charge:
Distribution Demand 5,202 $0.00 $0 5,202 $1.56 $8,115
Transmission Demand $1.27 $6,607
3 Energy Charges:
Distribution Energy 1,557,600 $0.03968 $61,806 1,557,600 $0.01800 $28,037
Transmission Energy $0.00273 $4,252 ($0.00136) ($2,118)
Transition Energy $0.02340 $36,448 $0.02340 $36,448
Standard Offer $0.03800 $59,189 $0.03800 $59,189
DSM $0.00230 $3,582 $0.00230 $3,582
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $165,421 $142,696
5 Total Revenue Shift: ($22,725)
6 Revenue Shift by Function:
Distribution Revenue ($22,961)
Transmission Revenue $236
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate H2 Narragansett Electric
Range: Rate H2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 10 of 26
The Narragansett Electric Company
Shifting NEC Rate H-2 to Narragansett Rate C-06
==================================================================================================================================
NEC Rate H-2 Narragansett Rate C-06
H-2/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 3,752 $4.59 $17,222 3,752 $0.00 $0
2 Energy Charges:
Distribution Energy 4,457,199 $0.04681 $208,641 4,457,199 $0.04559 $203,204
Transmission Energy $0.00273 $12,168 $0.00400 $17,829
Transition Energy $0.02340 $104,298 $0.02340 $104,298
Standard Offer $0.03800 $169,374 $0.03800 $169,374
DSM $0.00230 $10,252 $0.00230 $10,252
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $521,955 $504,956
4 Total Revenue Shift: ($16,999)
5 Revenue Shift by Function:
Distribution Revenue ($22,659)
Transmission Revenue $5,661
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate H2 Narragansett Electric
Range: Rate H2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 11 of 26
The Narragansett Electric Company
Shifting NEC Rate H-2 to Narragansett Rate G-02
==================================================================================================================================
NEC Rate H-2 Narragansett Rate G-02
H-2/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 113 $4.59 $519 113 $0.00 $0
2 Demand Charge:
Distribution Demand 5,208 $0.00 $0 5,208 $2.91 $15,156
Transmission Demand $1.40 $7,292
3 Energy Charges:
Distribution Energy 1,266,751 $0.04681 $59,297 1,266,751 $0.01691 $21,421
Transmission Energy $0.00273 $3,458 ($0.00136) ($1,723)
Transition Energy $0.02340 $29,642 $0.02340 $29,642
Standard Offer $0.03800 $48,137 $0.03800 $48,137
DSM $0.00230 $2,914 $0.00230 $2,914
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $143,966 $122,838
5 Total Revenue Shift: ($21,127)
6 Revenue Shift by Function:
Distribution Revenue ($23,238)
Transmission Revenue $2,111
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate H2 Narragansett Electric
Range: Rate G1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 12 of 26
The Narragansett Electric Company
Shifting NEC Rate G-1 to Narragansett Rate C-06
==================================================================================================================================
NEC Rate H-2 Narragansett Rate C-06
G-1/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge:
Customer Charge 48,861 $3.45 $168,570 47,123 $5.73 $270,015
Unmetered Charge 1,738 $1.83 $3,181
2 Energy Charges:
Distribution Energy 42,449,011 $0.05832 $2,475,626 42,449,011 $0.04559 $1,935,250
Transmission Energy $0.00273 $115,886 $0.00400 $169,796
Transition Energy $0.02340 $993,307 $0.03800 $993,307
Standard Offer $0.03800 $1,613,062 $0.03800 $1,613,062
DSM $0.00230 $97,633 $0.00230 $97,633
Renewables $0.00000 $0 $0.00000 $0
3 Total Revenue before GET: $5,464,085 $5,082,244
4 Total Revenue Shift: ($381,841)
5 Revenue Shift by Function:
Distribution Revenue ($435,751)
Transmission Revenue $53,910
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate G2 Narragansett Electric
Range: Rate G2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 13 of 26
The Narragansett Electric Company
Shifting NEC Rate G-2 to Narragansett Rate C-06
==================================================================================================================================
NEC Rate G-2 Narragansett Rate C-06
G-2/C-06 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 1,272 $0.00 $0 1,272 $5.73 $7,289
2 Demand Charge:
Distribution Demand 29,206 $1.60 $46,730 0 $0.00 $0
Transmission Demand $0.00 $0 $0.00 $0
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 6,707,011 $0.03443 $230,922 6,707,011 $0.04559 $305,773
Transmission Energy $0.00273 $18,310 $0.00400 $26,828
Transition Energy $0.02340 $156,944 $0.02340 $156,944
Standard Offer $0.03800 $254,866 $0.03800 $254,866
DSM $0.00230 $15,426 $0.00230 $15,426
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $723,199 $767,126
5 Total Revenue Shift: $43,927
6 Revenue Shift by Function:
Distribution Revenue $35,409
Transmission Revenue $8,518
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate G2 Narragansett Electric
Range: Rate G2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 14 of 26
The Narragansett Electric Company
Shifting NEC Rate G-2 to Narragansett Rate G-02
==================================================================================================================================
NEC Rate G-2 Narragansett Rate G-02
G-2/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 6,226 $0.00 $0 6,226 $103.41 $643,831
2 Demand Charge:
Distribution Demand 255,636 $1.60 $409,018 213,521 $2.91 $621,346
Transmission Demand $0.00 $0 $1.40 $298,929
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 85,631,955 $0.03443 $2,948,308 85,631,955 $0.01691 $1,448,036
Transmission Energy $0.00273 $233,775 ($0.00136) ($116,459)
Transition Energy $0.02340 $2,003,788 $0.02340 $2,003,788
Standard Offer $0.03800 $3,254,014 $0.03800 $3,254,014
DSM $0.00230 $196,953 $0.00230 $196,953
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $9,045,857 $8,350,439
5 Total Revenue Shift: ($695,418)
6 Revenue Shift by Function:
Distribution Revenue ($644,113)
Transmission Revenue ($51,305)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate G2 Narragansett Electric
Range: Rate G2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 15 of 26
The Narragansett Electric Company
Shifting NEC Rate G-2 to Narragansett Rate G-32
==================================================================================================================================
NEC Rate G-2 Narragansett Rate G-32
G-2/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 147 $0.00 $0 147 $236.43 $34,755
2 Demand Charge:
Distribution Demand 36,878 $1.60 $59,005 43,326 $1.56 $67,589
Transmission Demand $0.00 $0 $1.27 $55,024
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 12,741,620 $0.03443 $438,694 12,741,620 $0.01800 $229,349
Transmission Energy $0.00273 $34,785 ($0.00136) ($17,329)
Transition Energy $0.02340 $298,154 $0.02340 $298,154
Standard Offer $0.03800 $484,182 $0.03800 $484,182
DSM $0.00230 $29,306 $0.00230 $29,306
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $1,344,125 $1,181,030
5 Total Revenue Shift: ($163,095)
6 Revenue Shift by Function:
Distribution Revenue ($166,006)
Transmission Revenue $2,911
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate T2 Narragansett Electric
Range: Rate T2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 16 of 26
The Narragansett Electric Company
Shifting NEC Rate T-2 to Narragansett Rate G-02
==================================================================================================================================
NEC Rate T-2 Narragansett Rate G-02
T-2/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 84 $0.00 $0 84 $103.41 $8,686
2 Demand Charge:
Distribution Demand 11,103 $1.60 $17,765 10,263 $2.91 $29,865
Transmission Demand $0.00 $0 $1.40 $14,368
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 4,675,660 $0.03443 $160,983 4,675,660 $0.01691 $79,065
Transmission Energy $0.00273 $12,765 ($0.00136) ($6,359)
Transition Energy $0.02340 $109,410 $0.02340 $109,410
Standard Offer On Peak 862,640 $0.03800 $32,780 $0.03800 $177,675
Standard Offer Off Peak 3,813,020 $0.03800 $144,895
DSM $0.00230 $10,754 $0.00230 $10,754
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $489,352 $423,466
5 Total Revenue Shift: ($65,886)
6 Revenue Shift by Function:
Distribution Revenue ($61,131)
Transmission Revenue ($4,755)
Transition Revenue $0
Standard Offer Revenue ($0)
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate T2 Narragansett Electric
Range: Rate T2 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 17 of 26
The Narragansett Electric Company
Shifting NEC Rate T-2 to Narragansett Rate G-32
==================================================================================================================================
NEC Rate T-2 Narragansett Rate G-32
T-2/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 72 $0.00 $0 72 $236.43 $17,023
2 Demand Charge:
Distribution Demand 19,224 $1.60 $30,758 20,900 $1.56 $32,604
Transmission Demand $0.00 $0 $1.27 $26,543
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 9,686,300 $0.03443 $333,499 9,686,300 $0.01800 $174,353
Transmission Energy $0.00273 $26,444 ($0.00136) ($13,173)
Transition Energy $0.02340 $226,659 $0.02340 $226,659
Standard Offer On Peak 1,818,780 $0.03800 $69,114 $0.03800 $368,079
Standard Offer Off Peak 7,867,520 $0.03800 $298,966
DSM $0.00230 $22,278 $0.00230 $22,278
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $1,007,719 $854,367
5 Total Revenue Shift: ($153,351)
6 Revenue Shift by Function:
Distribution Revenue ($140,277)
Transmission Revenue ($13,074)
Transition Revenue ($0)
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate T4 Narragansett Electric
Range: Rate T4 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 18 of 26
The Narragansett Electric Company
Shifting NEC Rate T-4 to Narragansett Rate G-32
==================================================================================================================================
NEC Rate T-4 Narragansett Rate G-32
T-4/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 69 $0.00 $0 69 $236.43 $16,314
2 Demand Charge:
Distribution Demand 41,467 $1.95 $80,861 57,333 $1.56 $89,439
Transmission Demand $0.00 $0 $1.27 $72,813
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 18,430,440 $0.03517 $648,199 18,430,440 $0.01800 $331,748
Transmission Energy $0.00273 $50,315 ($0.00136) ($25,065)
Transition Energy $0.02340 $431,272 $0.02340 $431,272
Standard Offer On Peak 3,531,400 $0.03800 $134,193 $0.03800 $700,357
Standard Offer Off Peak 14,899,040 $0.03800 $566,164
DSM $0.00230 $42,390 $0.00230 $42,390
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $1,953,393 $1,659,268
5 Total Revenue Shift: ($294,126)
6 Revenue Shift by Function:
Distribution Revenue ($291,558)
Transmission Revenue ($2,568)
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate T5 Narragansett Electric
Range: Rate T5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 19 of 26
The Narragansett Electric Company
Shifting NEC Rate T-5 to Narragansett Rate G-32
==================================================================================================================================
NEC Rate T-5 Narragansett Rate G-32
T-5/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $0.00 $0 12 $236.43 $2,837
2 Demand Charge:
Distribution Demand 5,375 $1.76 $9,460 5,375 $1.56 $8,385
Transmission Demand $0.00 $0 $1.27 $6,826
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 2,964,000 $0.02948 $87,379 2,964,000 $0.01800 $53,352
Transmission Energy $0.00273 $8,092 ($0.00136) ($4,031)
Transition Energy $0.02340 $69,358 $0.02340 $69,358
Standard Offer On Peak 531,000 $0.03800 $20,178 $0.03800 $112,632
Standard Offer Off Peak 2,433,000 $0.03800 $92,454
DSM $0.00230 $6,817 $0.00230 $6,817
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 5,375 ($0.37) ($1,989)
Primary Metering $256,176 -1% ($2,562)
4 Total Revenue before GET: $293,737 $251,626
5 Total Revenue Shift: ($42,112)
6 Revenue Shift by Function:
Distribution Revenue ($35,593)
Transmission Revenue ($5,324)
Transition Revenue $0
Standard Offer Revenue ($1,126)
DSM ($68)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate G5 Narragansett Electric
Range: Rate G5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 20 of 26
The Narragansett Electric Company
Shifting NEC Rate G-5 to Narragansett Rate G-02
==================================================================================================================================
NEC Rate G-5 Narragansett Rate G-02
G-5/G-02 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 158 $0.00 $0 158 $103.41 $16,339
2 Demand Charge:
Distribution Demand 12,834 $1.76 $22,588 14,847 $2.91 $43,205
Transmission Demand $0.00 $0 $1.40 $20,786
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 4,061,340 $0.02948 $119,728 4,061,340 $0.01691 $68,677
Transmission Energy $0.00273 $11,087 ($0.00136) ($5,523)
Transition Energy $0.02340 $95,035 $0.02340 $95,035
Standard Offer 4,061,340 $0.03800 $154,331 $0.03800 $154,331
DSM $0.00230 $9,341 $0.00230 $9,341
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 14,847 ($0.37) ($5,493)
Primary Metering $402,191 -1% ($4,022)
4 Total Revenue before GET: $412,111 $392,675
5 Total Revenue Shift: ($19,436)
6 Revenue Shift by Function:
Distribution Revenue ($21,821)
Transmission Revenue $4,022
Transition Revenue $0
Standard Offer Revenue ($1,543)
DSM ($93)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate G5 Narragansett Electric
Range: Rate G5 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 21 of 26
The Narragansett Electric Company
Shifting NEC Rate G-5 to Narragansett Rate G-32
==================================================================================================================================
NEC Rate G-5 Narragansett Rate G-32
G-5/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 83 $0.00 $0 83 $236.43 $19,624
2 Demand Charge:
Distribution Demand 27,527 $1.76 $48,448 29,984 $1.56 $46,775
Transmission Demand $0.00 $0 $1.27 $38,080
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 11,014,249 $0.02948 $324,700 11,014,249 $0.01800 $198,256
Transmission Energy $0.00273 $30,069 ($0.00136) ($14,979)
Transition Energy $0.02340 $257,733 $0.02340 $257,733
Standard Offer 11,014,249 $0.03800 $418,541 $0.03800 $418,541
DSM $0.00230 $25,333 $0.00230 $25,333
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 29,984 ($0.37) ($11,094)
Primary Metering $989,363 -1% ($9,894)
4 Total Revenue before GET: $1,104,824 $968,375
5 Total Revenue Shift: ($136,449)
6 Revenue Shift by Function:
Distribution Revenue ($124,810)
Transmission Revenue ($7,200)
Transition Revenue $0
Standard Offer Revenue ($4,185)
DSM ($253)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate T6 Narragansett Electric
Range: Rate T6 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 22 of 26
The Narragansett Electric Company
Shifting NEC Rate T-6 to Narragansett Rate G-32
==================================================================================================================================
NEC Rate T-6 Narragansett Rate G-32
T-6/G-32 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $0.00 $0 12 $236.43 $2,837
2 Demand Charge:
Distribution Demand 14,305 $1.76 $25,177 15,820 $1.56 $24,679
Transmission Demand $0.00 $0 $1.27 $20,091
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 6,958,000 $0.02993 $208,253 6,958,000 $0.01800 $125,244
Transmission Energy $0.00273 $18,995 ($0.00136) ($9,463)
Transition Energy $0.02340 $162,817 $0.02340 $162,817
Standard Offer On Peak 1,417,000 $0.03800 $53,846 $0.03800 $264,404
Standard Offer Off Peak 5,541,000 $0.03800 $210,558
DSM $0.00230 $16,003 $0.00230 $16,003
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 15,820 ($0.37) ($5,853)
Primary Metering $606,613 -1% ($6,066)
4 Total Revenue before GET: $695,650 $594,694
5 Total Revenue Shift: ($100,956)
6 Revenue Shift by Function:
Distribution Revenue ($89,679)
Transmission Revenue ($8,473)
Transition Revenue $0
Standard Offer Revenue ($2,644)
DSM ($160)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate T6 Narragansett Electric
Range: Rate T6 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 23 of 26
The Narragansett Electric Company
Shifting NEC Rate T-6 to Narragansett Rate G-62
==================================================================================================================================
NEC Rate T-6 Narragansett Rate G-62
T-6/G-62 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $0.00 $0 12 $17,118.72 $205,425
2 Demand Charge:
Distribution Demand 35,977 $1.76 $63,320 36,233 $0.75 $27,175
Transmission Demand $0.00 $0 $1.39 $50,364
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 17,589,599 $0.02993 $526,457 17,589,599 $0.01095 $192,606
Transmission Energy $0.00273 $48,020 ($0.00136) ($23,922)
Transition Energy $0.02340 $411,597 $0.02340 $411,597
Standard Offer On Peak 3,754,799 $0.03800 $142,682 $0.03800 $668,405
Standard Offer Off Peak 13,834,800 $0.03800 $525,722
DSM $0.00230 $40,456 $0.00230 $40,456
Renewables $0.00000 $0 $0.00000 $0
4. High Voltage Credits
Transformer Ownership 36,233 ($0.37) ($13,406)
Primary Metering $1,572,105 -1% ($15,721)
4 Total Revenue before GET: $1,758,253 $1,542,978
5 Total Revenue Shift: ($215,276)
6 Revenue Shift by Function:
Distribution Revenue ($186,345)
Transmission Revenue ($21,842)
Transition Revenue $0
Standard Offer Revenue ($6,684)
DSM ($405)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate C1 Narragansett Electric
Range: Rate C1 BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 24 of 26
The Narragansett Electric Company
Shifting NEC Rate C-1 to Narragansett Rate N-01
==================================================================================================================================
NEC Rate C-1 Narragansett Rate N-01
C-1/N-01 Units Rate Revenues Units Rate Revenues
(1) (2) (3) (4) (5) (6)
==================================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
1 Customer Charge: 12 $0.00 $0 12 $0.00 $0
2 Demand Charge:
Distribution Demand 212,968 $7.68 $1,635,594 212,968 $6.60 $1,405,589
Transmission Demand $0.00 $0 $0.00 $0
Standard Offer $0.00 $0
3 Energy Charges:
Distribution Energy 114,919,292 $0.00851 $977,963 114,919,292 $0.00731 $840,060
Transmission Energy $0.00273 $313,730 $0.00273 $313,730
Transition Energy $0.02340 $2,689,111 $0.02340 $2,689,111
Standard Offer On Peak 23,608,292 $0.03800 $897,115 $0.03800 $4,366,933
Standard Offer Off Peak 91,311,000 $0.03800 $3,469,818
DSM $0.00230 $264,314 $0.00230 $264,314
Renewables $0.00000 $0 $0.00000 $0
4 Total Revenue before GET: $10,247,646 $9,879,737
5 Total Revenue Shift: ($367,909)
6 Revenue Shift by Function:
Distribution Revenue ($367,909)
Transmission Revenue $0
Transition Revenue $0
Standard Offer Revenue $0
DSM $0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate C1 Narragansett Electric
Range: NEC BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 25 of 26
The Narragansett Electric Company
Shifting NEC Rate S-1 to Narragansett Rate S-14
Total Standard
Number Annual Annual Annual Distribution Transmission Transition Offer DSM Total
of Units kWh Price kWh Sale Revenues Revenues Revenues Revenues Revenues Revenues
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Overhead $0.00273 $0.02340 $0.03800 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Wood Poles
5800 Streetlight 651 334 $53.46 217,434 $34,802 $594 $5,088 $8,262 $500 $49,247
5800 Flood 41 334 $62.46 13,694 $2,561 $37 $320 $520 $31 $3,471
9500 Streetlight 7 476 $60.43 3,332 $423 $9 $78 $127 $8 $644
25000 Streetlight 189 1,274 $103.46 240,786 $19,554 $657 $5,634 $9,150 $554 $35,549
25000 Flood 275 1,274 $107.55 350,350 $29,576 $956 $8,198 $13,806 $806 $52,850
50000 Streetlight 12 1,966 $144.74 23,592 $1,737 $64 $552 $896 $54 $3,304
50000 Flood 353 1,966 $144.25 693,998 $50,920 $1,895 $16,240 $26,372 $1,596 $97,023
Lighting only Wood Poles
5800 Streetlight 32 334 $123.20 10,688 $3,942 $29 $250 $406 $25 $4,652
25000 Streetlight 6 1,274 $173.20 7,644 $1,039 $21 $179 $290 $18 $1,547
25000 Flood 27 1,274 $177.28 34,398 $4,787 $94 $805 $1,307 $79 $7,072
50000 Streetlight 2 1,966 $214.48 3,932 $429 $11 $92 $149 $9 $690
50000 Flood 50 1,966 $215.91 98,300 $10,796 $268 $2,300 $3,735 $226 $17,326
Mercury Vapor Lamp
Existing or Prepaid Wood Poles
4200 Streetlight 2525 511 $50.98 1,290,275 $128,725 $3,522 $30,192 $49,030 $2,968 $214,437
8600 Streetlight 47 822 $60.92 38,634 $2,863 $105 $904 $1,468 $89 $5,430
12100 Streetlight 24 1,180 $77.08 28,320 $1,850 $77 $663 $1,076 $65 $3,731
22500 Streetlight 377 1,864 $98.98 702,728 $37,315 $1,918 $16,444 $26,704 $1,616 $83,998
22500 Flood 111 1,864 $100.38 206,904 $11,142 $565 $4,842 $7,862 $476 $24,887
63000 Flood 37 4,463 $195.06 165,131 $7,217 $451 $3,864 $6,275 $380 $18,187
Lighting only Wood Poles
4200 Streetlight 74 511 $110.86 37,814 $8,204 $103 $885 $1,437 $87 $10,716
22500 Streetlight 34 1,864 $158.85 63,376 $5,401 $173 $1,483 $2,408 $146 $9,611
22500 Flood 32 1,864 $160.26 59,648 $5,128 $163 $1,396 $2,267 $137 $9,091
63000 Flood 9 4,463 $254.94 40,167 $2,294 $110 $940 $1,526 $92 $4,963
Incandescent
Existing or Prepaid Standard Metal Poles
1000 Streetlight 383 362 $22.57 138,646 $8,644 $379 $3,244 $5,269 $319 $17,855
2500 Flood 64 743 $19.46 47,552 $1,245 $130 $1,113 $1,807 $109 $4,404
Metal Halide Lamp
Existing or Prepaid Wood Poles
20000 Flood 5 1,180 $129.45 5,900 $647 $16 $138 $224 $14 $1,039
40000 Flood 6 1,832 $168.76 10,992 $1,013 $30 $257 $418 $25 $1,743
115000 Flood 37 4,247 $216.90 157,139 $8,025 $429 $3,677 $5,971 $361 $18,464
Total Overhead 5,410 4,691,374 $390,281 $12,807 $109,778 $178,272 $10,790 $701,929
Total Standard
Annual Annual Annual Distribution Transmission Transition Offer DSM Total
kWh Price kWh Sale Revenues Revenues Revenues Revenue Revenues Revenues
Overhead ($0.01861) $0.00123 $0.02340 $0.0380 $0.00230
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Sodium Vapor Lamp
Existing or Prepaid Wood Poles
5800 Streetlight 349 $66.28 227,199 $38,920 $279 $5,316 $8,634 $523 $53,672
5800 Flood 349 $66.28 14,309 $2,451 $18 $335 $544 $33 $3,380
9500 Streetlight 490 $72.63 3,430 $445 $4 $80 $130 $8 $667
25000 Streetlight 1284 $120.39 242,676 $18,238 $298 $5,679 $9,222 $558 $33,994
25000 Flood 1284 $143.14 353,100 $32,792 $434 $8,263 $13,418 $812 $55,719
50000 Streetlight 1968 $163.46 23,616 $1,522 $29 $553 $897 $54 $3,055
50000 Flood 1968 $181.37 694,704 $51,095 $854 $16,256 $26,399 $1,598 $96,202
Lighting only Wood Poles
5800 Streetlight 349 $121.73 11,168 $3,688 $14 $261 $424 $26 $4,413
25000 Streetlight 1284 $175.84 7,704 $912 $9 $180 $293 $18 $1,412
25000 Flood 1284 $198.59 34,668 $4,717 $43 $811 $1,317 $80 $6,968
50000 Streetlight 1968 $218.91 3,936 $365 $5 $92 $150 $9 $620
50000 Flood 1968 $236.82 98,400 $10,010 $121 $2,303 $3,739 $226 $16,399
Mercury Vapor Lamp
Existing or Prepaid Wood Poles
4200 Streetlight 561 $54.40 1,416,525 $110,998 $1,742 $33,147 $53,828 $3,258 $202,973
8600 Streetlight 908 $70.77 42,676 $2,532 $52 $999 $1,622 $98 $5,303
12100 Streetlight 908 $70.77 21,792 $1,293 $27 $510 $828 $50 $2,708
22500 Streetlight 1897 $122.31 715,169 $32,802 $880 $16,735 $27,176 $1,645 $79,237
22500 Flood 1897 $152.08 210,567 $12,962 $259 $4,927 $8,002 $484 $26,634
63000 Flood 4569 $262.72 169,053 $6,575 $208 $3,956 $6,424 $389 $17,551
Lighting only Wood Poles
4200 Streetlight 561 $109.85 41,514 $7,356 $51 $971 $1,578 $95 $10,052
22500 Streetlight 1897 $177.76 64,498 $4,844 $79 $1,509 $2,451 $148 $9,031
22500 Flood 1897 $207.53 60,704 $5,511 $75 $1,420 $2,307 $140 $9,453
63000 Flood 4569 $318.17 41,121 $2,098 $51 $962 $1,563 $95 $4,768
Incandescent
Existing or Prepaid Standard Metal Poles
1000 Streetlight 440 $75.22 168,520 $25,673 $207 $3,943 $6,404 $388 $36,615
2500 Flood 845 $67.45 54,080 $3,310 $67 $1,265 $2,055 $124 $6,822
Metal Halide Lamp
Existing or Prepaid Wood Poles
20000 Flood 1284 $143.14 6,420 $596 $8 $150 $244 $15 $1,013
40000 Flood 1968 $181.37 11,808 $868 $15 $276 $449 $27 $1,635
115000 Flood 1968 $181.37 72,816 $5,356 $90 $1,704 $2,767 $167 $10,084
Total Overhead 4,812,173 $387,928 $5,919 $112,605 $182,863 $11,068 $700,382
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
File: C:\JMM\[workjmm3.wk4]Rate C1 Narragansett Electric
Range: NEC BVE/Newport Electric
Date: 14-May-99 R.I.P.U.C. Docket No. _______
Workpaper JMM - 3
Page 26 of 26
The Narragansett Electric Company
Shifting NEC Rate S-1 to Narragansett Rate S-14
Total Standard
Number Annual Annual Annual Distribution Transmision Transition Offer DSM Total
of Units kWh Price kWh Sales Revenues Revenues Revenues Revenues Revenues Revenues
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Underground $0.00273 $0.02340 $0.03800 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Standard Metal Poles
5800 Streetlight 8 334 $60.8 2,672 $487 $7 $63 $102 $6 $665
25000 Streetlight 12 1,274 $110.89 15,288 $1,331 $42 $358 $581 $35 $2,346
25000 Flood 1 1,274 $115.74 1,274 $116 $3 $30 $48 $3 $200
50000 Flood 1 1,966 $152.43 1,966 $152 $5 $46 $75 $5 $283
Lighting only Standard Metal Poles
5800 Streetlight 14 334 $161.51 4,676 $2,261 $13 $109 $178 $11 $2,572
Existing or Prepaid Poles less than 15 ft.
5800 T&C 247 334 $54.12 82,498 $13,368 $225 $1,930 $3,135 $190 $18,848
Existing or Prepaid Wood Poles
5800 Streetlight 78 334 $56.99 26,052 $4,445 $71 $610 $990 $60 $6,176
25000 Streetlight 24 1,274 $106.98 30,576 $2,568 $83 $715 $1,162 $70 $4,599
50000 Streetlight-Twin 12 3,932 $276.25 47,184 $3,315 $129 $1,104 $1,793 $109 $6,449
Lighting only Wood Poles
25000 Flood 1 1,274 $171.14 1,274 $171 $3 $30 $48 $3 $256
Mercury Vapor Lamp
Existing or Prepaid Standard Metal Poles
22500 Flood 6 1,864 $103.41 11,184 $620 $31 $262 $425 $26 $1,363
Lighting only Standard Metal Poles
4200 Streetlight 2 511 $143.76 1,022 $288 $3 $24 $39 $2 $355
22500 Streetlight 16 1,864 $191.74 29,824 $3,068 $81 $698 $1,133 $69 $5,049
22500 Streetlight-Twin 3 3,728 $278.38 11,184 $835 $31 $262 $425 $26 $1,578
Existing or Prepaid Wood Poles
4200 Streetlight 27 51 $54.01 13,797 $1,458 $38 $323 $524 $32 $2,375
22500 Streetlight 1 1,864 $102.00 1,864 $102 $5 $44 $71 $4 $226
Lighting only Wood Poles
4200 Streetlight 55 511 $105.59 28,105 $5,807 $77 $658 $1,068 $65 $7,674
8600 Streetlight 13 822 $115.53 10,686 $1,502 $29 $250 $406 $25 $2,212
12100 Streetlight 19 1,180 $136.93 22,420 $2,602 $61 $525 $852 $52 $4,091
12100 Streetlight-Twin 6 2,359 $186.86 14,154 $1,121 $39 $331 $538 $33 $2,061
22500 Streetlight 231 1,864 $153.58 430,584 $35,477 $1,175 $10,076 $16,362 $990 $64,081
22500 Streetlight-Twin 26 3,728 $235.30 96,928 $6,118 $265 $2,268 $3,683 $223 $12,557
63000 Streetlight 7 4,463 $245.38 31,241 $1,718 $85 $731 $1,187 $72 $3,793
Existing or Prepaid Poles less than 15 ft.
4200 T&C 14 511 $54.54 7,154 $764 $20 $167 $272 $16 $1,239
Total Underground 824 923,607 $89,693 $2,521 $21,612 $35,097 $2,124 $151,048
Total Overhead and
Underground 6,234 5,614,981 $479,974 $15,329 $131,391 $213,369 $12,914 $852,977
Total Standard
Annual Annual Annual Distribution Transmission Transition Offer DSM Total
kWh Price kWh Sales Revenues Revenues Revenues Revenues Revenues Revenues
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Underground ($0.01861) $0.00123 $0.02340 $0.0380 $0.00230
Sodium Vapor Lamp
Existing or Prepaid Standard Metal Poles
5800 Streetlight 349 $66.28 2,792 $478 $3 $65 $106 $6 $660
25000 Streetlight 1284 $120.39 15,408 $1,158 $19 $361 $586 $35 $2,158
25000 Flood 1284 $143.14 1,284 $119 $2 $30 $49 $3 $203
50000 Flood 1968 $181.37 1,968 $145 $2 $46 $75 $5 $273
Lighting only Standard Metal Poles
5800 Streetlight 349 $319.65 4,886 $4,384 $6 $114 $186 $11 $4,701
Existing or Prepaid Poles less than 15 ft.
5800 T&C 349 $66.28 86,203 $14,767 $106 $2,017 $3,276 $198 $20,364
Existing or Prepaid Wood Poles
5800 Streetlight 349 $66.28 27,222 $4,663 $33 $637 $1,034 $63 $6,431
25000 Streetlight 1284 $120.39 30,816 $2,316 $38 $721 $1,171 $71 $4,317
50000 Streetlight-Twin 3936 $326.92 47,232 $3,044 $58 $1,105 $1,795 $109 $6,111
Lighting only Wood Poles
25000 Flood 1284 $198.59 1,284 $175 $2 $30 $49 $3 $258
Mercury Vapor Lamp
Existing or Prepaid Standard Metal Poles
22500 Flood 1897 $152.08 11,382 $701 $14 $266 $433 $26 $1,440
Lighting only Standard Metal Poles
4200 Streetlight 561 $311.77 1,122 $603 $1 $26 $43 $3 $676
22500 Streetlight 1897 $375.68 30,352 $5,446 $37 $710 $1,153 $70 $7,417
22500 Streetlight-Twin 3794 $497.99 11,382 $1,282 $14 $266 $433 $26 $2,021
Existing or Prepaid Wood Poles
4200 Streetlight 561 $58.40 15,147 $1,295 $19 $354 $576 $35 $2,278
22500 Streetlight 1897 $122.31 1,897 $87 $2 $44 $72 $4 $210
Lighting only Wood Poles
4200 Streetlight 561 $113.85 30,855 $5,688 $38 $722 $1,172 $71 $7,691
8600 Streetlight 908 $126.22 11,804 $1,421 $15 $276 $449 $27 $2,188
12100 Streetlight 908 $126.22 17,252 $2,077 $21 $404 $656 $40 $3,197
12100 Streetlight-Twin 1816 $196.99 10,896 $979 $13 $255 $414 $25 $1,687
22500 Streetlight 1897 $177.76 438,207 $32,908 $539 $10,254 $16,652 $1,008 $61,360
22500 Streetlight-Twin 3794 $300.07 98,644 $5,966 $121 $2,308 $3,748 $227 $12,371
63000 Streetlight 4569 $318.17 31,983 $1,632 $39 $748 $1,215 $74 $3,709
Existing or Prepaid Poles less than 15 ft.
4200 T&C 561 $58.40 7,854 $671 $10 $184 $298 $18 $1,181
Total Underground 937,872 $92,005 $1,154 $21,946 $35,639 $2,157 $152,901
Total Overhead and
Underground 5,750,045 $479,933 $7,073 $134,551 $218,502 $13,225 $853,283
</TABLE>
<PAGE>
C:\JMM\[workjmm4.wk4]A Narragansett Electric
Range: BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Workpaper JMM - 4
Workpaper JMM-4
Transmission Back-up
<PAGE>
<TABLE>
<CAPTION>
C:\JMM\[workjmm4.wk4]A Narragansett Electric
Range: BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Workpaper JMM - 4
Page 1 of 1
The Narragansett Electric Company
Calculation of Projected Transmission Expenses
(based on 1998 actual expenses and coincident peak data)
Narragansett Blackstone Newport
<S> <C> <C> <C>
1 NEP Tariff No. 9 Expenses $17,271,638 $2,584,364 $1,081,211
2 NEPOOL Tariff No. 1 $5,947,067 $1,015,660 $401,812
3 Total Transmission Expenses $23,218,705 $3,600,024 $1,483,023
1 FERC Docket ER99-2832-000, Exhibit ____ (PAV-2), Statement BH
2 Average 1998 12 Month Coincident Peak Load * NEPOOL Rate in effect during
Year 2 of transition
CP Load NEPOOL Rate NEPOOL Charges
Narragansett Electric 838,570 $7.02 $5,883,405
New England Power for Narragansett 13,792 $4.62 $ 63,662
Blackstone Valley Electric 220,030 $4.62 $1,015,660
Newport Electric 87,048 $4.62 $ 401,812
3 line (1) + Line (2)
</TABLE>
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ------------------------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No.________
Blackstone Valley Electric Company )
Newport Electric Corporation )
)
- ------------------------------------------------
DIRECT TESTIMONY
OF
JAMES J. BONNER., JR.
<PAGE>
THE STATE OF RHODE ISLAND AND PROVIDENCE PLANTATIONS
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ------------------------------------------------
)
Narragansett Electric Company ) R.I.P.U.C. No.________
Blackstone Valley Electric Company )
Newport Electric Corporation )
)
- ------------------------------------------------
DIRECT TESTIMONY
OF
JAMES J. BONNER., JR.
Table of Contents
I. Introduction and Qualifications.................................... 1
II. Purpose of Testimony............................................... 3
III. Mapping of Blackstone/Newport's Customers to
Narragansett's Rates............................................... 4
IV. Derivation of Billing Determinants for Blackstone/Newport's
Customers Under Narragansett's Rates............................... 16
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 1 of 22
<S> <C>
1 I. Introduction and Qualifications
2 Q. Please state your full name and business address.
3 A. My name is James J. Bonner, Jr. My business address is 750 West Center Street, West
4 Bridgewater, Massachusetts.
5
6 Q. Please state your present position and responsibilities.
7 A. I am Manager of Retail Pricing and Rate Administration for EUA Service Corporation.
8 My responsibilities include the direct supervision of EUA Service Corporation's Retail
9 Pricing and Rate Administration supervisor and staff. Among the responsibilities of that
10 staff are the study, analysis, and design of retail delivery electric service rates for
11 Blackstone Valley Electric Company ("Blackstone") and Newport Electric Corporation
12 ("Newport") (collectively "Blackstone/Newport").
13
14 Q. Please describe your educational background and work experience.
15 A. I graduated from Northeastern University in 1976 with a Bachelor of Science degree in
16 Electrical Engineering (Power Systems). I attended the Edison Electric Institute's ("EEI")
17 Rate Fundamentals Course at Indiana University in November 1995 and the EEI
18 Advanced Rate Course at Indiana University in August 1986 and in August 1988. I was
19 Chairman of the Electric Council of New England's Rate and Regulatory Committee from 1993
20 through 1995.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 2 of 22
1 From August 1976 through February 1983, I was employed by the Belcher Division of
2 Dayton Malleable Inc., a malleable iron foundry located in Easton, Massachusetts, as Plant
3 Engineer. My duties included plant maintenance management, energy management,
4 capital budgeting, and production engineering.
5
6 In March 1983, I joined Eastern Edison Company ("Eastern") as Consumer Service
7 Engineer for the Brockton Division. In that capacity, I served as Eastern's representative
8 for its fifty largest commercial-industrial customers in the Brockton Division's service area
9 and as a staff assistant to the Consumer Service Manager.
10
11 I transferred to the Rate Department of EUA Service Corporation in February 1985 as an
12 Associate Rate Engineer, I was promoted to Rate Engineer in February 1987, to Senior
13 Rate Engineer in February 1989, to Supervisor of Rate Design in January 1991, and to
14 Manager of Retail Pricing and Rate Administration in January 1999.
15
16 Since assuming the position of Supervisor of Rate Design in 1991, I have supervised the
17 preparation of Blackstone/Newport's retail rates approved by the Commission in
18 subsequent regulatory proceedings.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 3 of 22
1 Q. Have you previously testified before the Commission?
2 A. Yes, I have testified before the Commission on numerous occasions. Most recently, I
3 testified in support of Blackstone/Newport's proposed Standard Offer Service tariffs in
4 Docket No. 2716 in May 1998.
5
6 Q. Were the schedules attached to your direct testimony prepared by you or under your
7 supervision and direction?
8 A. Yes, they were.
9
10 II. Purpose of Testimony
11 Q. What is the purpose of your testimony?
12 A. The purpose of my testimony is to present and support the mapping of
13 Blackstone/Newport's customers under Blackstone/Newport's rates to Narragansett
14 Electric Company's ("Narragansett's") rates and the derivation of the billing determinants
15 for Blackstone/Newport's customers mapped to Narragansett's rates. Mr. Molloy makes
16 use of this mapping and these billing determinants in his testimony and exhibits regarding
17 the Narragansett/Blackstone/Newport merger rate plan.
18
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 4 of 22
1 Q. Please explain how you have organized your testimony.
2 A. My testimony is organized as follows: (1) An explanation of the mapping process used to
3 cross match the schedule of rates between Blackstone/Newport and Narragansett, and (2)
4 an explanation of the derivation of the billing determinants used for transferring
5 Blackstone/Newport's customers to Narragansett's rates.
6
7 III. Mapping of Blackstone/Newport's Customers to Narragansett's Rates
8 Q. Please describe how Blackstone/Newport's customers were mapped to Narragansett's
9 rates.
10 A. A mapping of Blackstone/Newport's current rates to Narragansett's current rates was
11 performed by cross matching the availability provisions of Blackstone/Newport's rates and
12 Narragansett's rates. Exhibit JJB-1 and Exhibit JJB-2 show comparisons of the availability
13 provisions of Blackstone/Newport's and Narragansett's rates. Mr. Molloy in his Exhibit
14 JMM-2 provides a summary of the cross matching of Blackstone/Newport's rates to
15 Narragansett's.
16
17 Although Blackstone/Newport's schedule of rates is roughly comparable to Narragansett's
18 schedule of rates, Blackstone/Newport's scheme is not the same as Narragansett's.
19 Blackstone/Newport has, in some customer classes, more available rates than
20 Narragansett-in others, less. Blackstone/Newport uses distribution service voltage level
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 5 of 22
1 and billing determinant breakpoints to subdivide its general service customers among
2 several rate classes. Narragansett uses only billing determinant breakpoints to subdivide
3 its general service customers among several rate classes, and these breakpoints differ from
4 Blackstone/Newport's. Narragansett has more auxiliary service and lighting service rates
5 than does Blackstone/Newport. Blackstone and Newport used rate riders for economic
6 development purposes, while Narragansett used provisions in their base rate tariffs.
7 Finally Blackstone/Newport offers more supplementary1 rates than does Narragansett
8 (three rates to one).
9
10 Q. How were the determinants for the rate mapping scheme developed?
11 A. Blackstone-Newport based the mapping of Blackstone/Newport's rates to Narragansett's rates
12 on its customer billing information for calendar year 1998. For each of
13 Blackstone/Newport's rate classes, the number of bills rendered and annual energy
14 consumption were determined. In addition, monthly billing demands and annual peak and off
15 peak energy consumption were determined when applicable. In many cases, especially for
16 those current Blackstone/Newport rate classes that were subdivided into two or more
- ---------------
1 A supplementary rate is a rate that is available only to customers who also receive part
of their electric service under another rate, called a principal rate. A principal rate can be the only rate
under which a customer receives service at a given location, but a supplementary rate cannot. For
example, Blackstone/Newport's Controlled Water Heating Service Rate W-1 is a supplementary
rate. To be eligible for Rate W-1, a customer must also receive service under one or more of
Blackstone/Newport's residential or general service rates at the same service location.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 6 of 22
1 Narragansett rate classes, these determinants were required to be developed on a
2 customer-by-customer basis and transformed from Blackstone/Newport's definition of a
3 determinant -- e.g., billing demand -- to Narragansett's definition of the same determinant.
4
5 Q. Please describe Blackstone and Newport's Schedule of Rates.
6 A. Blackstone and Newport's Schedule of Rates are similar but not identical. Exhibit JJB-1
7 and Exhibit JJB-2 provide a brief description of the availabilities of Blackstone's and
8 Newport's rates, respectively.
9
10 In addition to the above referenced rates, Blackstone/Newport's Schedule of Rates
11 contains the following rate riders, terms and conditions, generation services, and
12 adjustment clauses:
13 Late Payment Charge2
14 Economic Development Rate Rider ED3
15 Economic Development Rate Rider EDR
16 Economic Development Rate Rider VSR
17 Economic Development Rate Rider DIR4
18 Terms and Conditions for Electric Service
- ---------------
2 Blackstone only.
3 Id.
4 Newport only.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 7 of 22
1 Terms and Conditions for Electric Power Suppliers
2 Last Resort Service
3 Standard Offer Service
4 Transition Cost Adjustment Clause
5
6 Q. Please describe Narragansett's Schedule of Rates.
7 A. Exhibit JJB-1 and Exhibit JJB-2 provide a brief description of the availabilities of
8 Narragansett's rates.
9
10 In addition to the above referenced rates, Narragansett's Schedule of Rates contains the
11 following terms and conditions, adjustment provisions, and generation service tariffs:
12 Terms and Conditions
13 Terms and Conditions for Nonregulated Power Producers
14 Transmission Service Charge Adjustment Provision
15 Transition Charge Adjustment Provision
16 Standard Offer Adjustment Provision
17 Conservation and Load Management Adjustment Provision
18 Tariff for Standard Offer Service
19 Tariff for Last Resort Service
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 8 of 22
1 Q. How were Blackstone/Newport's residential rates mapped to Narragansett's residential
2 rates?
3 A. Blackstone/Newport's residential rates are available only to residential customers for
4 domestic purposes. Rate R-1 is the basic residential retail delivery service rate, Rate R-2
5 is restricted to low-income customers, and Rate R-4 is Blackstone/Newport's time-of-use
6 residential rate. For Blackstone customers, Rate R-3 is available to certain electric space
7 heating customers. This rate was closed to new customers in 1984.
8
9 Like Blackstone/Newport, Narragansett's residential rates are available to residential
10 customers for domestic purposes. In addition, farms and churches are eligible to receive
11 service under Narragansett's residential rates. Rate A-16 is Narragansett's basic
12 residential retail delivery service rate, Rate A-60 is restricted to low-income customers,
13 and Rate A-32 is Narragansett's large-use residential rate.
14
15 As shown on Exhibit JMM-2, Blackstone/Newport's Rates R-1 and the residential portion
16 of W-1 were mapped to Narragansett's Rate A-16. Blackstone/Newport's Rate R-2 was
17 mapped to Narragansett's Rate A-60. Blackstone's Rate R-3 was mapped to
18 Narragansett's Rate A-16. Blackstone/Newport's Rate R-4 was mapped to
19 Narragansett's Rate A-32.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 9 of 22
1 Q. Were any of Blackstone/Newport's residential customers mapped to Narragansett's
2 Rates A-18 and E-30?
3 A. No. Those Narragansett rates, Residential Water Heating Control Rate A-18 and
4 Residential Storage Heating Rate E-30, are closed to new customers.
5
6 Q. Briefly describe Blackstone/Newport's general service rate scheme.
7 A. Blackstone/Newport's "G" and "T" series rates form the main sequence of
8 Blackstone/Newport's general service tariffs. The "G" and "T" series rates are divided
9 into two groups: (1) Secondary distribution voltage rates-Rates G-1, G-2, T-2, and T-4,
10 and (2) primary distribution voltage rates-Rates G-5, T-5, and T-6. The available
11 provisions in the "G" and "T" series rates for Blackstone differ somewhat from Newport's.
12
13 For Blackstone, the availability of the secondary distribution voltage rates is as follows:
14 Rate G-1 is available to customers whose annual maximum monthly demand is less than
15 10 kW and whose annual energy consumption is less than 36,000 kWh. Rate G-2 is
16 available to customers whose annual maximum monthly demand is at least 10 kW but less
17 than 500 kW or whose annual energy consumption is 36,000 kWh or more. For Newport,
18 the availability of the secondary voltage rates is as follows: Rate G-1 is available to
19 customers whose average monthly demand is less than 500 kW and whose annual energy
20 consumption is less than 54,000 kWh. Rate G-2 is available to customers whose average
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 10 of 22
1 monthly demand is less than 500 kW and whose annual energy consumption is 54,000
2 kWh or more. For both Blackstone and Newport, Rate T-4 is mandatory for customers
3 whose monthly demand is 500 kW or more.
4
5 For Blackstone's general service customers served at primary distribution voltage, Rate
6 G-5 is available to customers whose annual maximum monthly demand is at least 10 kW
7 but less than 500 kW or whose annual energy consumption is 36,000 kWh or more. Rate
8 T-5 is an optional time-of-use rate for Rate G-5 customers. Rate T-6 is mandatory for
9 customers whose annual maximum monthly demand is 500 kW or more.
10
11 For Newport's general service customers served at primary voltage, Rate G-5 is available
12 to customers whose average monthly demand is at least 15 kW but less than 500 kW or
13 whose annual energy consumption is 54,000 kWh or more. Rate T-5 is an optional time-of-use
14 rate for Rate G-5 customers. Rate T-6 is mandatory for customers whose average
15 monthly demand is 500 kW or more. In addition, Newport offers Transmission Voltage
16 General Retail Delivery Service Rate C-1, which is applicable only to the U.S. Navy under
17 the terms of a special electric service contract originally executed in 1961 and was
18 amended to incorporate the C-1.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 11 of 22
1 Q How does Narragansett's general service rate scheme compare to Blackstone/Newport's?
2 A. Narragansett's general service rate scheme is generally comparable to
3 Blackstone/Newport's. Narragansett offers six general service rates, Rates C-06, E-40,
4 G-02, G-32, G-62, and T-06.
5
6 Narragansett's main sequence of general service rates consists of Rates C-06, G-02, G-32,
7 and G-62. These rates roughly correspond with Blackstone/Newport's "G" and "T" series
8 rates and apply to customers as follows: Rate C-06 is a non-demand metered general
9 service rate available to customers whose monthly demand is 200 kW or less. Rate G-02
10 is a non-time-differentiated demand metered rate available to customers whose monthly
11 demand is at least 10 kW but not more than 200 M Rate G-32 is a time-differentiated
12 demand metered rate available to customers whose monthly demand is more than 200 kW
13 but less than 3,000 kW. Rate G-62 is a time-differentiated demand metered rate available
14 to customers whose demand is 3,000 kW or greater.
15
16 In addition, Narragansett offers Storage Cooling Rate E-40 and Limited Service - All
17 Electric Living Rate T-06. Blackstone/Newport does not offer a rate that corresponds to
18 Narragansett's Rate E-40; however, Blackstone/Newport's Rate H-1 is comparable to
19 Narragansett's Rate T-06.
20
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 12 of 22
1 Q. How were Blackstone/Newport's general service rates mapped to Narragansett's general
2 service rates?
3 A. As shown in Exhibit JMM-2, Blackstone/Newport's Rate G-1 was mapped to
4 Narragansett's Rate C-06. Blackstone/Newport's Rate G-2 was mapped to
5 Narragansett's Rates C-06, G-02, and G-32. Blackstone/Newport's Rate T-4 was
6 mapped to Narragansett's Rate G-32. Blackstone/Newport's Rate G-5 was mapped to
7 Narragansett's Rates G-02 and G-32. Blackstone/Newport's Rate T-6 was mapped to
8 Narragansett's Rate G-32 and G-62. Blackstone/Newport's Rate H-1 was mapped to
9 Narragansett's Rates C-06, G-02, and G-32. Newport's Rate C-1 was mapped to
10 Narragansett's Rate N-01, which is a new rate and is described in greater detail in Mr.
11 Molloy's testimony.
12
13 Q. Were any of Blackstone/Newport's general service customers mapped to Narragansett's
14 Rates E-40 and T-06?
15 A. No. Blackstone/Newport does not have any customers who qualify for Narragansett Rate
16 E-40, and Narragansett Rate T-06 is closed to new customers.
17
18 Q. How were Blackstone/Newport's auxiliary service Rates A-4 and A-6 mapped to
19 Narragansett's rates?
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 13 of 22
1 A. Blackstone/Newport offers two auxiliary service rates: Large Secondary Voltage Auxiliary
2 General Retail Delivery Service Rate A-4 and Large Primary Voltage Auxiliary General
3 Retail Delivery Service Rate A-6.
4
5 Narragansett's auxiliary service rate offerings are more extensive than
6 Blackstone/Newport's. Narragansett offers rates that are applicable to partial
7 requirements customers whose total electric service requirements exceed 30 kW, while
8 Blackstone/Newport offers rates that are applicable to partial requirements customers
9 whose total electric service requirements exceed 500 kW.
10
11 The availability provisions of Narragansett's auxiliary rates, their "B" series rates,
12 correspond with the availability provisions of the general service rates having the same
13 numerical suffix. Thus, Narragansett's Rate B-06 is available to customers who supply
14 part of their load from on-site generation and who would otherwise be served by
15 Narragansett's Rate C-06. Likewise, Narragansett's Rate B-32 is available to partial
16 requirements customers who would otherwise be served by Narragansett's Rate G-32.
17 And, Narragansett's Rate B-62 is available to partial requirements customers who would
18 otherwise be served by Narragansett's Rate G-62.
19
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 14 of 22
1 Blackstone/Newport's Rate A-4 would be mapped to Narragansett's Rate B-06; however,
2 there are no customers on this rate; Blackstone/Newport's Rate A-6 was mapped to
3 Narragansett's Rate B-32.
4
5 Q. How were Blackstone/Newport's supplementary service rates mapped to Narragansett's
6 rates?
7 A. To determine the proper mapping of Blackstone/Newport's customers who receive part of
8 their service under a supplementary rate, the supplementary rate was paired with the
9 principal rate for each customer. The supplementary rate was then mapped to the
10 Narragansett rate that corresponded to the customer's principal rate. Thus, the residential
11 portion of Blackstone/Newport's Rate W-1 was mapped to Narragansett's Rate A-16, and
12 the non-residential portion of Blackstone/Newport's Rate W-1 was mapped to
13 Narragansett's Rate C-06. Blackstone's Rate H-2 was mapped to three of Narragansett's
14 rates: Rates C-06, G-02, and G-32. Newport's Rate H-2 was mapped to two of
15 Narragansett's rates: Rates C-06 and G-02.
16
17 Q. Were any Blackstone/Newport supplementary rates mapped to Narragansett's
18 supplementary rate, Rate V-02?
19 A. No. Although Limited Service - Business Space Heating Rate V-02 is comparable to
20 Blackstone/Newport's Rate H-2, it is closed to new customers.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 15 of 22
1 Q. How was Blackstone/Newport's lighting service rate mapped to Narragansett's lighting
2 service rates?
3 A. Blackstone/Newport offers only one lighting service rate to its customers, Rate S-1.
4 Blackstone/Newport's Rate S-1 provides customers with a wide choice of lighting fixtures
5 (streetlights, floodlights, and area lights) mounted on distribution or specialty lighting
6 poles served from overhead or underground conductors. All lighting equipment
7 (luminaires, poles, conductors, etc.) required to provide service under Rate S-1 is
8 furnished, installed, owned, and maintained by Blackstone/Newport. For certain fixture-pole
9 combinations, Blackstone/Newport permits customers to pay the initial cost of
10 installation by a contribution in aid of construction to obtain a lower monthly rate.
11
12 Although it appears that Narragansett offers more lighting rates than does
13 Blackstone/Newport, in fact, Narragansett offers only one. Three of Narragansett's
14 lighting rates are frozen: Rates R-02, S-10, and S-12. Only Rate S-14 is currently
15 available for new installations.
16
17 Blackstone/Newport's Rate S-1 was mapped to Narragansett's Rate S-14.
18
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 16 of 22
1 IV. Derivation of Billing Determinants for Blackstone/Newport's Customers
2 Under Narragansett's Rates
3 Q. Please summarize how billing determinants for Blackstone/Newport's customers under
4 Narragansett's rates were derived.
5 A. Billing determinants are customer usage parameters that are applied to the component
6 charges of a rate schedule to calculate a customer's bill. Examples of commonly used
7 billing determinants are the number of bills, monthly energy consumption, and monthly
8 maximum demand. The precise definition of a billing determinant is dependent upon the
9 rate to which it is applied. Consequently, the derivation of billing determinants for a
10 customer to be transferred from one rate to another depends upon the rate to which the
11 customer is to be transferred.
12
13 In some cases, the billing determinants for Blackstone/Newport's customers under
14 Narragansett's rates are the same determinants Blackstone/Newport uses to bill these
15 same customers under its rates. This is exactly the case for Blackstone/Newport's
16 customers served under Rates R-1, R-2, R-3, R-4, G-1, W-1, and S-1 that will be
17 transferred to Narragansett's Rates A-16, A-32, A-60, C-06, and S-14.
18
19 In all other cases, the billing determinants for Blackstone/Newport's customers under
20 Narragansett's rates had to be calculated or estimated, at least for some of the customers
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 17 of 22
1 being transferred from a particular Blackstone/Newport rate to a particular Narragansett
2 rate. All of Blackstone/Newport's customers served under its general service rates, other
3 than Rate G-1 customers, and all of Blackstone/Newport's customers served under its
4 supplementary rates required the calculation or estimation of billing determinants under
5 Narragansett's rates.
6
7 Exhibit JJB-3 and Exhibit JJB-4 show the billing determinants for each Blackstone and
8 Newport to Narragansett rate mapping, respectively. Each Blackstone/Newport rate
9 mapping is shown on a separate page, and, where appropriate, explanatory notes detailing
10 how the billing determinants were derived is included on the page.
11
12 Q. Why was it necessary to estimate billing determinants for some customers?
13 A. Estimated billing determinants, particularly billing demands, for customers were used
14 where Blackstone/Newport's definition of a billing determinant differs from
15 Narragansett's and/or where Blackstone/Newport does not record, or does not have
16 readily available, the data required to calculate the determinant. For example,
17 Blackstone/Newport's Rate H-1 non-demand metered customers transferring to
18 Narragansett's demand metered Rates G-02 and G-32 required the estimation of billing
19 demands. Exhibits JJB-3 and JJB-4 detail each instance where estimated determinants
20 were required.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 18 of 22
1 Q. In general, is Blackstone/Newport's definition of billing demand for its general service
2 rates substantially different from Narragansett's?
3 A. Yes, it is. Although both companies define demand as a fifteen-minute integrated demand,
4 the determination of billing demand from raw demand data is generally more complicated
5 under Narragansett's rates than it is under Blackstone/Newport's rates.
6
7 Blackstone/Newport generally defines billing demand as the maximum demand over all
8 hours for non-time-differentiated rates and as the maximum demand within peak hours for
9 time-differentiated rates.
10
11 Narragansett generally determines billing demand as the largest of several demands. For
12 example, Narragansett defines billing demand for their Rate G-32 customers as the
13 greatest of the following:
14 (a) The greatest fifteen-minute demand occurring in such month during Peak
15 or Shoulder hours as measured in kilowatts,
16 (b) 80% of the greatest fifteen-minute demand occurring in such month during
17 Peak or Shoulder hours as measured in kilovolt-amperes,
18 (c) 50% of the greatest fifteen-minute demand occurring in such month during
19 Off-Peak Hours as measured in kilowatts,
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 19 of 22
1 (d) 40% of the greatest fifteen-minute demand occurring in such month during
2 Off-Peak Hours as measured in kilovolt-amperes,
3 (e) 75% of the greatest billing demand as determined above during the
4 preceding eleven months, or
5 (f) 10 kilowatts.
6 Similar "greatest of" criteria are used to determine billing demand under other
7 Narragansett demand metered rates.
8
9 Q. Is Blackstone/Newport's definition of time periods for its time-differentiated general
10 service rates substantially different from Narragansett's?
11 A. Yes, it is. Blackstone/Newport use a two-part definition with relatively short peak hour
12 periods. Narragansett uses a three-part time period definition and relatively long
13 peak-shoulder hour periods.
14
15 Blackstone defines its time periods for all time-differentiated rates as follows:
16 Peak Hours
17 Monday through Friday excluding holidays:
18 April through September, 11:00 a.m. to 4:00 p.m.
19 October through March, 8:00 a.m. to 12:00 noon, and
20 4:00 p.m. to 7:00 p.m.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 20 of 22
1 Off-Peak Hours
2 All other hours.
3 Newport's time periods are slightly differ from Blackstone's and are as follows for all
4 time-differentiated rates:
5 Peak Hours
6 Monday through Friday excluding holidays:
7 May through September, 10:00 a.m. to 4:00 p.m.
8 October through April, 9:00 a.m. to 12:00 noon, and
9 5:00 p.m. to 8:00 p.m.
10 Off-Peak Hours
11 All other hours.
12 Narragansett defines its time periods as follows:
13 Peak Hours
14 Monday through Friday excluding holidays:
15 June through September, 9:00 a.m. to 6:00 p.m.
16 December through February, 8:00 a.m. to 8:00 p.m.
17 Shoulder Hours
18 Monday through Friday excluding holidays:
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 21 of 22
1 June through September, 8:00 a.m. to 9:00 a.m., and
2 6:00 p.m. to 10:00 p.m.
3 December through February, 7:00 a.m. to 8:00 a.m., and
4 8:00 p.m. to 10:00 p.m.
5 October through November and March through May,
6 8:00 a.m. to 9:00 p.m.
7 Off-Peak Hours
8 All other hours.
9 All companies define holidays as follows:
10 New Year's Day Columbus Day
11 President's Day Veteran's Day
12 Memorial Day Thanksgiving Day
13 Independence Day Christmas Day
14 Labor Day
15
16 Q. Are the differences in the definition of billing demand and TOU time periods between
17 Blackstone/Newport and Narragansett taken into consideration in the estimation of billing
18 determinants for affected rate classes.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _____
Testimony of J. J. Bonner
Page 22 of 22
1 A. Yes. As shown in Exhibit JJB-3 and Exhibit JJB-4, these definitional differences are taken
2 into account. Where such considerations were material, they are so noted on the
3 individual pages of the exhibit.
4
5 Q. Does this conclude your testimony?
6 A. Yes, it does.
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibits
of
James J.Bonner, Jr.
JJB-1 Blackstone - Comparison of Availability Provisions of Rates
JJB-2 Newport - Comparison of Availability Provisions of Rates
JJB-3 Blackstone - Billing Determinants
JJB-4 Newport - Billing Determinants
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JJB-1
Exhibit JJB-1
Blackstone - Comparison of Availability Provisions of Rates
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. _______
Exhibit JJB-1
Page 1 of 7
THE NARRAGANSETT ELECTRIC COMPANY
BLACKSTONE VALLEY ELECTRIC COMPANY
COMPARISON OF AVAILABILITY PROVISIONS OF RATES
BLACKSTONE'S RATE
RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-1
Available only to residential customers whose energy consumption is
<30,000 kWh.
NARRAGANSETT'S RATE
BASIC RESIDENTIAL RATE A-16
Available for all domestic purposes in an individual private dwelling or an
individual private apartment. Notwithstanding the foregoing, service is not
available under this rate for any customer required to take service on the
Residential Time-of-Use Rate A-32. Service is also available for farm
customers where all electricity is delivered by the Company.
RESIDENTIAL WATER HEATING CONTROL RATE A-18
This rate is closed to new customers as of January 1, 1998. Available for
all domestic purposes wherein the customer has installed and has in regular
operation an electric water heater.
BLACKSTONE'S RATE
RESIDENTIAL SSI RETAIL DELIVERY SERVICE RATE R-2
Available to residential Customers that meet the following criteria:
1. Must be the head of a household or principal wage earner.
2. Must be presently receiving Supplemental Security income from the
Social Security Administration or one of the following from the
appropriate Rhode Island agencies: Medicaid, Food Stamps, General
Public Assistance or Aid to Families with Dependent Children.
NARRAGANSETT'S RATE
LOW INCOME RATE A-60
Available only to currently qualified customers for all domestic purposes
in an individual private dwelling or an individual apartment, providing
such customer meets both of the following criteria:
1. Must be the head of a household or principal wage earner.
2. Must be presently receiving Supplemental Security Income from the
Social Security Administration or one of the following from the
appropriate Rhode Island agencies: Medicaid, Food Stamps, General
Public Assistance or Aid to Families with Dependent Children.
BLACKSTONE'S RATE
RESIDENTIAL SPACE HEATING RETAIL DELIVERY SERVICE RATE R-3
Closed to new customers. Available only to residential customers where
electricity is the sole source of energy used for comfort heating and water
heating and energy consumption is <30,000 kWh.
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. ________
Exhibit JJB-1
Page 2 of 7
BLACKSTONE'S RATE
LARGE RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-4
Available to residential customers whose actual or estimated energy
consumption is at least 6,000 kWh but < 30,000 kWh.
NARRAGANSETT'S RATE
RESIDENTIAL TIME-OF-USE RATE A-32
Available for all domestic purposes in an individual private dwelling or an
individual private apartment. Service is also available for farm customers
where delivery is provided by the Company. A church and adjacent buildings
owned and operated by the church may be served under this rate, but any
such buildings separated by public ways must be billed separately.
The Company will require any Customer taking service on the Basic
Residential Rate A- 16 or the Residential Water Heater Control Rate A- 18
to take service on this rate if the Customer's usage for the previous 12
months exceeds 30,000 kWh. The Company will require any new customer to
take service under this rate if the Company estimates that the Customer's
annual usage will exceed 30,000 kWh. A Customer who has been placed on this
rate pursuant to this paragraph may transfer to another available rate if
the Customer's usage for the previous 12 months is less than 24,000 kWh.
RESIDENTIAL STORAGE HEATING RATE E-30
Available to customers who were served under Limited Residential Service -
Storage Heating (E01) on July 1, 1990.
GENERAL C&I BACK-UP SERVICE RATE B-02
Apply to Customers in the class identified below: (I) who receive all or
any portion of their electric supply from non-emergency generation unit(s)
with a nameplate rating greater than 30 kW ("Generation Units"), where
electricity received by the Customer from the Generation Units is not being
delivered over Company-owned distribution facilities pursuant to an
applicable retail delivery tariff, and (ii) who expect the Company to
provide retail delivery service to supply the Customer's load at the
service location when the Generation Units are not supplying all of that
load.
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. _______
Exhibit JJB-1
Page 3 of 7
BLACKSTONE'S RATE
SMALL SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-1
Available to customers whose actual or estimated average monthly demand is
less than 500 kW and annual energy consumption is less than 54,000 kWh.
NARRAGANSETT'S RATE
SMALL C&I RATE C-06
Available for all purposes. The Company may require any customer with a
12-month average demand greater than 200 kW to take service on the 200 kW
Demand Rate G-32. If any electricity is delivered hereunder at a given
location, then all electricity delivered by the Company at such location
shall be delivered hereunder, except such electricity as may be delivered
under the provisions of the Limited Service - Business Space Heating (V-02)
rate.
STORAGE COOLING RATE E-40
Available to any customer solely for use in operating a full storage air
conditioning system.
BLACKSTONE'S RATE
MEDIUM SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-2
Available only to customers whose actual or estimated average monthly
demand is less than 500 kW and whose actual or estimated annual energy
consumption is 54,000 kWh or more.
NARRAGANSETT'S RATE
GENERAL C&I RATE G-02
Available for all purposes to customers with a Demand of 10 kW or more. The
Company may require any customer with a 12-month average Demand greater
than 200 kW to take service on the 200 kW Demand Rate G-32.
BLACKSTONE'S RATE
MEDIUM PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-5
Available only to customers whose actual or estimated average monthly
demand is at least 15 kW but less than 500 kW or whose actual or estimated
annual energy consumption is 54,000 kWh or more.
NARRAGANSETT'S RATE
200 KW DEMAND RATE G-32
The Company shall place on this rate any customer who has a 12-month
average Demand of 200 kW or greater for 3 consecutive months as soon as
practicable.
BLACKSTONE'S RATE
LARGE SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-4
Mandatory for all customers whose actual or estimated average monthly
demand is 500 kW or more.
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. _______
Exhibit JJB-1
Page 4 of 7
BLACKSTONE'S RATE
LARGE PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-6
Mandatory for all customers whose actual or estimated average monthly
demand is 500 kW or more.
NARRAGANSETT'S RATE
3000 KW DEMAND RATE G-62
The Company shall place on this rate any customer who has a 12-month
maximum Demand of 3,000 kW or greater. Delivery service can be taken under
this rate by customers who do not meet the qualifications on a voluntary
basis. New Customers: Delivery service will initially be taken under this
rate by any new customer who requests delivery service capability of 3,375
kVA or greater. Transfers From Rate G-62: Any customer whose 12-month
maximum demand is less than 2,700 kW for twelve consecutive months may
elect to transfer from the 3,000 kW Demand Rate G-62 to another available
rate.
BLACKSTONE'S RATE
LARGE SECONDARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-4
Available to any Customer served at secondary voltage, who furnishes its
own electric power supply for all or part of its total electric retail
delivery service requirements.
NARRAGANSETT'S RATE
SMALL C&I BACK-UP SERVICE RATE B-06
Apply to Customers in the class identified below: (I) who receive all or
any portion of their electric supply from non-emergency generation unit(s)
with a nameplate rating greater than 30 kW ("Generation Units"), where
electricity received by the Customer from the Generation Units is not being
delivered over Company-owned distribution facilities pursuant to an
applicable retail delivery tariff, and (ii) who expect the Company to
provide retail delivery service to supply the Customer's load at the
service location when the Generation Units are not supplying all of that
load. Electric delivery service under this rate is applicable to those
Customers being served by Generation Unit(s) installed on or after April 1,
1998 and would otherwise be served under the Company's Small C&I Rate C-06
if the Generation Units were not supplying electricity to the Customer.
This tariff shall not apply to customers with a contracted demand of 25 kVA
or less.
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. _______
Exhibit JJB-1
Page 5 of
BLACKSTONE'S RATE
LARGE PRIMARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-6
Available to any Customer served at primary voltage, who furnishes its own
electric power supply for all or part of its total electric retail delivery
service requirements.
NARRAGANSETT'S RATE
200 KW DEMAND BACK-UP SERVICE RATE B-32
This service shall apply to Customers in the class identified below:
(I) who receive all or any portion of their electric supply from
non-emergency generation unit(s) with a nameplate rating greater than 30 kW
("Generation Units"), where electricity received by the Customer from the
Generation Units is not being delivered over Company-owned distribution
facilities pursuant to an applicable retail delivery tariff, and (ii) who
expect the Company to provide retail delivery service to supply the
Customer's load at the service location when the Generation Units are not
supplying all of that load.
3,000 KW DEMAND BACK-UP SERVICE RATE B-62
This service shall apply to Customers in the class identified below:
(I) who receive all or any portion of their electric supply from
non-emergency generation unit(s) with a nameplate rating greater than 30 kW
("Generation Units"), where electricity received by the Customer from the
Generation Units is not being delivered over Company-owned distribution
facilities pursuant to an applicable retail delivery tariff, and (ii) who
expect the Company to provide retail delivery service to supply the
Customer's load at the service location when the Generation Units are not
supplying all of that load. Electric delivery service under this rate is
applicable to those Customers being served by Generation Unit(s) installed
on or after April 1, 1998 and would otherwise be served under the Company's
3,000 kW Demand Rate G-62 if the Generation Units were not supplying
electricity to the Customer. This tariff shall not apply to customers with
a contracted demand of 25 kVA or less.
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. _______
Exhibit JJB-1
Page 6 of 7
NARRAGANSETT'S RATE
LIMITED SERVICE - ALL ELECTRIC LIVING RATE T-06
The availability of this rate is limited to those customers who were served
under Limited Service - All Electric Living Rate T, on May 1, 1984 and have
continuously been served under the AllElectric Living Rate since that date.
LIMITED SERVICE - BUSINESS SPACE HEATING RATE V-02
The availability of this rate is limited to those customers who were served
under Limited Service - Business Space Heating Rate V on May 1, 1984 and
have continuously been served under the Business Space Heating Rate since
that date.
BLACKSTONE'S RATE
GENERAL SPACE HEATING RETAIL DELIVERY SERVICE RATE H-1
Closed to new Customers. Available only to Customers whose actual or
estimated average monthly demand is < 500 kW that were taking service from
the former Total Electric Living Rate -Limited, R.I.P.U.C. No. 205-L prior
to April 1, 1988.
GENERAL HEATING RETAIL DELIVERY SERVICE RATE H-2
Closed to new Customers. Available to customers that were taking service
under the Special Space Heating Provision - Limited of former General
Service Rate R.I.P.U.C. No. 201-N prior to April 1, 1988.
CONTROLLED WATER HEATING RETAIL DELIVERY SERVICE RATE W-1
Closed to new Customers. Available to Customers that were taking retail
delivery service from the Company under former Controlled Off-Peak Rate,
R.I.P.U.C. No. 102-N before 10-28-92.
<PAGE>
Narragansett Electric Company
Blackstone Valley Electric Company
R.I.P.U.C. Docket No. ________
Exhibit JJB-1
Page 7 of 7
NARRAGANSETT'S RATE
LIMITED TRAFFIC SIGNAL SERVICE RATE R-02
Availability of this rate is limited to the following customers and
locations: those customers and locations who were served under Traffic
Signal Rate R - R.I.P.U.C. No. 937 on May 10, 1992.
LIMITED SERVICE - PRIVATE LIGHTING RATE S-10
Private lighting and floodlighting service is available under this rate to
any Customer who prior to the date of this rate was served on Limited
Service-Private Lighting Rate S-6, R.I.P.U.C. No. 872. There will be no new
installations or relocations under this rate.
LIMITED STREET LIGHTING RATE S-12
Street Lighting Service is available under this rate to any Customer who
prior to the date of this rate was served on Limited Street Lighting
Service (S-7), R.I.P.U.C. NO. 873. There will be no installations or
relocations under this rate.
BLACKSTONE'S RATE
LIGHTING RETAIL DELIVERY SERVICE RATE S-1
Available to all Customers where electricity is supplied to lighting
equipment owned and maintained by the Company on Company owned poles, for
dusk-to-dawn operation of approximately 4,000 burning hours per year.
NARRAGANSETT'S RATE
GENERAL STREETLIGHTING SERVICE RATE S-14
Street Lighting Service is available under this rate to any city, town, or
other public authority hereinafter referred to as the Customer, in
accordance with the provisions and the specifications hereinafter set forth
for all installations made after January 1, 1990.
1. For municipally-owned or accepted roadways, which includes those
classified as "private ways" for which a municipality has agreed to
supply street lighting service.
2. Service under this rate is contingent upon Company ownership and
maintenance of street lighting equipment.
3. Service under this rate is not available for limited access highways or
the access and egress ramps.
4. Service under this rate is available to private contractors for street
lighting service for streets which have not yet been accepted by the
municipality.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JJB-2
Exhibit JJB-2
Newport - Comparison of Availability Provisions of Rates
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 1 of 7
THE NARRAGANSETT ELECTRIC COMPANY
NEWPORT ELECTRIC COMPANY
COMPARISON OF AVAILABILITY PROVISIONS OF RATES
NEWPORT'S RATE
RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-1
Available only to residential customers whose energy consumption is
<30,000 kWh.
NARRAGANSETT'S RATE
BASIC RESIDENTIAL RATE A-16
Available for all domestic purposes in an individual private dwelling or an
individual private apartment. Notwithstanding the foregoing, service is not
available under this rate for any customer required to take service on the
Residential Time-of-Use Rate A-32. Service is also available for farm
customers where all electricity is delivered by the Company.
RESIDENTIAL WATER HEATING CONTROL RATE A-18
This rate is closed to new customers as of January 1, 1998, Available for
all domestic purposes wherein the customer has installed and has in regular
operation an electric water heater.
NEWPORT'S RATE
RESIDENTIAL SSI RETAIL DELIVERY SERVICE RATE R-2
Available to residential Customers that meet the following criteria:
1. Must be the head of a household or principal wage earner.
2. Must be presently receiving Supplemental Security Income from the
Social Security Administration or one of the following from the
appropriate Rhode Island agencies: Medicaid, Food Stamps, General
Public Assistance or Aid to Families with Dependent Children.
NARRAGANSETT'S RATE
LOW INCOME RATE A-60
Available only to currently qualified customers for all domestic purposes
in an individual private dwelling or an individual apartment, providing
such customer meets both of the following criteria:
1. Must be the head of a household or principal wage earner.
2. Must be presently receiving Supplemental Security Income from the
Social Security Administration or one of the following from the
appropriate Rhode Island agencies: Medicaid, Food Stamps, General
Public Assistance or Aid to Families with Dependent Children.
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 2 of 7
NEWPORT'S RATE
LARGE RESIDENTIAL RETAIL DELIVERY SERVICE RATE R-4
Available to residential customers whose actual or estimated energy
consumption is at least 6,000 kWh but < 30,000 kWh.
NARRAGANSETT'S RATE
RESIDENTIAL TIME-OF-USE RATE A-32
Available for all domestic purposes in an individual private dwelling or an
individual private apartment. Service is also available for farm customers
where delivery is provided by the Company. A church and adjacent buildings
owned and operated by the church may be served under this rate, but any
such buildings separated by public ways must be billed separately.
The Company will require any Customer taking service on the Basic
Residential Rate A-16 or the Residential Water Heater Control Rate A-18
to take service on this rate if the Customer's usage for the previous 12
months exceeds 30,000 kWh. The Company will require any new customer to
take service under this rate if the Company estimates that the Customer's
annual usage will exceed 30,000 kWh. A Customer who has been placed on this
rate pursuant to this paragraph may transfer to another available rate if
the Customer's usage for the previous 12 months is less than 24,000 kWh.
RESIDENTIAL STORAGE HEATING RATE E-30
Available to customers who were served under Limited Residential Service -
Storage Heating (E-01) on July 1, 1990.
GENERAL C&I BACK-UP SERVICE RATE B-02
Apply to Customers in the class identified below: (I) who receive all or
any portion of their electric supply from non-emergency generation unit(s)
with a nameplate rating greater than 30 kW ("Generation Units"), where
electricity received by the Customer from the Generation Units is not being
delivered over Company-owned distribution facilities pursuant to an
applicable retail delivery tariff, and (ii) who expect the Company to
provide retail delivery service to supply the Customer's load at the
service location when the Generation Units are not supplying all of that
load.
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 3 of 7
NEWPORT'S RATE
SMALL SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-1
Available to customers whose actual or estimated average monthly demand is
less than 500 kW and annual energy consumption is less than 54,000 kWh.
NARRAGANSETT'S RATE
SMALL C&I RATE C-06
Available for all purposes. The Company may require any customer with a
12-month average demand greater than 200 kW to take service on the 200 kW
Demand Rate G-32. If any electricity is delivered hereunder at a given
location, then all electricity delivered by the Company at such location
shall be delivered hereunder, except such electricity as may be delivered
under the provisions of the Limited Service - Business Space Heating (V-02)
rate.
STORAGE COOLING RATE E40
Available to any customer solely for use in operating a full storage air
conditioning system.
NEWPORT'S RATE
MEDIUM SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-2
Available only to customers whose actual or estimated average monthly
demand is less than 500 kW and whose actual or estimated annual energy
consumption is 54,000 kWh or more.
NARRAGANSETT'S RATE
GENERAL C&I RATE G-02
Available for all purposes to customers with a Demand of 10 kW or more. The
Company may require any customer with a 12-month average Demand greater
than 200 kW to take service on the 200 kW Demand Rate G-32.
NEWPORT'S RATE
MEDIUM PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE G-5
Available only to customers whose actual or estimated average monthly
demand is at least 15 kW but less than 500 kW or whose actual or estimated
annual energy consumption is 54,000 kWh or more.
NARRAGANSETT'S RATE
200 KW DEMAND RATE G-32
The Company shall place on this rate any customer who has a 12-month
average Demand of 200 kW or greater for 3 consecutive months as soon as
practicable.
NEWPORT'S RATE
LARGE SECONDARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-4
Mandatory for all customers whose actual or estimated average monthly
demand is 500 kW or more.
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 4 of 7
NEWPORT'S RATE
LARGE PRIMARY VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE T-6
Mandatory for all customers whose actual or estimated average monthly
demand is 500 kW or more.
NARRAGANSETT'S RATE
3000 KW DEMAND RATE G-62
The Company shall place on this rate any customer who has a 12-month
maximum Demand of 3,000 kW or greater. Delivery service can be taken under
this rate by customers who do not meet the qualifications on a voluntary
basis. New Customers: Delivery service will initially be taken under this
rate by any new customer who requests delivery service capability of
3,375 kVA or greater. Transfers From Rate G-62: Any customer whose 12-month
maximum demand is less than 2,700 kW for twelve consecutive months may
elect to transfer from the 3,000 kW Demand Rate G-62 to another available
rate.
NEWPORT'S RATE
TRANSMISSION VOLTAGE GENERAL RETAIL DELIVERY SERVICE RATE C-1
Available only to the Dept. of the Navy under the provisions of the
contract dated May 1, 1961.
NEWPORT'S RATE
LARGE SECONDARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-4
Available to any Customer served at secondary voltage, who furnishes its
own electric power supply for all or part of its total electric retail
delivery service requirements.
NARRAGANSETT'S RATE
SMALL C&I BACK-UP SERVICE RATE B-06
Apply to Customers in the class identified below:
(I) who receive all or any portion of their electric supply from
non-emergency generation unit(s) with a nameplate rating greater than 30 kW
("Generation Units"), where electricity received by the Customer from the
Generation Units is not being delivered over Company-owned distribution
facilities pursuant to an applicable retail delivery tariff, and (ii) who
expect the Company to provide retail delivery service to supply the
Customer's load at the service location when the Generation Units are not
supplying all of that load.
Electric delivery service under this rate is applicable to those Customers
being served by Generation Unit(s) installed on or after April 1, 1998 and
would otherwise be served under the Company's Small C&I Rate C-06 if the
Generation Units were not supplying electricity to the Customer. This
tariff shall not apply to customers with a contracted demand of 25 kVA or
less.
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 5 of 7
NEWPORT'S RATE
LARGE PRIMARY VOLTAGE AUXILIARY GENERAL RETAIL DELIVERY SERVICE RATE A-6
Available to any Customer served at primary voltage, who furnishes its own
electric power supply for all or part of its total electric retail delivery
service requirements.
NARRAGANSETT'S RATE
200 KW DEMAND BACK-UP SERVICE RATE B-32
This service shall apply to Customers in the class identified below:
(I) who receive all or any portion of their electric supply from
non-emergency generation unit(s) with a nameplate rating greater than 30 kW
("Generation Units"), where electricity received by the Customer from the
Generation Units is not being delivered over Company-owned distribution
facilities pursuant to an applicable retail delivery tariff, and (ii) who
expect the Company to provide retail delivery service to supply the
Customer's load at the service location when the Generation Units are not
supplying all of that load.
3,000 KW DEMAND BACK-UP SERVICE RATE B-62
This service shall apply to Customers in the class identified below:
(I) who receive all or any portion of their electric supply from
non-emergency generation unit(s) with a nameplate rating greater than 30 kW
("Generation Units"), where electricity received by the Customer from the
Generation Units is not being delivered over Company-owned distribution
facilities pursuant to an applicable retail delivery tariff, and (ii) who
expect the Company to provide retail delivery service to supply the
Customer's load at the service location when the Generation Units are not
supplying all of that load. Electric delivery service under this rate is
applicable to those Customers being served by Generation Unit(s) installed
on or after April 1, 1998 and would otherwise be served under the Company's
3,000, kW Demand Rate G-62 if the Generation Units were not supplying
electricity to the Customer. This tariff shall not apply to customers with
a contracted demand of 25 kVA or less.
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 6 of 7
NARRAGANSETT'S RATE
LIMITED SERVICE - ALL ELECTRIC LIVING RATE T-06
The availability of this rate is limited to those customers who were served
under Limited Service - All Electric Living Rate T, on May 1, 1984 and have
continuously been served under the All Electric Living Rate since that date.
NEWPORT'S RATE
GENERAL SPACE HEATING RETAIL DELIVERY SERVICE RATE H-1
Closed to new Customers. Available only to Customers whose actual or
estimated average monthly demand is < 500 kW that were taking service from
the former Total Electric Living Rate -Limited, R.I.P.U.C. No. 205-L prior
to April 1, 1988.
NARRAGANSETT'S RATE
LIMITED SERVICE - BUSINESS SPACE HEATING RATE V-02
The availability of this rate is limited to those customers who were served
wider Limited Service - Business Space Heating Rate V on May 1, 1984 and
have continuously been served under the Business Space Heating Rate since
that date.
NEWPORT'S RATE
GENERAL HEATING RETAIL DELIVERY SERVICE RATE H-2
Closed to new Customers. Available to customers that were taking service
under the Special Space Heating Provision - Limited of former General
Service Rate R.I.P.U.C. No. 201-N prior to April 1, 1988.
CONTROLLED WATER HEATING RETAIL DELIVERY SERVICE RATE W-1
Closed to new Customers. Available to Customers that were taking retail
delivery service from the Company under former Controlled Off-Peak Rate,
R.I.P.U.C. No. 102-N before 10-28-92.
<PAGE>
Narragansett Electric Company
Newport Electric Corporation
R.I.P.U.C. Docket No. _______
Exhibit JJB-2
Page 7 of 7
NARRAGANSETT'S RATE
LIMITED TRAFFIC SIGNAL SERVICE RATE R-02
Availability of this rate is limited to the following customers and
locations: those customers and locations who were served under Traffic
Signal Rate R - R.I.P.U.C. No. 937 on May 10, 1992.
LIMITED SERVICE - PRIVATE LIGHTING RATE S-10
Private lighting and floodlighting service is available under this rate to
any Customer who prior to the date of this rate was served on Limited
Service-Private Lighting Rate S-6, R.I.P.U.C. No. 872. There will be no new
installations or relocations under this rate.
LIMITED STREET LIGHTING RATE S-12
Street Lighting Service is available under this rate to any Customer who
prior to the date of this rate was served on Limited Street Lighting
Service (S-7), R.I.P.U.C. NO. 873. There will be no installations or
relocations under this rate.
NEWPORT'S RATE
LIGHTING RETAIL DELIVERY SERVICE RATE S-1
Available to all Customers where electricity is supplied to lighting
equipment owned and maintained by the Company on Company owned poles, for
dusk-to-dawn operation of approximately 4,000 burning hours per year.
NARRAGANSETT'S RATE
GENERAL STREETLIGHTING SERVICE RATE S-14
Street Lighting Service is available under this rate to any city, town, or
other public authority hereinafter referred to as the Customer, in
accordance with the provisions and the specifications hereinafter set forth
for all installations made after January 1, 1990.
1. For municipally-owned or accepted roadways, which includes those
classified as "private ways" for which a municipality has agreed to
supply street lighting service.
2. Service under this rate is contingent upon Company ownership and
maintenance of street lighting equipment.
3. Service under this rate is not available for limited access highways or
the access and egress ramps.
4. Service under this rate is available to private contractors for street
lighting service for streets which have not yet been accepted by the
municipality.
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JJB-3
Exhibit JJB-3
Blackstone - Billing Determinants
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 1 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate R-1 v. Narragansett's Rate A-16
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 876,261 876,261
Energy (kWh) 362,568,042 362,568,042
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 2 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate R-2 v. Narragansett's Rate A-60
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 25,844 25,844
Energy (kWh) 10,464,104 10,464,104
First 300 kWh 6,540,065 6,540,065
Excess 300 kWh 3,924,039 3,924,039
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 3 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate R-3 v. Narragansett's Rate A-16
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 10,622 10,622
Energy (kWh) 9,162,722 9,162,722
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 4 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate R-4 v. Narragansett's Rate A-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 1,821 1,821
Energy (kWh) 4,487,447 4,487,447
Peak Energy (kWh) 815,510 0
Off-Peak Energy (KWh) 3,671,937 0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 5 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate G-1 v. Narragansett's Rate C-06
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 87,619 85,368
Unmetered 2,251
Energy (kWh) 43,670,643 43,670,643
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 6 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate G-2: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 31,059
Demand (kW) 1,140,854
Energy (kWh) 313,855,524
Blackstone's Rate G-2 v. Narragansett's Rate C-06
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 17,427 17,427
Demand (kW) 293,038
Energy (kWh) 55,207,092 55,207,092
Blackstone's Rate G-2 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 12,852 12,852
Demand (kW) 621,666 597,149
Energy (kWh) 189,662,772 189,662,772
Blackstone's Rate G-2 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 780 780
Demand (kW) 226,150 269,038
Energy (kWh) 68,985,660 68,985,660
Note:
1. For Blackstone's Rate G-2 customers apportioned to Narragansett's C-06, the revenue for each
customer was calculation under both Narragansett's Rate C-06 and G-02. The Blackstone Rate G-2
customers were then transferred to the Narragansett rate producing the lower revenue.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 7 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate G-5: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 394
Demand (kW) 73,140
Energy (kWh) 23,108,580
Blackstone's Rate G-5 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 228 228
Demand (kW) 20,540 27,078
Energy (kWh) 7,714,640 7,714,640
Blackstone's Rate G-5 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 166 166
Demand (kW) 52,600 58,829
Energy (kWh) 15,393,940 15,393,940
Note:
1. Blackstone's Rate G-5 determinants were apportioned among Narragansett Rates G-02 and G-32 based
on the availability provisions of Narragansett's rates.
2. Narragansett's billing demands are estimated based upon Blackstone's Rate G-5 load research data
using Narragansett TOU hours.
3. Billing demands used to determine whether a Blackstone Rate G-5 is to be transferred to
Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest
demand in the previous 11 months less 10 kW.
4. Billing demands used to determine whether a Blackstone Rate G-5 customer is to be transferred to
Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of
monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11
months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 8 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate T-2: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 856
Demand (kW) 110,812
Energy (kWh) 45,916,407
Peak Energy (kWh) 9,573,412
Off-Peak Energy (kWh) 36,342,995
Blackstone's Rate T-2 v. Narragansett's Rate C-06
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 54 54
Demand (kW) 707 1,888
Energy (kWh) 93,312 93,312
Peak Energy (kWh) 13,722 0
Off-Peak Energy (kWh) 79,590 0
Blackstone's Rate T-2 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 551 551
Demand (kW) 31,864 24,796
Energy (kWh) 13,353,435 13,353,435
Peak Energy (kWh) 2,692,710 0
Off-Peak Energy (kWh) 10,660,725 0
Blackstone's Rate T-2 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 251 251
Demand (kW) 78,241 99,892
Energy (kWh) 32,469,660 32,469,660
Peak Energy (kWh) 6,866,980 0
Off-Peak Energy (kWh) 25,602,680 0
Note:
1. For Blackstone's Rate T-2 customers apportioned to Narragansett's C-06, the revenue for each
customer was calculation under both Narragansett's Rate C-06 and G-02. The Blackstone Rate T-2
customers were then transferred to the Narragansett rate producing the lower revenue.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 9 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate T-4 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 372 372
Demand (kW) 195,414 225,770
Energy (kWh) 78,036,479 78,036,479
Peak Energy (kWh) 18,111,219 0
Off-Peak Energy (kWh) 59,925,260 0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 10 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate T-5: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 52
Demand (kW) 20,892
Energy (kWh) 8,474,950
Peak Energy (kWh) 2,007,100
Off-Peak Energy (kWh) 6,467,850
Blackstone's Rate T-5 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 7 7
Demand (kW) 358 288
Energy (kWh) 114,950 114,950
Peak Energy (kWh) 27,650 0
Off-Peak Energy (kWh) 87,300 0
Blackstone's Rate T-5 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 45 45
Demand (kW) 20,534 20,534
Energy (kWh) 8,360,000 8,360,000
Peak Energy (kWh) 1,979,450 0
Off-Peak Energy (kWh) 6,380,550 0
Note:
1. Blackstone's Rate T-5 determinants were apportioned among Narragansett Rates G-02 and G-32 based
on the availability provisions of Narragansett's rates.
2. Narragansett's billing demands are estimated based upon Blackstone's Rate T-5 load research data
using Narragansett TOU hours.
3. Billing demands used to determine whether a Blackstone Rate T-5 is to be transferred to
Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest
demand in the previous 11 months less 10 kW.
4. Billing demands used to determine whether a Blackstone Rate T-5 customer is to be transferred to
Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of
monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11
months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 11 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate T-6: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 692
Demand (kW) 792,182
Energy (kWh) 369,857,394
Peak Energy (kWh) 78,028,788
Off-Peak Energy (kWh) 291,828,606
Blackstone's Rate T-6 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 656 656
Demand (kW) 682,889 782,155
Energy (kWh) 300,621,894 300,621,894
Peak Energy (kWh) 66,237,289 0
Off-Peak Energy (kWh) 234,384,605 0
Blackstone's Rate T-6 v. Narragansett's Rate G-62
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 36 36
Demand (kW) 109,293 142,198
Energy (kWh) 69,235,500 69,235,500
Peak Energy (kWh) 11,791,499 0
Off-Peak Energy (kWh) 57,444,001 0
Note:
1. Blackstone's Rate T-6 determinants were apportioned among Narragansett Rates G-32 and G-62 based
on the availability provisions of Narragansett's rates.
2. Billing demands used to determine whether a Blackstone Rate T-2 customer is to be transferred to
Narragansett's Rate G-32 and G-62 are the highest of: (1) the customer's monthly peak hour demand,
(2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the
previous 11 months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 12 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate A-6 v. Narragansett's Rate B-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 48 48
Demand (kW) 31,497 31,497
Energy (kWh) 6,085,455 6,085,455
Peak Energy (kWh) 1,172,792 0
Off-Peak Energy (kWh) 4,912,663 0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 13 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate H-1: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 204
Demand (kW) 0
Energy (kWh) 3,639,022
Blackstone's Rate H-1 v. Narragansett's Rate C-06
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 85 85
Energy (kWh) 225,822 225,822
Blackstone's Rate H-1 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 104 104
Demand (kW) 0 8,848
Energy (kWh) 2,380,400 2,380,400
Blackstone's Rate H-1 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 15 15
Demand (kW) 0 3,845
Energy (kWh) 1,032,800 1,032,800
Note:
1. Blackstone's Rate H-1 determinants were apportioned among Narragansett Rates C-06, G-02 and G-32
based on the availability provisions of Narragansett's rates.
2. Narragansett's billing demands are estimated based upon Blackstone's Rate H-1 load research data
using Narragansett TOU hours.
3. Billing demands used to determine whether a Blackstone Rate H-1 is to be transferred to
Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest
demand in the previous 11 months less 10 kW.
4. Billing demands used to determine whether a Blackstone Rate H-1 customer is to be transferred to
Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of
monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11
months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 14 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate H-2: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 964
Demand (kW) 0
Energy (kWh) 2,290,392
Blackstone's Rate H-2 v. Narragansett's Rate C-06
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 940 940
Energy (kWh) 2,034,902 2,034,902
Blackstone's Rate H-2 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 12 12
Demand (kW) 0 0
Energy (kWh) 33,090 33,090
Blackstone's Rate H-2 v. Narragansett's Rate G-32
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 12 12
Demand (kW) 0 2,386
Energy (kWh) 222,400 222,400
Note:
1. Blackstone's Rate H-2 is a supplementary rate. Each customer's Rate H-2 usage was combined with
the customer's principal rate usage. Based on the combined usage, revenue for each customer was
colculated under both Narragansett's Rates C-06 and G-02. The Blackstone Rate H-2 customers were
then transferred to the Narragansett rate producing the lower revenue.
2. The billing determinants for Blackstone's H-2 customers to be transferred to Narragansett's Rate
G-32 are identical to the determinants shown in Schedule JJB-2
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 15 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate W-1: Total
Blackstone's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 15,781
Energy (kWh) 3,602,371
Blackstone's Rate W-1 v. Narragansett's Rate A-16
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 15,594 15,594
Energy (kWh) 3,568,998 3,568,998
Blackstone's Rate W-1 v. Narragansett's Rate C-06
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 187 187
Energy (kWh) 33,373 33,373
Blackstone's Rate W-1 v. Narragansett's Rate G-02
Blackstone's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 0 0
Energy (kWh) 0 0
Note:
1. Blackstone's Rate W-1 is a supplementary rate. Each customer's Rate W-1 usage was combined with
the customer's principal rate usage. Based on the combined usage, revenue for each customer was
colculated under both Narragansett's Rates C-06 and G-02. The Blackstone Rate W-1 customers were
then transferred to the Narragansett rate producing the lower revenue.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 3
Page 16 of 16
Narragansett Electric Company
Blackstone Valley Electric Company
Original Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Blackstone's Rate S-1 Streetlighting Rate
Blackstone's Blackstone's
Blackstone's Lamp Blackstone's Service & Special Fixture Annual kWh Total Annual
Lighting Code Wattage Lumen Size Pole Type Fixture Type Pricing Option Count per Light Energy
- -----------------------------------------------------------------------------------------------------------------------------------
Metal Halide
<S> <C> <C> <C> <C> <C> <C> <C> <C>
0300-4-120 250 20,000 OH_WoodLine FldLt 5 1,180 5,900
0466-4-120 400 40,000 OH_WoodLine FldLt 28 1,832 51,296
------ ----------
Total Metal Halide 33 57,196
- -----------------------------------------------------------------------------------------------------------------------------------
Mercury Vapor
0130-2-110 100 4,200 OH_WoodLine StLt 2,279 511 1,164,569
0130-2-211 100 4,200 OH_WoodLitg StLt CustPaidPole 1 511 511
0209-2-110 175 8,600 OH_WoodLine StLt 465 822 382,230
0209-2-140 175 8,600 OH_WoodLine T&C 16 822 13,152
0209-2-211 175 8,600 OH_WoodLitg StLt CustPaidPole 2 822 1,644
0209-2-610 175 8,600 UG_Aluminum StLt 28 822 23,016
0209-2-640 175 8,600 UG_Aluminum T&C 1 822 822
0209-2-940 175 8,600 URD_WoodPost T&C 268 822 220,296
0418-2-612 350 8,600 UG_Aluminum StLt TwinFixts 18 1,644 29,592
0474-2-110 400 22,500 OH_WoodLine StLt 105 1,864 195,720
0474-2-120 400 22,500 OH_WoodLine FldLt 99 1,864 184,536
0474-2-310 400 22,500 OH_Aluminum StLt 3 1,864 5,592
0474-2-320 400 22,500 OH_Aluminum FldLt 2 1,864 3,728
0474-2-610 400 22,500 UG_Aluminum StLt 33 1,864 61,512
0948-2-612 800 22,500 UG_Aluminum StLt TwinFixts 3 3,728 11,184
1135-2-120 1,000 63,000 OH_WoodLine FldLt 23 4,463 102,649
------ ----------
Total Mercury Vapor 3,346 2,400,753
- -----------------------------------------------------------------------------------------------------------------------------------
Sodium Vapor
0061-3-110 50 3,300 OH_WoodLine StLt 14 240 3,360
0085-3-110 70 5,800 OH_WoodLine StLt 9,055 334 3,024,370
0085-3-120 70 5,800 OH_WoodLine FldLt 9 334 3,006
0085-3-170 70 5,800 OH_WoodLine StLtSC 1,804 334 602,536
0085-3-440 70 5,800 URD_Fiberglass T&C 25 334 8,350
0085-3-710 70 5,800 UG_WoodLitg StLt 1 334 334
0085-3-810 70 5,800 URD_LamWood StLt 38 334 12,692
0085-3-940 70 5,800 URD_WoodPost T&C 104 334 34,736
0121-3-110 100 9,500 OH_WoodLine StLt 1,813 476 862,988
0121-3-140 100 9,500 OH_WoodLine T&C 3 476 1,428
0121-3-170 100 9,500 OH_WoodLine StLtSC 476 476 226,576
0121-3-440 100 9,500 URD_Fiberglass T&C 6 476 2,856
0121-3-460 100 9,500 URD_Fiberglass SBA 26 476 12,376
0121-3-610 100 9,500 UG_Aluminum StLt 95 476 45,220
0121-3-940 100 9,500 URD_WoodPost T&C 30 476 14,280
0176-3-110 150 16,000 OH_WoodLine StLt 30 692 20,760
0176-3-120 150 16,000 OH_WoodLine FldLt 78 692 53,976
0176-3-170 150 16,000 OH_WoodLine StLtSC 1 692 692
0176-3-210 150 16,000 OH_WoodLitg StLt 1 692 692
0176-3-220 150 16,000 OH_WoodLitg FldLt 1 692 692
0176-3-624 150 16,000 UG_Aluminum FldLt AddlFixt 1 692 692
0242-3-612 200 9,500 UG_Aluminum StLt TwinFixts 2 952 1,904
0324-3-110 250 25,000 OH_WoodLine StLt 901 1,274 1,147,874
0324-3-120 250 25,000 OH_WoodLine FldLt 886 1,274 1,128,764
0324-3-170 250 25,000 OH_WoodLine StLtSC 168 1,274 214,032
0324-3-211 250 25,000 OH_WoodLitg StLt CustPaidPole 10 1,274 12,740
0324-3-220 250 25,000 OH_WoodLitg FldLt 7 1,274 8,918
0324-3-221 250 25,000 OH_WoodLitg FldLt CustPaidPole 3 1,274 3,822
0324-3-310 250 25,000 OH_Aluminum StLt 2 1,274 2,548
0324-3-320 250 25,000 OH_Aluminum FldLt 1 1,274 1,274
0324-3-324 250 25,000 OH_Aluminum FldLt AddlFixt 3 1,274 3,822
0324-3-370 250 25,000 OH_Aluminum StLtSC 22 1,274 28,028
0324-3-610 250 25,000 UG_Aluminum StLt 354 1,274 450,996
0324-3-614 250 25,000 UG_Aluminum StLt AddlFixt 4 1,274 5,096
0324-3-620 250 25,000 UG_Aluminum FldLt 18 1,274 22,932
0324-3-624 250 25,000 UG_Aluminum FldLt AddlFixt 1 1,274 1,274
0500-3-110 400 50,000 OH_WoodLine StLt 102 1,966 200,532
0500-3-120 400 50,000 OH_WoodLine FldLt 1,884 1,966 3,703,944
0500-3-210 400 50,000 OH_WoodLitg StLt 1 1,966 1,966
0500-3-220 400 50,000 OH_WoodLitg FldLt 72 1,966 141,552
0500-3-221 400 50,000 OH_WoodLitg FldLt CustPaidPole 32 1,966 62,912
0500-3-310 400 50,000 OH_Aluminum StLt 1 1,966 1,966
0500-3-320 400 50,000 OH_Aluminum FldLt 5 1,966 9,830
0500-3-610 400 50,000 UG_Aluminum StLt 9 1,966 17,694
0500-3-620 400 50,000 UG_Aluminum FldLt 10 1,966 19,660
0500-3-621 400 50,000 UG_Aluminum FldLt CustPaidPole 2 1,966 3,932
0500-3-624 400 50,000 UG_Aluminum FldLt AddlFixt 9 1,966 17,694
0648-3-612 500 25,000 UG_Aluminum StLt TwinFixts 16 2,548 40,768
------ ----------
Total Sodium Vapor 18,136 12,189,086
- -----------------------------------------------------------------------------------------------------------------------------------
Total Streetlighting 21,515 14,647,035
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. No. ______
Exhibit JJB-4
Exhibit JJB-4
Newport - Billing Determinants
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 1 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate R-1 v. Narragansett's Rate A-16
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 325,773 325,773
Energy (kWh) 167,201,036 167,201,036
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 2 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate R-2 v. Narragansett's Rate A-60
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 4,208 4,208
Energy (kWh) 1,764,819 1,764,819
First 300 kWh 1,055,362 1,055,362
Excess 300 kWh 709,457 709,457
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 3 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate R-4 v. Narragansett's Rate A-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 2,504 2,504
Energy (kWh) 7,100,991 7,100,991
Peak Energy (kWh) 1,248,828 0
Off-Peak Energy (KWh) 5,852,163 0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 4 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate G-1 v. Narragansett's Rate C-06
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 48,861 47,123
Unmetered 1,738
Energy (kWh) 42,449,011 42,449,011
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 5 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate G-2: Total
Newport's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 7,645
Demand (kW) 321,720
Energy (kWh) 105,080,586
Newport's Rate G-2 v. Narragansett's Rate C-06
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 1,272 1,272
Demand (kW) 29,206
Energy (kWh) 6,707,011 6,707,011
Newport's Rate G-2 v. Narragansett's Rate G-02
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 6,226 6,226
Demand (kW) 255,636 213,521
Energy (kWh) 85,631,955 85,631,955
Newport's Rate G-2 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 147 147
Demand (kW) 36,878 43,326
Energy (kWh) 12,741,620 12,741,620
Note:
1. For Newport's Rate G-2 customers apportioned to Narragansett's C-06, the revenue for each
customer was calculation under both Narragansett's Rate C-06 and G-02. The Newport Rate G-2
customers were then transferred to the Narragansett rate producing the lower revenue.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 6 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate G-5: Total
Newport's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 241
Demand (kW) 40,361
Energy (kWh) 15,075,589
Newport's Rate G-5 v. Narragansett's Rate G-02
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 158 158
Demand (kW) 12,834 14,847
Energy (kWh) 4,061,340 4,061,340
Newport's Rate G-5 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 83 83
Demand (kW) 27,527 29,984
Energy (kWh) 11,014,249 11,014,249
Note:
1. Newport's Rate G-5 determinants were apportioned among Narragansett Rates G-02 and G-32 based on
the availability provisions of Narragansett's rates.
2. Narragansett,s billing demands are estimated based upon Newport's Rate G-5 load research data
using Narragansett TOU hours.
3. Billing demands used to determine whether a Newport Rate G-5 is to be transferred to
Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest
demand in the previous 11 months less 10 kW.
4. Billing demands used to determine whether a Newport Rate G-5 customer is to be transferred to
Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of
monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11
months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 7 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate T-2: Total
Newport's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 156
Demand (kW) 30,327
Energy (kWh) 14,361,960
Peak Energy (kWh) 2,681,420
Off-Peak Energy (kWh) 11,680,540
Newport's Rate T-2 v. Narragansett's Rate G-02
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 84 84
Demand (kW) 11,103 10,263
Energy (kWh) 4,675,660 4,675,660
Peak Energy (kWh) 862,640 0
Off-Peak Energy (kWh) 3,813,020 0
Newport's Rate T-2 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 72 72
Demand (kW) 19,224 20,900
Energy (kWh) 9,686,300 9,686,300
Peak Energy (kWh) 1,818,780 0
Off-Peak Energy (kWh) 7,867,520 0
Note:
1. Newport's Rate T-2 determinants were apportioned among Narragansett Rates G-02 and G-32 based on
the availability provisions of Narragansett's rates.
2. Narragansett's billing demands are estimated based upon Newport's Rate T-2 load research data
using Narragansett TOU hours.
3. Billing demands used to determine whether a Newport Rate T-2 is to be transferred to
Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest
demand in the previous 11 months less 10 kW.
4. Billing demands used to determine whether a Newport Rate T-2 customer is to be transferred to
Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of
monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11
months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 8 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate T-4 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 69 69
Demand (kW) 41,467 57,333
Energy (kWh) 18,430,440 18,430,440
Peak Energy (kWh) 3,531,400 0
Off-Peak Energy (kWh) 14,899,040 0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 9 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate T-5 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 12 12
Demand (kW) 5,375 5,375
Energy (kWh) 2,964,000 2,964,000
Peak Energy (kWh) 531,000 0
Off-Peak Energy (kWh) 2,433,000 0
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 10 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate T-6: Total
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 24
Demand (kW) 50,282
Energy (kWh) 24,547,599
Peak Energy (kWh) 5,171,799
Off-Peak Energy (kWh) 19,375,800
Newport's Rate T-6 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 12 12
Demand (kW) 14,305 15,820
Energy (kWh) 6,958,000 6,958,000
Peak Energy (kWh) 1,417,000 0
Off-Peak Energy (kWh) 5,541,000 0
Newport's Rate T-6 v. Narragansett's Rate G-62
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 12 12
Demand (kW) 35,977 36,233
Energy (kWh) 17,589,599 17,589,599
Peak Energy (kWh) 3,754,799 0
Off-Peak Energy (kWh) 13,834,800 0
Note:
1. Newport's Rate T-6 determinants were apportioned among Narragansett Rates G-32 and G-62 based on
the availability provisions of Narragansett's rates.
2. Billing demands used to determine whether a Newport Rate T-2 customer is to be transferred to
Narragansett's Rate G-32 and G-62 are the highest of: (1) the customer's monthly peak hour demand,
(2) 50% of monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the
previous 11 months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 11 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate C-1 v. Narragansett's Rate N-01
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 12 12
Demand (kW) 212,968 212,968
Energy (kWh) 114,919,292 114,919,292
Peak Energy (kWh) 23,608,292 23,608,292
Off-Peak Energy (kWh) 91,311,000 91,311,000
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 12 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate H-1: Total
Newport's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 227
Demand (kW) 0
Energy (kWh) 4,908,488
Newport's Rate H-1 v. Narragansett's Rate C-06
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 36 36
Energy (kWh) 146,940 146,940
Newport's Rate H-1 v. Narragansett's Rate G-02
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 179 179
Demand (kW) 0 7,866
Energy (kWh) 3,203,948 3,203,948
Newport's Rate H-1 v. Narragansett's Rate G-32
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 12 12
Demand (kW) 0 5,202
Energy (kWh) 1,557,600 1,557,600
Note:
1. Newport's Rate H-1 determinants were apportioned among Narragansett Rates C-06, G-02 and G-32
based on the availability provisions of Narragansett's rates.
2. Narragansett's billing demands are estimated based upon Newport's Rate H-1 load research data
using Narragansett TOU hours.
3. Billing demands used to determine whether a Newport Rate H-1 is to be transferred to
Narragansett's Rate G-02 are the higher of each customer's actual demand or 75% of the highest
demand in the previous 11 months less 10 kW.
4. Billing demands used to determine whether a Newport Rate H-1 customer is to be transferred to
Narragansett's Rate G-32 are the highest of: (1) the customer's monthly peak hour demand, (2) 50% of
monthly off-peak hours demand, (3) 75% of the highest monthly peak hours demand in the previous 11
months, or (4) 10 kW.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 13 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate H-2: Total
Newport's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 3,865
Demand (kW) 0
Energy (kWh) 5,723,950
Newport's Rate H-2 v. Narragansett's Rate C-06
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 3,752 3,752
Energy (kWh) 4,457,199 4,457,199
Newport's Rate H-2 v. Narragansett's Rate G-02
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 113 113
Demand (kW) 0 5,208
Energy (kWh) 1,266,751 1,266,751
Note:
1. Newport's Rate H-2 is a supplementary rate. Each customer's Rate H-2 usage was combined with the
customer's principal rate usage. Based on the combined usage, revenue for each customer was
colculated under both Narragansett's Rates C-06 and G-02. The Newport Rate H-2 customers were then
transferred to the Narragansett rate producing the lower revenue.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 14 of 15
Narragansett Electric Company
Newport Electric Corporation
Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate W-1: Total
Newport's
Billing Billing
Parameter Determinant
- ----------------------------------------------------------------------------
<S> <C>
Bills 64,408
Energy (kWh) 13,383,268
Newport's Rate W-1 v. Narragansett's Rate A-16
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
<S> <C> <C>
Bills 63,065 63,065
Energy (kWh) 13,062,846 13,062,846
Newport's Rate W-1 v. Narragansett's Rate C-06
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 1,303 1,303
Energy (kWh) 313,931 313,931
Newport's Rate W-1 v. Narragansett's Rate G-02
Newport's Narragansett's
Billing Billing Billing
Parameter Determinant Determinant
- -------------------------------------------------------------------------------------------------
Bills 40 40
Energy (kWh) 6,491 6,491
Note:
1. Newport's Rate W-1 is a supplementary rate. Each customer's Rate W-1 usage was combined with the
customer's principal rate usage. Based on the combined usage, revenue for each customer was
colculated under both Narragansett's Rates C-06 and G-02. The Newport Rate W-1 customers were then
transferred to the Narragansett rate producing the lower revenue.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
C:\JJB\[jjb4.wk4]O Narragansett Electric
08/01/99 BVE/Newport Electric
R.I.P.U.C. Docket No. _______
Exhibit JJB - 4
Page 15 of 15
Narragansett Electric Company
Newport Electric Corporation
Original Apportionment of Company Billing Determinants
Year Ending December 31, 1998, Billing Determinants
Newport's Rate S-1 Streetlighting Rate
Newport's Newport's
Newport's Lamp Newport's Service & Special Fixture Annual kWh Total Annual
Lighting Code Wattage Lumen Size Pole Type Fixture Type Pricing Option Count per Light Energy
- ----------------------------------------------------------------------------------------------------------------------------------
Incandescent
<S> <C> <C> <C> <C> <C> <C>
0092-1-110 92 1,000 OH_WoodLine StLt 383 362 138,646
0189-1-110 189 2,500 OH_WoodLine StLt 64 743 47,552
------ ---------
Total Incandescent 447 186,198
- ----------------------------------------------------------------------------------------------------------------------------------
Metal Halide
0300-4-120 250 20,000 OH_WoodLine FldLt 5 1,180 5,900
0466-4-120 400 40,000 OH_WoodLine FldLt 6 1,832 10,992
1080-4-120 1,000 115,000 OH_WoodLine FldLt 37 4,247 157,139
------ ---------
Total Metal Halide 48 174,031
- ----------------------------------------------------------------------------------------------------------------------------------
Mercury Vapor
0130-2-110 100 4,200 OH_WoodLine StLt 2,525 511 1,290,275
0130-2-210 100 4,200 OH_WoodLitg StLt 74 511 37,814
0130-2-441 100 4,200 URD_Fiberglass T&C CustPaidPole 14 511 7,154
0130-2-610 100 4,200 UG_Aluminum StLt 2 511 1,022
0130-2-710 100 4,200 UG_WoodLitg StLt 55 511 28,105
0130-2-711 100 4,200 UG_WoodLitg StLt CustPaidPole 27 511 13,797
0209-2-110 175 8,600 OH_WoodLine StLt 47 822 38,634
0209-2-710 175 8,600 UG_WoodLitg StLt 13 822 10,686
0300-2-110 250 12,100 OH_WoodLine StLt 24 1,180 28,320
0300-2-710 250 12,100 UG_WoodLitg StLt 19 1,180 22,420
0474-2-110 400 22,500 OH_WoodLine StLt 377 1,864 702,728
0474-2-120 400 22,500 OH_WoodLine FldLt 111 1,864 206,904
0474-2-210 400 22,500 OH_WoodLitg StLt 34 1,864 63,376
0474-2-220 400 22,500 OH_WoodLitg FldLt 32 1,864 59,648
0474-2-610 400 22,500 UG_Aluminum StLt 16 1,864 29,824
0474-2-621 400 22,500 UG_Aluminum FldLt CustPaidPole 2 1,864 3,728
0474-2-624 400 22,500 UG_Aluminum FldLt AddlFixt 4 1,864 7,456
0474-2-710 400 22,500 UG_WoodLitg StLt 231 1,864 430,584
0474-2-711 400 22,500 UG_WoodLitg StLt CustPaidPole 1 1,864 1,864
0600-2-712 250 12,100 UG_WoodLitg StLt TwinFixts 6 2,359 14,154
0948-2-612 800 22,500 UG_Aluminum StLt TwinFixts 3 3,728 11,184
0948-2-712 800 22,500 UG_WoodLitg StLt TwinFixts 26 3,728 96,928
1135-2-120 1,000 63,000 OH_WoodLine FldLt 37 4,463 165,131
1135-2-220 1,000 63,000 OH_WoodLitg FldLt 9 4,463 40,167
1135-2-710 1,000 63,000 UG_WoodLitg StLt 7 4,463 31,241
------ ---------
Total Mercury Vapor 3,696 3,343,144
- ----------------------------------------------------------------------------------------------------------------------------------
Sodium Vapor
0085-3-110 70 5,800 OH_WoodLine StLt 642 334 214,428
0085-3-120 70 5,800 OH_WoodLine FldLt 41 334 13,694
0085-3-210 70 5,800 OH_WoodLitg StLt 32 334 10,688
0085-3-211 70 5,800 OH_WoodLitg StLt CustPaidPole 9 334 3,006
0085-3-441 70 5,800 URD_Fiberglass T&C CustPaidPole 247 334 82,498
0085-3-610 70 5,800 UG_Aluminum StLt 14 334 4,676
0085-3-611 70 5,800 UG_Aluminum StLt CustPaidPole 8 334 2,672
0085-3-711 70 5,800 UG_WoodLitg StLt CustPaidPole 78 334 26,052
0121-3-110 100 9,500 OH_WoodLine StLt 7 476 3,332
0324-3-110 250 25,000 OH_WoodLine StLt 188 1,274 239,512
0324-3-120 250 25,000 OH_WoodLine FldLt 269 1,274 342,706
0324-3-210 250 25,000 OH_WoodLitg StLt 6 1,274 7,644
0324-3-211 250 25,000 OH_WoodLitg StLt CustPaidPole 1 1,274 1,274
0324-3-220 250 25,000 OH_WoodLitg FldLt 27 1,274 34,398
0324-3-221 250 25,000 OH_WoodLitg FldLt CustPaidPole 6 1,274 7,644
0324-3-611 250 25,000 UG_Aluminum StLt CustPaidPole 12 1,274 15,288
0324-3-621 250 25,000 UG_Aluminum FldLt CustPaidPole 1 1,274 1,274
0324-3-711 250 25,000 UG_WoodLitg StLt CustPaidPole 24 1,274 30,576
0324-3-720 250 25,000 UG_WoodLitg FldLt 1 1,274 1,274
0500-3-110 400 50,000 OH_WoodLine StLt 12 1,966 23,592
0500-3-120 400 50,000 OH_WoodLine FldLt 349 1,966 686,134
0500-3-210 400 50,000 OH_WoodLitg StLt 2 1,966 3,932
0500-3-220 400 50,000 OH_WoodLitg FldLt 50 1,966 98,300
0500-3-221 400 50,000 OH_WoodLitg FldLt CustPaidPole 4 1,966 7,864
0500-3-624 400 50,000 UG_Aluminum FldLt AddlFixt 1 1,966 1,966
1000-3-613 800 50,000 UG_Aluminum StLt CustPaidTwinFixt 6 3,932 23,592
1000-3-713 800 50,000 UG_WoodLitg StLt CustPaidTwinFixt 6 3,932 23,592
------ ---------
Total Sodium Vapor 2,043 1,911,608
- ----------------------------------------------------------------------------------------------------------------------------------
Total Streetlighting 6,234 5,614,981
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
The Narragansett Electric Company,
Blackstone Valley Electric Company,
and Newport Electric Corporation
Rate Plan Filing in Support of Merger
Volume 3
Testimony and Exhibits of:
David J. Hoffman & Richard J. Levin
May, 1999
Submitted to:
Rhode Island Public Utilities Commission
RIPUC Docket _____
Submitted by:
Nees Logo
Eastern Utilities Associates Logo
<PAGE>
STATE OF RHODE ISLAND
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ------------------------------
New England Electric System )
) R.I.P.U.C. Docket __________
Eastern Utilities Associates )
- ------------------------------
DIRECT TESTIMONY
OF
DAVID J. HOFFMAN AND
RICHARD J. LEVIN
<PAGE>
STATE OF RHODE ISLAND
RHODE ISLAND PUBLIC UTILITIES COMMISSION
- ------------------------------
New England Electric System )
) R.I.P.U.C. Docket __________
Eastern Utilities Associates )
- ------------------------------
DIRECT TESTIMONY
OF
DAVID J. HOFFMAN AND
RICHARD J. LEVIN
Table of Contents
I. Introduction and Qualifications..................................... 1
II. Summary of Testimony................................................ 6
III. Detailed Estimate of Cost Savings................................... 12
A. Summary of Personnel and Non-Personnel Savings............. 12
B. Personnel Savings.......................................... 13
C. Information Systems Savings (Non-Personnel)................ 17
D. Supply Chain Savings (Non-Personnel)....................... 18
E. Facilities Savings (Non-Personnel)......................... 20
F. Administrative and General Savings (Non-Personnel)......... 20
G. Comparison with Other Transactions......................... 24
IV. Detailed Estimate of Cost to Achieve................................ 26
<PAGE>
<TABLE>
<CAPTION>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 1 of 29
<S> <C>
1 I. Introduction and Qualifications
2 Q. Please state your names, current positions and business addresses.
3 A. My name is David J. Hoffman. I am a Vice President with Mercer Management
4 Consulting, Lexington, Massachusetts.
5
6 My name is Richard J. Levin. I am a management consultant with Mercer
7 Management Consulting, Lexington, Massachusetts.
8
9 Q. Mr. Hoffman, please summarize your educational and professional background.
10 A. I received a B.S. degree in finance in 1976 and a MBA degree (with honors) in
11 management information systems in 1980 from Boston University.
12
13 My professional experience includes over 15 years as a consultant to electric and gas
14 utilities. I joined Mercer in 1982 and prior to that, worked for United Information Systems
15 (from 1980 to 1982).
16
17 During my consulting career, I have led a broad range of assignments, encompassing:
18 o Merger and acquisition analysis
19 o Organizational and performance improvement
20 o Strategic and business planning
21 o Information systems strategy
22
Hoffman/Levin
- 1 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 2 of 29
1 Q. Mr. Levin, please summarize your educational and professional background.
2 A. I received a B.A. in economics from Washington University in 1972 and an M.A. in
3 economics from The Ohio State University in 1974. In 1977, I received a J.D. degree
4 from Ohio State and was admitted to the Ohio Bar.
5
6 My professional experience includes over nineteen years as a management consultant
7 specializing in the management and regulation of utilities. I joined Mercer in May 1983
8 and, prior to that, worked as an independent consultant (June 1982 through April 1983) and
9 for Booz, Allen & Hamilton, Inc. (April 1979 through May 1982).
10
11 During my consulting career, I have served as a project manager or lead consultant on a
12 broad range of assignments for utilities and regulatory commissions. The subject matter of
13 these assignments has encompassed:
14 o Merger and acquisition analysis
15 o Organizational and performance improvement
16 o Strategic and business planning
17 o Management audits
18 o Rate of return and cost of capital studies
19 o Financial forecasting and planning
20 o Economic and financial feasibility evaluations
21
22 Prior to my consulting career, I was a lecturer at Ohio State in economic theory and
23 corporate finance. I held that position from January 1978 through March 1979. From June
24 1975 to September 1978, I was employed by the Public Utilities Commission of Ohio. From
Hoffman/Levin
- 2 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 3 of 29
1 1975 to 1977, I served as a financial economist with the Commission's staff and testified on
2 rate of return and financial issues in electric, gas, telephone, and water rate cases.
3 After graduation from law school in 1977, I became a Hearing Examiner for the Commission.
4 My primary responsibilities in that position were presiding over rate and other proceedings,
5 drafting proposed rules, and preparing written orders for the Commission's consideration.
6
7 I have testified before the Massachusetts Department of Public Utilities, the Maine
8 Public Utilities Commission, and the Ohio Public Utilities Commission on the cost
9 of capital. I have also testified before the Maine PUC, New Mexico Public Service
10 Commission, the Iowa State Commerce Commission, the Pennsylvania Public Utility
11 Commission, and the Massachusetts Appellate Tax Board on other regulatory issues.
12
13 Q. Mr. Hoffman and Mr. Levin, please summarize your relevant experience.
14 A. Over the past several years, we have both been actively involved in the merger and
15 acquisitions (M&A) area. This work has included 1) screening and evaluating
16 potential merger candidates, 2) estimating cost savings for approximately 15
17 potential mergers, and 3) assisting utilities in post-merger integration planning.
18
19 We have also been involved in organizational and/or performance improvement work at
20 more than 30 utilities. This work has been done for utility clients and on behalf of
21 regulatory commissions (as part of management audits). This work has included
Hoffman/Levin
- 3 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 4 of 29
1 organizational design, determining appropriate staffing levels, process redesign, and
2 identifying opportunities to reduce costs. The work has encompassed all aspects of the
3 utility business (generation, transmission, distribution, customer and marketing-related, and
4 A&G functions). With respect specifically to A&G activities, we have both been involved
5 in assignments dealing with the following functions: information services, accounting,
6 human resources, finance and treasury, supply chain management, legal, rates and regulatory
7 affairs, and corporate communication and external affairs.
8
9 Important elements of this work have been benchmarking a particular utility's performance
10 against other companies and understanding the drivers of costs on the overall business and
11 on specific functions. We are also two of the principal authors of Mercer's utility staffing
12 survey. This survey has become an industry standard for evaluating staffing levels; its
13 definition of utility functions and sub-functions is also widely used in merger analysis and
14 testimony.
15
16 Q. Please describe Mercer's experience in working with NEES.
17 A. Mercer Management Consulting has worked extensively with NEES since 1992. Our
18 work with the Company has included the following types of assignments:
19 o Organizational transformation
20 o Process improvement
21 o Business strategy
Hoffman/Levin
- 4 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 5 of 29
1 o Mergers and acquisitions analysis
2
3 These assignments have encompassed all operating, customer-related, and A&G
4 functions in the operating companies and the service company.
5
6 Mercer's extensive knowledge of NEES management and operations was extremely
7 helpful in discussing integration strategies, identifying cost savings opportunities and
8 ultimately, in developing sound estimates of savings and cost to achieve for the
9 proposed NEES-EUA merger.
10
11 Q. Please describe some of these assignments.
12 A. In 1992 and 1993, Mercer assisted NEES in a major organizational transformation,
13 which included the creation of business units, the alignment and clarification of roles
14 and responsibilities, and a significant streamlining of organizational structure and
15 staffing. In 1993 and 1994, we assisted NEES in developing a customer call center
16 strategy which led to the successful consolidation of Massachusetts Electric's six
17 individual call centers into a single center (the Northboro Customer Service Center).
18 During the 1996-1998 period, Mercer helped NEES in the transition from a fully-
19 integrated utility into a "wires" utility; this particular effort included identifying
20 corporate support services required after the divestiture of generation assets.
Hoffman/Levin
- 5 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 6 of 29
1
2 Q. In addition to this testimony, has Mercer been retained to assist in other aspects
3 of the proposed NEES-EUA merger?
4 A. Yes. Mercer has been retained to assist in the post-merger integration process.
5
6 II. Summary of Testimony
7 Q. What is the purpose of your testimony?
8 A. We have been asked to describe the analysis conducted to estimate the potential cost
9 savings associated with a merger of the New England Electric System ("NEES") and
10 Eastern Utilities Associates ("EUA"). Mercer Management Consulting (Mercer)
11 assisted NEES and EUA (also referred to as the "Companies") in 1) identifying areas
12 with potential cost saving or cost to achieve, 2) collecting relevant data, 3)
13 developing related operating and financial assumptions, and 4) estimating potential
14 savings and costs.
15
16 This testimony presents the results of the analysis, including:
17 o A summary of results (this section)
18 o A detailed estimate of savings (Section III)
19 o A detailed estimate of cost to achieve (Section IV)
20
Hoffman/Levin
- 6 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 7 of 29
1 Exhibit DJH-1 provides a summary of potential merger cost savings for the first 10
2 years (2000-2009) and the cost to achieve. Exhibit DJH-2 contains the non-
3 confidential working papers that support the estimates. Exhibit DJH-3 contains our
4 confidential working papers.
5
6 Q. Please summarize your testimony.
7 A. The planned merger will result in savings that would not otherwise be achieved by
8 the stand-alone operations of NEES (through its Massachusetts Electric, Narragansett
9 Electric, Granite State Electric, Nantucket Electric, and New England Power Service
10 Company subsidiaries) and EUA (through its Eastern Edison, Blackstone Valley
11 Electric, Newport Electric and EUA Service Corporation subsidiaries). Based on
12 information provided by NEES and EUA and the analysis conducted by NEES
13 management and Mercer, merger-related savings were estimated at approximately
14 $31.1 million in 2005, as shown below:
Estimated Savings in 2005
Savings Component ($ Millions)
Personnel Savings $21.5
Information Systems Savings 0.1
Supply Chain Savings 0.6
Facilities Savings 4.7
Administrative and General Savings 4.2
---
Total Savings 31.1
Hoffman/Levin
- 7 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 8 of 29
1 The figures above include merger-related savings related only to the regulated
2 "wires" and A&G-related operations of NEES and EUA. No revenue enhancements
3 were identified for the regulated business.
4
5 Only cost savings that would result from the merger were included in estimated
6 savings. These types of savings are derived from the elimination of duplication, cost
7 avoidance, adoption of different management practices and policies, and the
8 improved utilization of assets and employees. Savings which could be achieved
9 without a merger (e.g., position reductions resulting from a process improvement in
10 one company) were not included in the estimated savings.
11
12 Q. When will the savings commence?
13 A. Savings will begin in 2000 and continue permanently. Exhibit DJH-l presents savings for
14 only the first 10 years (2000-2009). The cost to achieve the merger savings will occur
15 primarily in the 1999-2002 period.
16
17 Q. Could the cost savings discussed above and in detail in Section III be achieved
18 without a merger?
19 A. No. The savings are based upon the elimination of redundancies (in personnel,
20 facilities and other areas) and the gaining of economies brought about by a merger.
Hoffman/Levin
- 8 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 9 of 29
1 In addition, the savings would not result without incurring the cost to achieve
2 discussed above and in detail in Section IV.
3
4 Q. Please describe the process utilized to estimate merger cost savings and cost to
5 achieve.
6 A. Mercer worked with senior and middle managers at both NEES and EUA to gather
7 the information required to estimate savings and costs. We also met with EUA
8 managers to develop a fuller understanding of the company's business practices,
9 operations, and costs. As discussed earlier, we already had an extensive
10 understanding of NEES business practices, operations, and costs.
11
12 We also worked with NEES management to determine how the merged companies
13 would operate in the future, e.g., the expected level of integration in the A&G,
14 customer-related, and T&D functions.
15
16 Based on information collected and assumptions about now the merged companies
17 would operate, estimates of merger savings and costs were developed, discussed, and
18 refined. The process used to develop the estimated savings and cost to achieve was
19 reasonable, and captured the significant sources of savings available and costs that
20 would be incurred in a merger.
Hoffman/Levin
- 9 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 10 of 29
1 Q. What assumptions were made in the analysis?
2 A. The following assumptions were made in estimating cost savings:
3 o The combined companies will begin integrated operations on January 1, 2000
4 o The "wires" business will be run with one principal operating company in each
5 state (Massachusetts, Rhode Island, and New Hampshire) and one service
6 company
7 o A high-degree of integration will occur, e.g.:
8 - Financial, accounting, human resources, legal, external affairs, and corporate
9 planning functions will be fully integrated
10 - IS data centers will be consolidated
11 - Call centers will be consolidated
12 - Central T&D planning, engineering, and support will be fully integrated, as
13 will transmission field forces
14 o Annual savings will escalate at a rate of 2.2 percent
15
16 Q. How were capital-related savings calculated?
17 A. Capital-related savings were calculated using a revenue requirement methodology.
18 Under this methodology, for example, a capital deferral or avoidance of $1 million in
19 2000 would not result in a merger savings of $1 million in that year; rather annual
20 savings relating to the fixed charges (cost of capital, depreciation, insurance, and
21 taxes on the $1 million deferral or avoided) are calculated. The revenue
22 requirements methodology reflects the timing of merger savings and how capital or
23 construction-related costs are treated for ratemaking purposes.
24
Hoffman/Levin
- 10 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 11 of 29
1 Fixed charge rates for NEES and EUA were estimated and then blended, based on the
2 relative size of the companies. A levelized fixed charge rate of 13.5 percent was
3 used for capital items other than IS-related. A levelized fixed charge rate of 28.6
4 percent was used for IS-related items; the higher rate is due to a more rapid (five-year)
5 depreciation period.
6
7 Q. Is the level of estimated cost savings achievable?
8 A. We believe that the level of savings identified in our study has a high likelihood of
9 achievement. Beyond that level, we are aware that Mr. Jesanis is testifying that he
10 expects the savings to be achieved from the acquisition of EUA will be $35 million per
11 year or more in 2005. We believe that this higher level of savings is likely to be
12 achieved for the following reasons:
13 o NEES management approach: During our previous assignments with NEES,
14 the Company has been very creative and aggressive in identifying opportunities
15 to reduce costs; the early creation of a transition team to facilitate the merger
16 illustrates NEES's aggressive approach to opportunities.
17 o NEES "track record": NEES has successfully addressed many of the same
18 issues that arise in a merger, e.g., designing a streamlined organization,
19 integrating multiple call centers, and optimizing field forces and work out
20 locations.
21 o National Grid-related synergies: Additional synergies are expected to result
22 from the National Grid-NEES merger, e.g., taking advantage of National Grid test
23 practices and financing capabilities.
Hoffman/Levin
- 11 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 12 of 29
1 o Additional sources of savings: Opportunities may arise which have not been
2 captured in our estimates. These include 1) outsourcing functions (given the
3 greater volume of work for the merged companies); 2) taking advantage of new
4 technologies (given the merged companies greater scale); and 3) achieving
5 longer-term IS savings by avoiding duplicative efforts.
6
7 As such, we agree with Mr. Jesanis that actual savings are likely to exceed our
8 estimated savings.
9
10 III. Detailed Estimate of Cost Savings
11
12 A. Summary of Personnel and Non-Personnel Savings
13 Q. You have estimated merger cost savings of $31.1 million in 2005. Would you
14 define the principal components of cost savings and the estimated savings in
15 each component?
16 A. As illustrated in the table on page 7 of this testimony and in Exhibit DJH-2, savings
17 have been classified into five components:
18 o Personnel savings: related to position reductions in A&G, customer, transmission and
19 distribution, and other functions
20 o Information systems savings (non-personnel): related to integration of applications;
21 mainframe, network, midrange/server, and PC/workstation operations; projects; and
22 telecommunications
23 o Supply chain savings (non-personnel): related to reductions in inventory; lower costs
24 for materials, equipment, and contractor services; and reductions in the number of
25 vehicles
Hoffman/Levin
- 12 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 13 of 29
1 o Facilities savings (non-personnel): related to the closing of facilities, including
2 office space
3 o Administrative and general savings (non-personnel): related to A&G
4 overheads, advertising, association dues, benefits administration, corporate
5 governance (i.e., shareholder services and board fees), financing costs and fees,
6 insurance, professional services, and regulatory expenses
7
8 The level of estimated savings (in 2005 dollars unless otherwise indicated) and the
9 bases for the estimates are discussed below.
10
11 B. Personnel Savings
12 Q. Please discuss the analysis supporting your personnel savings estimate of $21.5
13 million in 2005.
14 A. Personnel savings were estimated using the following process:
15 o First, staffing levels for NEES and EUA were estimated as of January 1, 2000.
16 Both companies provided detailed organizational and functional breakdowns that
17 assigned each employee to one of the following functions:
Hoffman/Levin
- 13 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 14 of 29
1 A&G Functions Customer Functions
o Purchasing and Material Management (excluding o Retail Marketing and Sales
Storeroom Personnel)
o Customer Service
o Human Resources
Electric Transmission and Distribution Functions
o Finance, Accounting, and Planning
o Electric Distribution
o Information Services and Telecommunications
o Electric System Technical Support
o External Relations
o Electric Transmission
o Legal
o Transportation, Real Estate, and Facilities
o Administrative and Support Services (excluding Maintenance
Transportation, Real Estate and Facilities
Maintenance) o Storeroom Personnel
o Executive Management Other
o Other Activities
2
3 Within these functions, employees were also assigned to specific sub-functions.
4 For example, within Customer Service, an employee could be assigned to meter
5 reading, customer inquiry, credit and collections, or another sub-function. The
6 complete list of functions and sub-functions used in this analysis is included in
7 the Exhibit DJH-3 working papers. The use of a common format (Mercer's
8 staffing survey function and sub-function classification) allowed for an
9 "apples-to-apples" staffing analysis.
10 o Second, the number of positions that could be eliminated as a result of the merger
11 was estimated. The magnitude of the reduction in each sub-function was based
12 upon identified duplication or redundant activities; the expected degree of
13 integration; potential changes in policies or practices; and any incremental
14 workloads that would result in that area. The number of position reductions in
15 any one sub-function were not allowed to exceed the smaller of the number of
16 positions of either NEES or EUA on a stand-alone basis. For example, if NEES
17 had 15 positions in a sub-function and EUA had 5 positions, the reduction could
18 not exceed 5 positions.
Hoffman/Levin
- 14 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 15 of 29
1 o Third, an average compensation was calculated for each sub-function and then
2 multiplied by the number of positions reduced in that sub-function. The
3 compensation figures used were the average of NEES and EUA compensation
4 levels. Compensation figures included base compensation (wages or salaries)
5 and benefits. Benefits included such items as pension plans, medical insurance,
6 life insurance, savings (401K) plans, bonuses and incentives, and payroll taxes.
7 The average total compensation (salary and benefits) for positions reduced was
8 $84,900 (in 2000 dollars).
9
10 Q. Please describe the results of the personnel analysis.
11 A. NEES was estimated to have 3,240 positions in utility operations and EUA was
12 estimated to have 869 positions as of January 1, 2000. Total position reductions
13 were estimated at 234, or approximately 6 percent of the 4,109 combined positions.
14 These reductions consist of 88 A&G, 62 customer, 78 T&D, and 6 other function
15 positions, as shown below.
Position Reductions
-------------------------------------------------------
A&G Customer T&D Other Total
NEES Positions 461 722 2,057 0 3,240
EUA Positions 173 201 488 7 869
--- --- --- - ---
Combined Positions 634 923 2,545 7 4,109
Estimated Reductions (88) (62) (78) (6) (234)
Reduction as a % of 14% 7% 3% 86% 6%
Combined Positions
Reduction as a % of 51% 31% 16% 86% 27%
EUA Positions
16
17 The 234 position reductions also equals 27 percent of EUA's 869 positions. At this
18 point, no decisions have been made as to which reductions will come from current
19 NEES positions or EUA positions.
Hoffman/Levin
- 15 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 16 of 29
1
2 As shown above, the percentage reductions in the A&G functions are significantly
3 higher than the percentage reductions in the customer and T&D functions. The
4 relative difference reflects the fact that "headquarter" or "office" type functions offer
5 greater opportunities for savings than do "field" functions, such as line maintenance
6 and construction.
7
8 Q. What was the assumed timing of the estimated reduction in positions?
9 A. In the A&G (except for IS), customer, and T&D functions, 75 percent of reductions
10 were assumed to occur in 2000 with the remaining 25 percent occurring in 2001. In
11 the IS area, reductions were assumed to be 0 percent in 2000, 50 percent in 2001, and
12 the remaining 50 percent in 2002. The slower timing of reductions in IS reflects the
13 complicated work required to integrate the two companies' systems.
14
15 Q. How were capital-related personnel savings calculated?
16 A. The percent of payroll savings allocated to capital was 0 percent for the A&G and
17 customer functions and 35 percent for the T&D functions. These rates were based on
18 payroll allocation figures provided by the companies, weighted by their relative sizes.
19 As discussed earlier, capital-related savings were translated into revenue
20 requirements, based on estimated fixed charge rates.
21
Hoffman/Levin
- 16 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 17 of 29
1 C. Information Systems Savings (Non-Personnel)
2 Q. Please describe the information systems functions at NEES and EUA.
3 A. NEES information systems operate on an MM mainframe computer, an IBM
4 midrange computer, approximately 60 servers, and approximately 2,500 PCs.
5 Corporate, financial and administrative systems utilize Walker software; HR/payroll
6 will utilize PeopleSoft; and the customer information system was developed
7 in-house. The company also has numerous operational systems running on the
8 midrange and mainframe computers. The NEES data center is located in the
9 Westborough headquarters.
10
11 EUA information systems operate on an Amdahl mainframe computer,
12 approximately 20 servers, and approximately 600 PCs. EUA operates various
13 financial packages; a CYBORG HR/payroll system; a customer information system
14 developed in-house; and numerous operational systems. The EUA data center is
15 located in the West Bridgewater headquarters.
16
17 Q. Please discuss estimated cost savings in the IS area?
18 A. Merger savings were estimated based on two major assumptions: first, that data
19 centers will be consolidated; second, that the combined companies will migrate to
20 NEES applications including Walker, PeopleSoft, and the NEES customer
21 information system.
Hoffman/Levin
- 17 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 18 of 29
1
2 Most of the savings come from a reduction in personnel, which was discussed earlier.
3 Non-personnel savings relating to the consolidation of data centers are largely offset
4 by the cost of adding computing capacity for combined mainframe and midrange
5 computer operations. In 2005, non-personnel IS savings were estimated at
6 approximately $0.1 million.
7
8 D. Supply Chain Savings (Non-Personnel)
9 Q. What are the potential areas of cost savings in the supply chain area?
10 A. Cost savings in supply chain can potentially occur in the following areas:
11 o A reduction in inventory, based on the consolidation of the companies'
12 storerooms and a sharing of spare parts
13 o Lower prices paid for materials, equipment and contractor services, based on
14 greater purchasing leverage and the potential for more standardization and vendor
15 consolidation
16 o A reduction in the number of vehicles, based on a reduction in the number of
17 field and headquarter positions
18
19 Q. Please discuss the estimated level of savings in supply chain?
20 A. Supply chain-related savings in 2005 of $0.6 million were estimated.
21
Hoffman/Levin
- 18 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 19 of 29
1 Inventory savings were $0.1 million of the total. Savings were based on a reduction
2 in fixed charges associated with a 25 percent reduction in EUA's current inventory of
3 $3.6 million.
4
5 Procurement savings on materials and equipment were estimated at $0.3 million in
6 2005. These savings were based on an estimated 3 percent reduction in the cost of
7 EUA's annual purchases of approximately $9.4 million. Merger-related savings for
8 contractor services were minimal, since EUA does not have significant contractor
9 services costs (estimated at $2.4 million for vegetation control and $0.2 million for
10 other services in 1998). In addition, the ability to gain purchasing leverage on
11 contractor services is difficult.
12
13 Vehicle-related savings were estimated at $0.2 million in 2005. Vehicle savings will
14 occur as a result of the reductions in the number of positions. An elimination of 5
15 heavy duty vehicles (due to the reduction of 5 T&D crews) and 10 passenger vehicles
16 (due to the reduction of approximately 90 A&G personnel) were estimated. Savings
17 were based on annual operating and fixed costs of $20,000 per heavy duty vehicle
18 and $5,000 per passenger vehicle.
19
Hoffman/Levin
- 19 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 20 of 29
1 E. Facilities Savings (Non-Personnel)
2 Q. Does the merger of NEES and EUA create an opportunity to consolidate
3 facilities?
4 A. Yes. As a result of the NEES-EUA merger, only one headquarters building will be
5 required, since A&G functions will be fully integrated. Based on planned T&D
6 operations, the EUA service centers and work out locations will continue to operate
7 in order to meet customer needs. As a result, no other opportunities to reduce facility
8 costs were identified.
9 Q. What are the estimated facilities-related savings?
10 A. The consolidation of headquarters will provide an estimated savings of $4.7 million
11 in 2005. The savings reflect reductions in both operating expenses (e.g.,
12 maintenance and outside services) and capital-related costs.
13
14 F. Administrative and General Savings (Non-Personnel)
15 Q. What are the potential areas of non-personnel savings related to administrative
16 and general functions?
17 A. We identified the following nine potential areas of cost savings: A&G overheads;
18 advertising; association dues; benefits administration; corporate governance (i.e.,
19 shareholder services and board-related costs); financial fees; insurance; professional
20 services; and regulatory expenses.
21
Hoffman/Levin
- 20 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 21 of 29
1 Q. What level of non-personnel A&G savings were estimated in the merger
2 analysis?
3 A. Savings in 2005 of $4.2 million were estimated. Sources of significant savings
4 included the professional services and corporate governance areas. Savings estimates
5 for each area are discussed below.
6
7 Q. Please discuss estimated savings related to A&G overheads in 2005.
8 A. Estimated A&G overhead-related merger savings of $0.8 million were identified.
9 A&G overheads include expenses for office supplies, publications, personal
10 computers, and other miscellaneous expenses. These types of expenses are often
11 captured in FERC Account 921.
12
13 Using NEES and EUA FERC data and other reports, we estimated overheads at
14 $3,000 per employee (in 2000 dollars). This figure was multiplied by the number of
15 position reductions to estimate annual savings.
16
17 Q. Please discuss estimated savings related to advertising.
18 A. Estimated savings in the advertising area were $0.3 million in 2005. Savings will
19 result from an elimination of duplicative costs, e.g., some media purchases. For this
20 transaction, savings were estimated at 50 percent of EUA's annual, normalized
21 advertising expenses.
Hoffman/Levin
- 21 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 22 of 29
1
2 Q. Please discuss estimated savings related to association dues.
3 A. Association dues-related savings of $0.1 million in 2005 were identified. Savings
4 were based on lower expenditures for combined membership in the Edison Electric
5 Institute and the termination of membership in other associations.
6
7 Q. Please discuss estimated savings related to benefits administration.
8 A. Estimated merger savings in this area were $0.1 million in 2005. Although total
9 benefit costs for medical, dental, life and other insurance, pensions, and savings
10 plans are significant, the opportunity to reduce costs is very limited. For example,
11 NEES' HMO benefits are self-insured and do not provide an opportunity for savings.
12
13 Q. Please discuss estimated savings related to corporate governance.
14 A. Merger savings related to a reduction in corporate governance costs were estimated
15 at $0.9 million in 2005. Savings related to shareholder services result from the
16 elimination of duplicate activities and costs, such as preparation of the annual
17 shareholders' report and transfer agent fees. Additional savings result from the
18 elimination of director fees and expenses for one company.
19
20 Q. Please discuss estimated savings related to financing costs and fees.
Hoffman/Levin
- 22 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 23 of 29
1 A. Merger savings in this area were estimated at $0.3 million in 2005, based on a
2 reduction in line of credit fees for the combined company. The savings related to
3 lines of credit are based on a 100 percent elimination of EUA's stand-alone fees.
4
5 Q. Please discuss estimated savings related to insurance.
6 A. Merger-related insurance savings were estimated at $0.7 million in 2005. Savings
7 were based on expected reductions in property and liability coverage premiums (due
8 to reduction in cost per additional dollar of coverage); reductions in directors and
9 officers insurance premiums (due to the elimination of one board of directors); and
10 reductions in brokerage fees (due to the consolidation of insurance purchasing).
11
12 Q. Please discuss estimated savings related to professional services.
13 A. Merger-related savings for professional services were estimated at $1.0 million in
14 2005. Professional services savings result from the elimination of duplicative efforts
15 in areas such as external auditing, legal support, legislative services, and general
16 consulting. The savings were based on an approximate 40 percent reduction in
17 EUA's stand-alone annual professional services costs.
18
19 Q. Please discuss estimated savings related to regulatory expenses.
Hoffman/Levin
- 23 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 24 of 29
1 A. Merger-related savings for regulatory expenses were estimated at $0.1 million in
2 2005. Savings (non-personnel) in this area are relatively small, since annual
3 assessments (the largest component of costs) are not likely to be reduced when the
4 two companies merge. The savings estimate is based on a 20 percent reduction in
5 EUA's annual reporting, filing, and miscellaneous expenses of approximately $0.3
6 million, to reflect the elimination of some duplication and gains from integrating
7 regulatory affairs management.
8
9 G. Comparison with Other Transactions
10 Q. Did you compare the NEES-EUA merger to other transactions?
11 A. Yes. We reviewed a number of transactions, including the BEC Energy-COM/Energy
12 merger.
13
14 The 6 percent reduction in positions for the NEES-EUA merger falls in the 3 percent-
15 11 percent range for other transactions that we reviewed. We would not expect the
16 NFES-EUA percentage reductions to be at the high end of the range given the
17 significant difference in staffing levels between NEES and EUA (NEES has 3.7
18 times the staffing of EUA). In the other transactions, the ratio of employees for the
19 merger partners is typically in the 1 to 2 times range, which creates the potential for
20 higher percentage savings.
21
Hoffman/Levin
- 24 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 25 of 29
1 Q. Why did you conclude that the NEES-EUA merger has a more limited
2 opportunity to reduce costs?
3 A. First, NEES and EUA are relatively "lean" utilities. This limits the ability to reduce
4 staffing (the largest source of savings) in a merger situation.
5
6 For example, NEES and EUA were estimated to have a combined pre-merger staffing of
7 4,109 or 2.5 employees per thousand customers (based on a total of 1.66 million
8 customers). The comparable figures for BEC Energy and COM/Energy are combined
9 pre-merger staffing of 3,338 or 3.2 employees per thousand customers (based on a
10 total of 1.04 electric customers). Based on estimated position reductions in each
11 transaction, post-merger NEES-EUA will have 2.3 employees per thousand customers
12 compared to 2.9 employees per thousand customers for post-merger BEC
13 Energy-CONI/Energy.
14
15 Second, EUA has a relatively small cost base. For example, in 1997, combined T&D,
16 customer (excluding demand-side management) and A&G-related expenses were $77
17 million. COM/Energy's expenses were $116 million for the same electric functions and
18 $147 million if gas-related A&G expenses are included. Again, the lower cost base
19 limits the potential savings.
20
21 Q. Please summarize this section of your testimony.
Hoffman/Levin
- 25 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 26 of 29
1 A. Merger cost savings of $31.1 million in 2005 were estimated. Approximately 70
2 percent of savings ($21.5 million) were personnel-related. The savings are based
3 upon an assumed merger of NEES and EUA and would not result otherwise.
4
5 IV. Detailed Estimate of Cost to Achieve
6 Q. What types of costs are incurred when two companies merge?
7 A. Costs fall into the following four categories:
8 o Transaction costs: primarily the fees paid to investment bankers for advice on
9 the merger transaction and to outside legal counsel for advice on the merger
10 transaction and support in regulatory proceedings
11 o Personnel costs: primarily the out-of-pocket costs incurred to achieve the
12 reduction in positions, e.g., early retirement/severance packages; other costs
13 include retention payments to employees deemed necessary for a successful
14 integration, as well as relocation and retraining costs
15 o Transition costs: the costs incurred to integrate the two companies, e.g.,
16 support for organizational redesign and process integration; communication
17 costs; and costs related to the closing of facilities
18 o Information systems costs: the costs associated with integrating systems,
19 consolidating data centers, creating a common meter reading standard, and
20 connecting telecommunication networks
21
22 Q. How were these costs estimated for the potential merger of NEES and EUA?
Hoffman/Levin
- 26 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 27 of 29
1 A. Banker and legal fees were estimated by NEES and EUA management. Other
2 estimated costs to achieve were based on information provided by NEES and EUA
3 and on discussions with NEES management concerning the degree of integration
4 expected, planned corporate policies, and the resulting integration requirements.
5 This process addressed all significant costs to achieve.
6
7 Q. Please summarize the estimated cost to achieve for the merger.
8 A. The cost to achieve was estimated at $63.6 million - approximately $11.4 million for
9 transaction costs, $40.1 million for personnel costs; $4.6 million for transition costs,
10 and $7.6 million for information systems costs. Details are provided in Exhibits
11 DJH-1 and 2 and below. Approximately 85 percent of the costs will be incurred in
12 the 1999-2000 period.
13
14 Q. Please discuss the estimated transaction costs of approximately $11.4 million.
15 A. The primary transaction costs are for merger assistance provided by investment
16 bankers and merger and regulatory assistance from outside counsel. These costs
17 were estimated by NEES and EUA at $7.5 million for banker fees and $3.5 million
18 for legal fees. The other transaction cost included is for director and officer tail
19 liability coverage ($0.4 million).
20
Hoffman/Levin
- 27 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 28 of 29
1 Q. Please discuss the estimated personnel costs of approximately $40.1 million.
2 A. The most significant personnel costs incurred in a merger are related to achieving
3 targeted reductions in the workforce.
4
5 Separation and retention costs were estimated at $35.2 million. These costs include
6 payments te employees for early retirement, severance and/or other separation
7 packages; payments to executives other than EUA parent company, generation-related,
8 and unregulated business executives; and retention of key employees.
9
10 Other costs were estimated at $5 million. These costs include estimated relocation
11 and miscellaneous costs ($2.8 million) and estimated retraining and reorientation
12 costs for customer services, T&D, and administrative personnel to learn about future
13 work processes, as well as company policies and practices ($2.2 million).
14
Hoffman/Levin
- 28 -
<PAGE>
New England Electric System
Eastern Utilities Associates
Testimony of D. J. Hoffman and R. J. Levin
Page 29 of 29
1 Q. Please discuss the estimated transition costs of $4.6 million.
2 A. Transition costs are costs incurred to integrate the separate operations of the two
3 companies. Estimated costs for the NEES-EUA merger included $2.0 million for
4 outside organizational and change management support; $0.8 million for internal
5 process integration teams; $0.5 million for communications about the merger and
6 integration process to employees and external parties, e.g., shareholders, regulatory
7 commissions, vendors, and the investment community; $1.0 million for the closing
8 of some facilities and for the reconfiguration of other facilities; and $0.3 million for
9 changes to corporate signage and stationary.
10
11 Q. Please discuss the estimated information systems costs of $7.6 million.
12 A. The most significant IS cost was an estimated $6.6 million for applications
13 integration, data conversion, and the consolidation of data centers. Other costs
14 included $0.6 million to outfit EUA meter readers with NEES-standard meter
15 reading devices; and $0.4 million to link the two telecommunications networks and
16 to reconfigure/reprogram customer service center switches.
17
18 Q. Does this conclude your testimony?
19 A. Yes, it does.
Hoffman/Levin
- 29 -
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
R.I.P.U.C. Docket _____
EXHIBITS
OF
DAVID J. HOFFMAN & RICHARD J. LEVIN
Exhibit DJH-1 Summary of Savings and Cost to Achieve
Exhibit DJH-2 Supporting Working Papers
Exhibit DJH-3 Supporting Working Papers (Confidential)
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket _____
Exhibit DJH-1
Exhibit DJH-1
Summary of Savings and
Cost to Achieve
<PAGE>
<TABLE>
<CAPTION>
Exhibit DJH-1
Savings Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Personnel 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728
Non-Personnel
Information Systems 17 34 52 53 55 56 57 58 60 61 502
Supply Chain 247 513 539 566 594 622 651 680 710 741 5,862
Facilities - 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
Administrative and General 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
-------------------------------------------------------------------------------------------------------
Total Savings 16,137 26,442 28,224 29,149 30,095 31,061 32,049 33,059 34,090 35,145 295,452
Cost to Achieve 54,060 8,350 1,200 - - - - - - - 63,610
-------------------------------------------------------------------------------------------------------
Net Savings (37,923) 18,092 27,024 29,149 30,095 31,061 32,049 33,059 34,090 35,145 231,842
Confidential
Page 1 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Personnel Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
A&G Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized--- IS 0% 50% 100% 100% 100% 100% 100% 100% 100% 100%
% Realized---Other 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
----------
Ongong savings - IS 1,528 18
Ongoing savings - Other 6,680 70
Total Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
O&M Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
1 Capital Savings - - - - - - - - - -
2 - - - - - - - - -
3 - - - - - - - -
4 - - - - - - -
5 - - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
--------------------------------------------------------------------------------------------------------
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
Confidential
Page 2 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
Customer Related Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
Ongoing savings 4,930 62
Total Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
O&M Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
1 Capital Savings - - - - - - - - - -
2 - - - - - - - - -
3 - - - - - - - -
4 - - - - - - -
5 - - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
Total O&M + Rev Req Savings 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
Confidential
Page 3 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
T&D Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 35%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
Ongoing savings 6,088 78
Total Savings 4,566 6,222 6,359 6,499 6,642 6,788 6,938 7,090 7,246 7,406 65,757
O&M Savings 2,968 4,045 4,133 4,224 4,317 4,412 4,509 4,609 4,710 4,814 42,742
1 Capital Savings 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598 1,598
2 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178 2,178
3 2,226 2,226 2,226 2,226 2,226 2,226 2,226 2,226
4 2,275 2,275 2,275 2,275 2,275 2,275 2,275
5 2,325 2,325 2,325 2,325 2,325 2,325
6 2,376 2,376 2,376 2,376 2,376
7 2,428 2,428 2,428 2,428
8 2,482 2,482 2,482
9 2,536 2,536
10 2,592
--------------------------------------------------------------------------------------------------------
Total Capital Savings 1,598 3,776 6,002 8,276 10,601 12,977 15,405 17,887 20,423 23,015 119,961
Rev Req Savings 216 510 810 1,117 1,431.16 1,752 2,080 2,415 2,757 3,107 16,195
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937
Confidential
Page 4 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
Other Personnel
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 75% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Reductions
Ongoing savings 632 6
Total Savings 474 646 661 675 690 705 721 737 753 769 6,831
O&M Savings 474 646 661 675 690 705 721 737 753 769 6,831
1 Capital Savings - - - - - - - - - -
2 - - - - - - - - -
3 - - - - - - - -
4 - - - - - - -
5 - - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
--------------------------------------------------------------------------------------------------------
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 474 646 661 675 690 705 721 737 753 769 6,831
Total Personnel Savings
A&G 5,010 7,608 8,573 8,761 8,954 9,151 9,352 9,558 9,768 9,983 86,719
Customer-Related 3,697 5,038 5,149 5,262 5,378 5,496 5,617 5,741 5,867 5,996 53,242
T&D 3,184 4,554 4,944 5,342 5,749 6,164 6,589 7,023 7,467 7,921 58,937
Other 474 646 661 675 690 705 721 737 753 769 6,831
--------------------------------------------------------------------------------------------------------
Total 12,365 17,846 19,326 20,040 20,771 21,517 22,279 23,059 23,855 24,669 205,728
Confidential
Page 5 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
IS Savings Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Rev Req Rate 28.6%
Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 33% 67% 100% 100% 100% 100% 100% 100% 100% 100%
O&M Savings
A&G Applications - - - - - - - - - - -
T&D Applications - - - - - - - - - - -
Customer Applications - - - - - - - - - - -
Mainframe and Network 17 34 52 53 55 56 57 58 60 61 502
Midrange/Servers - - - - - - - - - - -
PC/Workstations - - - - - - - - - - -
Projects - - - - - - - - - - -
Telecommunications - - - - - - - - - - -
- -----------------------------------------------------------------------------------------------------------------------------------
Total O&M Savings 17 34 52 53 55 56 57 58 60 61 502
Capital Savings
A&G Applications
T&D Applications
Customer Applications
Mainframe and Network
Midrange/Servers
PC/Workstations
Projects (PeopleSoft) - -
Telecommunications
Total Capital Savings - - - - - - - - - - -
1 Capital Savings - - - - -
2 - - - - -
3 - - - - -
4 - - - - -
5 - - - - -
6 - - - - -
7 - - - -
8 - - -
9 - -
10 -
--------------------------------------------------------------------------------------------------------
Total Capital Savings - - - - - - - - - - -
Rev Req Savings - - - - - - - - - - -
--------------------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 17 34 52 53 55 56 57 58 60 61 502
Confidential
Page 6 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Supply Chain Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Inventory
% Capitalized 100%
Carrying Cost 13.7%
Total Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Inventory Reduction 899
Annual Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485
O&M Savings 0 0 0 0 0 0 0 0 0 0 0
Capital Savings 450 919 939 960 981 1,002 1,024 1,047 1,070 1,093 9,485
Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299
-----------------------------------------------------------------------------------------------
O&M +Rev Req Savings 62 126 129 131 134 137 140 143 147 150 1,299
Confidential
Page 7 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Procurement
% Capitalized 35%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing savings 290
Total Savings 145 296 303 310 316 323 330 338 345 353 3,060
O&M Savings 94 193 197 201 206 210 215 220 224 229 1,989
1 Capital Savings 51 51 51 51 51 51 51 51 51 51
2 104 104 104 104 104 104 104 104 104
3 106 106 106 106 106 106 106 106
4 108 108 108 108 108 108 108
5 111 111 111 111 111 111
6 113 113 113 113 113
7 116 116 116 116
8 118 118 118
9 121 121
10 123
-----------------------------------------------------------------------------------------------
Total Capital Savings 51 154 260 369 480 593 708 827 947 1,071 5,460
Rev Req Savings 7 21 35 50 65 80 96 112 128 145 737
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 101 214 232 251 270 290 310 331 352 374 2,726
Confidential
Page 8 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Contractor Services
% Capitalized 35%
Rev Req Rate 13.5%
Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing savings 27
Total Savings 14 28 28 29 29 30 31 31 32 33 285
O&M Savings 9 18 18 19 19 20 20 20 21 21 185
1 Capital Savings 5 5 5 5 5 5 5 5 5 5
10 10 10 10 10 10 10 10 10
10 10 10 10 10 10 10 10
10 10 10 10 10 10 10
10 10 10 10 10 10
11 11 11 11 11
11 11 11 11
11 11 11
11 11
11 11
Total Capital Savings 5 14 24 34 45 55 66 77 88 100 508
Rev Req Savings 1 2 3 5 6 7 9 10 12 13 69
Total O&M + Rev Req Savings 9 20 22 23 25 27 29 31 33 35 254
Confidential
Page 9 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Vehicles
% Capitalized 0%
Rev Req Rate 13.5%
Escalation Total 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
% Realized 50% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing savings 150
Total Savings 75 153 157 160 164 167 171 175 179 182 1,583
O&M Savings 75 153 157 160 164 167 171 175 179 182 1,583
1 Capital Savings 0 0 0 0 0 0 0 0 0 0
2 0 0 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0
5 0 0 0 0 0 0
6 0 0 0 0 0
7 0 0 0 0
8 0 0 0
9 0 0
10 0
-----------------------------------------------------------------------------------------------
Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0
Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 75 153 157 160 164 167 171 175 179 182 1,583
Total SCM Savings
Inventory 62 126 129 131 134 137 140 143 147 150 1,299
Procurement 101 214 232 251 270 290 310 331 352 374 2,726
Contractor Services 9 20 22 23 25 27 29 31 33 35 254
Vehicles 75 153 157 160 164 167 171 175 179 182 1,583
-----------------------------------------------------------------------------------------------
Total 247 513 539 566 594 622 651 680 710 741 5,862
Confidential
Page 10 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Facilities Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
Phase-in 0% 100% 100% 100% 100% 100% 100% 100% 100% 100%
Ongoing Savings 4,179
Total Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
O&M Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
1 Capital Savings 0 0 0 0 0 0 0 0 0 0
2 0 0 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0
5 0 0 0 0 0 0
6 0 0 0 0 0
7 0 0 0 0
8 0 0 0
9 0 0
10 0
-----------------------------------------------------------------------------------------------
Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0
Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 0 4,271 4,365 4,461 4,559 4,659 4,762 4,867 4,974 5,083 42,001
Confidential
Page 11 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Non-Labor A&G Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
% Capitalized 0%
Rev Req Rate 13.5%
Escalation 2.2% 4.4% 6.7% 9.1% 11.5% 13.9% 16.5% 19.0% 21.6%
A&G Overheads 486 690 733 749 766 783 800 818 835 854 7,514
Advertising 273 279 285 291 298 304 311 318 325 332 3,017
Association Dues 82 84 86 88 89 91 93 95 98 100 906
Benefits Administration 0 0 52 53 55 56 57 58 60 61 451
Corporate Governance 787 804 822 840 859 877 897 916 937 957 8,697
Financing Costs and Fees 272 278 284 290 297 303 310 317 324 331 3,006
Insurance 646 660 675 690 705 720 736 752 769 786 7,139
Professional Services 905 925 945 966 987 1,009 1,031 1,054 1,077 1,101 10,001
Regulatory Expenses 57 58 60 61 62 64 65 66 68 69 630
Total Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
O&M Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
1 Capital Savings 0 0 0 0 0 0 0 0 0 0
2 0 0 0 0 0 0 0 0 0
3 0 0 0 0 0 0 0 0
4 0 0 0 0 0 0 0
5 0 0 0 0 0 0
6 0 0 0 0 0
7 0 0 0 0
8 0 0 0
9 0 0
10 0
-----------------------------------------------------------------------------------------------
Total Capital Savings 0 0 0 0 0 0 0 0 0 0 0
Rev Req Savings 0 0 0 0 0 0 0 0 0 0 0
-----------------------------------------------------------------------------------------------
Total O&M + Rev Req Savings 3,508 3,778 3,942 4,029 4,117 4,208 4,300 4,395 4,492 4,590 41,359
Confidential
Page 12 of 13
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEES-EUA Savings Summary
Cost to Achieve Summary
in $000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Total
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Transaction Costs
Bankers fees 7,500 7,500
Legal fees 3,500 3,500
D&O liability tail coverage 400 400
Total Transaction Costs 11,400 - - 11,400
Personnel Costs
Separation / Retention 25,850 8,100 1,200 35,150
Relocation, Retraining,
Reorientation and Miscellaneous 4,950 4,950
Total Personnel Costs 30,800 8,100 1,200 40,100
Transition Costs
Internal/Outside Support 2,810 2,810
Communications 500 500
Facilities Consolidation 750 250 1,000
Other 250 250
Total Transition Costs 4,310 250 - 4,560
Information Systems
Systems Integration and Data
Center Consolidation 6,600 6,600
Meter Reading Hardware 600 600
Telecommunications Costs 350 350
Total Information Systems Costs 7,550 7,550
Total Cost to Achieve 54,060 8,350 1,200 63,610
Confidential
Page 13 of 13
</TABLE>
<PAGE>
Narragansett Electric
BVE/Newport Electric
R.I.P.U.C. Docket _____
Exhibit DJH-2
Exhibit DJH-2
Supporting Working Papers
(Non-Confidential)
<PAGE>
Exhibit DJH-2
Information Systems
Savings
<PAGE>
<TABLE>
<CAPTION>
Software comparisons Confidential
- ----------------------------------------------------------------------------------------------------------------------
Application NEES EUA Comments
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Corporate, Financial, and o Walker o Various financial packages
Administrative Systems
- Significant programming/ - IVIS (AP, 1993, Y2K
customization has upgrade scheduled
improved speed 1Q99)
- Works well for NEES' - GEAC (Fixed assets, 1988)
business model
(intracompany billing,
etc.)
- Limited decision support - In-house S/W (Purchasing/
capabilities Materials Mgmt, 1992)
- Expandable for similar - Lawson (General Ledger, 12/98)
business model
o Focus for 1999 on Y2K upgrades
- -----------------------------------------------------------------------------------------------------------------------
HR/Payroll o PeopleSoft o CYBORG
- Installation complete in - Y2K upgrade in 1999
early 1999
- Expandable, but license
may be restrictive
- -----------------------------------------------------------------------------------------------------------------------
2
<PAGE>
Software comparisons Confidential
- -----------------------------------------------------------------------------------------------------------------------
Application NEES EUA Comments
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Customer System o CIS - developed in-house o CIS - developed in-house
- GUI front-end placed - GUI front-end placed
on mainframe system on mainframe system
- Expandable, but only - Major upgrade 1997
for one dimensional
(e.g., electric only) - Integrated with Radix
customers hand-held meter
reading devices
- -----------------------------------------------------------------------------------------------------------------------
Operational Systems o Numerous o Numerous
- Many systems running - Many systems running
on midrange and on mainframe
mainframe
- Intergraph digital
- Major GIS system topology mapping
implementation half system
complete
- Map-based trouble
reporting system
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
3
<PAGE>
<TABLE>
<CAPTION>
Hardware comparisons Confidential
- -----------------------------------------------------------------------------------------------------------------------
Device NEES EUA
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Mainframes o IBM 390 SP; CMOS 4 engines 220 o Amdahl 45 MIPS
MIPS
- Expandable up to 540-600 MIPS
- -----------------------------------------------------------------------------------------------------------------------
Midrange o IBM RS6000
- Runs decision support, PeopleSoft
and retail applications
- -----------------------------------------------------------------------------------------------------------------------
Servers o DEC alpha and IBM AIX o Sun (Unix)
o Few Digital VAXes left
- ~60 o Compaq, Gateway
o Migrating to NT
o Approximately 20 servers total
- -----------------------------------------------------------------------------------------------------------------------
PCs o 2500 Pentium PCs o 600 Pentium PCs (Gateway, Compaq)
o Additional 400 devices o 150 "Dumb" terminals
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
4
<PAGE>
<TABLE>
<CAPTION>
System environment comparisons Confidential
- -----------------------------------------------------------------------------------------------------------------------
Device NEES EUA
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Mainframes o VMS, IMS, CICS, DB2 o VMS, CICS, Sybase
- -----------------------------------------------------------------------------------------------------------------------
Servers o Unix (primary), NT (becoming o Unix, NT (becoming standard
standard)
- -----------------------------------------------------------------------------------------------------------------------
Networks o Novell 4.11 o Eliminate TAO e-mail and standardize
on MS-Outlook (MS-Exchange-based)
- Considering 5.0
o Ethernet 100%
- -----------------------------------------------------------------------------------------------------------------------
PCs o Windows 3.1, 95, NT o MS Office
- Standard is 95 for A&G positions
- Standard is NT for operations
positions
- -----------------------------------------------------------------------------------------------------------------------
</TABLE>
5
<PAGE>
<TABLE>
<CAPTION>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Savings opportunities
- -----------------------------------------------------------------------------------------------------------------------------------
Area Opportunity Savings Assumptions Savings
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Applications o Corporate, financial, administrative
systems:
- Integrate EUA data into Walker - No incremental license fees for
-> NEES
- Discontinue EUA's financial - Reduce 1/3 of EUA's financial - 3 positions
systems applications support positions
- Move data onto NEES' - Reduce 100% of EUA's HR and - 1 position
PeopleSoft system payroll applications support
- Disconue EIA's CYBORG -> positions
HR and payroll system
----------------------------------------------------------------------------------------------------------
o Customer and related systems:
- Integrate EUA call center - Reduce 1/3 of EUA's call center - 3 positions
application into NEES' system -> applications support positions
- Discontinue EUA's CIS systems
----------------------------------------------------------------------------------------------------------
o T&D systems:
- Migrate EUA's work -> - Reduce 1/3 of EUA's T&D - 3 positions
management system to NEES' applications support positions
WIN system
- Migrate topological info from
EUA's Intergraph into NEGIS
and re-digitize if appropriate
- Discontinue EUA's T&D
systems
- -----------------------------------------------------------------------------------------------------------------------------------
6
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Savings opportunities
- -----------------------------------------------------------------------------------------------------------------------------------
Area Opportunity Savings Assumptions Savings
- -----------------------------------------------------------------------------------------------------------------------------------
Hardware/System o Data center/mainframe:
Software - Close EUA's data center -> - Reduce EUA's data center and - 5 positions
tech support positions by 50%
- Reduce EUA's associated $2M - $1M
non-labor IS cost for mainframe
maintenance, S/W licenses, and
disaster recovery by $1M;
remaining $1M to focus on
software licenses and support
----------------------------------------------------------------------------------------------------------
o Midrange system:
- - -
- -
----------------------------------------------------------------------------------------------------------
o Servers/network:
- - -
----------------------------------------------------------------------------------------------------------
o PCs/workstations:
- Reduce end-user/help desk -> - Reduce EUA's help desk/end - 1 position
support staff user support by 20%
- -----------------------------------------------------------------------------------------------------------------------------------
7
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Savings opportunities
- -----------------------------------------------------------------------------------------------------------------------------------
Area Opportunity Savings Assumptions Savings
- -----------------------------------------------------------------------------------------------------------------------------------
Telecommunications o Integrates NEES's and EUA's -> - Reduce 15% of EUA's network - 1 position
telecommunications networks support positions
- -----------------------------------------------------------------------------------------------------------------------------------
Facilities o Cost savings captured in the -> - Cost savings captured in
closing of West Bridgewater; IS Facilities section
is a portion
o Integrate EUA's bill printing, -> - Cost avoidance of outsourcing - $250K
stuffing, and mailing operations bill printing, stuffing, and
into NEES' operations mailing (one additional resource
required is already reflected in
office services)
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
8
<PAGE>
<TABLE>
<CAPTION>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Cost to achieve
- -----------------------------------------------------------------------------------------------------------------------------------
Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Applications o Corporate, financial,
administrative systems:
- System "combination" costs -> - Cost for application and - $2.1 M1
data conversion
---------------------------------------------------------------------------------------------------------------
o Customer and related systems:
- System "combination" costs -> - Cost for application and - $2.1M1
data conversion
- Outfit meter readers with -> - 55 devices @$10,000 each - $0.6M
ITRON devices (including device,
training, programming,
transfer of routing info)
---------------------------------------------------------------------------------------------------------------
o T&D systems:
- System "combination" costs -> - Cost for application and - $2.1M1
data conversion
- -----------------------------------------------------------------------------------------------------------------------------------
- ---------------
1 Prorated from base of $6.3M.
9
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Cost to achieve
- -----------------------------------------------------------------------------------------------------------------------------------
Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost
- -----------------------------------------------------------------------------------------------------------------------------------
Hardware/System o Data center/mainframe:
Software - Discontinuation of EUA -> - Closing cost -$0.3M
data center
- Increase NEES' processing -> - Turn up 2 additional - - $1.0M
power CMOS enginees (cost of
H/W & S/W)
---------------------------------------------------------------------------------------------------------------
o Midrange system:
- Transfer midrange -> - Turn up 2 additional - - $0.2M
application to NEES nodes of IBM RS6000
midrange system
---------------------------------------------------------------------------------------------------------------
o Servers/networks:
- Network reconfiguration -> - - -
---------------------------------------------------------------------------------------------------------------
o PCs/workstations:
- No costs incurred -> - Freed-up PCs available to - -
replace dumb terminals
- -----------------------------------------------------------------------------------------------------------------------------------
10
<PAGE>
Information systems and telecommunications Confidential
- -----------------------------------------------------------------------------------------------------------------------------------
Cost to achieve
- -----------------------------------------------------------------------------------------------------------------------------------
Area Potential Costs Cost Assumptions Initial Cost Ongoing Cost
- -----------------------------------------------------------------------------------------------------------------------------------
Telecommunications o Costs to integrate both companies' - $100K
networks
o Customer service center switch: - Switch capacity sufficient - $250K
Cost to reconfigure EUA's tie-lines to handle EUA's
and reprogram switch additional inbound calls
- -----------------------------------------------------------------------------------------------------------------------------------
Facilities o Costs are captured in the closing of
West Bridgewater facility
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
11
<PAGE>
Purchases
35
1
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
35 Annual materials and equipment purchases by commodity class
a) T&D related
b) Corporate and other
See attached.
<PAGE>
ADDRL
#35
35
2
N35 Annual materials and equipment purchases by commodity class, T&D
Issues from M&S Total T&D Corp. &
Stock, Cap,&Exp. Purchases Other
Blackstone Valley 990,780 442,254 1,433,034 195,459
Eastern Edison 2,404,158 840,142 3,244,300 377,438
Newport Electric 604,470 187,815 792,285 101,099
--------------------------------------------------
3,999,408 1,470,211 5,469,619 673,996
========= =======
Meters 998,000
Transformers 2,249,000
Inputs
<PAGE>
<TABLE>
<CAPTION>
EUA DISTRIBUTION COMPANIES & MONTAUP TRANSMISSION
1999 Capital Budget BVE EECo NECo VEC
Blankets:
Priority Priority Req 1999 1999 Cumm Distrib Transm
No Code No Title Expenditures Expenditures OH Lines UG Substation OH Lines
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1 1-99 New Business $4,484.0 $ 4,484.0 30,400 11,500 0 0
2 2-99 Routine Distribution Imps/Rets 2,445.0 6,929.0 20,900 2,060 0 0
3 3-99 Meter Devices & Installations 998.0 7,927.0 0 0 0 0
4 4-99 Line Transf Capacitors & Regs 2,249.0 10,176.0 0 0 0 0
5 5-99 Distribution Substations 235.0 10,411.0 67 0 1,634 0
6 6-99 Street & Area Lighting 786.9 11,197.9 5,960 1,090 0 0
7 7-99 Building Imps/Rets 108.1 11,306.0 0 0 0 0
8 8-99 Transmission Lines & Subs 388.0 11,694.0 400 0 0 45000
9 9-99 Damages and/or Failures 534.0 12,228.0 4,750 2,192 0 0
10 10-99 Furniture, Tools, Lab & Comm 263.9 12,491.9 0 0 0 0
Equip
11 12-99 Land & Land Rights 90.0 12,581.9 0 0 0 0
12 13-99 Misc. Production Imps/Rets 0.0 12,581.9 0 0 0 0
Blanket Subtotal $12,581.9 62,477 16,842 1,634 4,500
Specifics: General Projects
1 HP.B Fire Alarm Replacement $35.0 $35.0 0 0 0 0
2 HP.O BVE Operators Roof 120.0 155.0 0 0 0 0
Replacement
Specifics: Substation
Projects
1 HP.D Dupont Sub Capacitor Bank $102.0 $102.0 0 120 269 0
Addition
2 MP.C 690 Swansea DFP Upgrades 76.9 178.9 0 0 696 0
3 MP.C Scituate Substation Relay 44.0 222.9 0 0 192 0
Upgrades
4 MP.C Riverside Substation Rebuild 1,108.0 1,330.9 0 576 4,416 0
5 MP.C Mill St. Substation Relay 61.0 1,391.9 0 0 288 0
Upgrades
6 MP.C Jepson Sub Ground Gnd 143.0 1,534.9 0 0 864 0
Replacement
7 MP.C 199 Jepson Sub Bus Thermal 65.5 1,600.4 0 0 290 0
Upgrade
8 MP.C Install 2nd Transformer at 222.0 1,822.4 0 0 1,728 0
Eldred
9 MP.C 198 Gate II Overcurrent Relay 78.0 1,900.4 0 0 851 0
Upgrade
10 LP.A Repl Jepson Sub Breaker 3729 55.0 1,955.4 0 0 346 0
11 LP.B Repl Gate II Transformer 33.0 1,988.4 0 0 288 0
Bushings
Substation Subtotal $1,988.4 0 696 10,228 0
Specifics: Transmission Projects
1 HP. EMI/Tiverton Power Plant $1,070.0 $1,070.0 0 0 0 6,400
2 HP. EMI/Tiverton Power Plant 260.0 1,330.0 0 0 1800 0
3 HP. 839 EMI/Tiverton Power Plant 1,950.0 3,305.0 0 0
<PAGE>
4 HP. 837 EMI/Dignton Interconnection 220.0 3,525.0 0 0
5 HP. ANP Power Plant 1,135.0 4,660.0 0 0 3,200 440
6 HP.D 238 Sherman Rd Sub Foundations 40.0 4,700.0 0 0 2 0
7 HP.D Belmont Replace Switch S1-1 29.0 4,729.0 0 0 0 307
8 MP.C Washington Substation Doub 2,100.0 6,829.0 0 180 3,643 4,151
End
Transmission Subtotal $6,829.0 0 180 8,893 18,998
Specifics: Distribution
Projects
1 HP.A Gate II Feeder Addition $86.0 $86.0 220 170 220 0
2 HP.C 692 Marvel St. Swansea Road Imps 18.9 104.9 75 0 0
0
3 HP.C 283 Main St. Easton - Road 74.8 179.7 302 128 0 0
Widening
4 HP.C 691 Bank St. Swansea Road Imps. 86.1 265.8 180 0 0 0
Phase II
5 HP.C 1999 Street Light Conversion 385.0 650.8 1,200 800 0 0
Program
6 HP.C 1999 St. Light Conversion, 57.0 707.8 300 0 0 0
Portsmouth
7 HP.D Washington Substation Feeder 220.0 927.8 550 150 0 0
Addition
8 HP.D 196 Reliability Imps. Back yard 22.0 949.8 100 0 0 0
Construction
9 HP.D 293 North Main St. Rebuild 42.5 992.3 0 0 0 0
10 HP.D R270 Main St. Rebuild, Brockton 46.8 1,039.1 0 0 0 0
11 HP.D 197 Conversion - Senes St. Light 60.0 1,099.1 250 420 0 0
Circuits
12 HP.D Condenmed Pole Replacement 580.0 1,679.1 7,600 0 0 0
- 1999
13 HP.D Condemned Pole Replacement 220.0 1,899.1 2,850 0 0 0
- 1999
14 MP.C 278 Storm Proofing 618.4 7,447.4 5,719 0 0 0
15 MP.C Modern Furniture Vault 147.0 7,594.4 0 1,200 0 0
16 MP.C Distribution Automation 325.0 7,919.4 700 0 0 0
17 MP.C Distribution Automation 650.0 8,569.4 1,400 0 1,280 0
18 MP.C 269 Condemned Poles Easton 166.1 8,735.5 1,789 0 0 0
19 MP.C R274 Belmont St Rebuild, Brockt 199.1 8,934.6 558 200 0 0
20 MP.C 261 #6 CU Replacement-Scituate 232.0 9,166.6 2,167 0 0 0
21 MP.C 262 #6 CU Replacement-Brockton 432.0 9,598.6 3,728 0 0 0
22 LP.A 181 Install Neutral Wire, 51.0 9,649.6 450 0 0 0
Portsmouth
23 LP.A 679 Cable Removal-Fall River 46.0 9,695.6 0 4,380 0 0
24 LP.A 675 23kV Cable Removal-Fall 32.3 9,727.9 0 4,000 0 0
River
25 LP.B 178 Remove 23kV Cable 13.5 9,741.4 0 270 0 0
Distribution Subtotal $4,811.5 30,138 11,718 2,140 0
Total dollars/Manhours $26,365.8 92,615 29,436 22,895 22,498
Budgeted
Total Available Manhours 78,235 19,673 21,206 22,498
Surplus/Deficit Manhours (14,380) (9,763) (1,689) 19,800
<PAGE>
EUASC MH Requirements 0 0 0 0
Surplus (Deficit) Manhours (14,380) (9,763) (1,689) 19,800
including EUASC
* Note There is an estimated contribution of $128,000 from EMI on this project
** Note There are 250 Electrical Maintenance manhours associated with this job
*** Note There are 3,500 Electrical Maintenance manhours associated with this job
</TABLE>
<PAGE>
Inventory
55
1
DDRL (12/17/98)
55. Details of how materials are stocked, ordered and distributed including:
- value of T&D inventory
- degree of centralization
- quantities of materials in field locations
- use of vendors to provide materials in emergencies
Value of T&D inventory / Quantities of materials stored in field locations
Inventory Value
6/30/98
Lincoln $906,287
Brockton $941,766
Hanover $244,522
Fall River $725,489
Newport $776,757
--------
System Total $3,594,821
Input
Degree of centralization
This is answered in ADDRL (12/19/98) #39.
Use of vendors to provide materials in emergencies
In addition to maintaining a safety stock, we make an assessment of our critical
material needs prior to a forecasted storm and contact vendors for immediate
re-supply where appropriate. Our vendors have been responsive in the past and we
have not experienced a shortage of critical materials in any storm or other
emergency in at least the last ten years. EUA does not have alliances with any
vendors to maintain inventory on our behalf.
<PAGE>
Inventory 39R
1
ADDRL (12/19/98)
39. High-level overview of central stores, e.g. value of inventory, annual
receipts and issues, square footage, expandability.
EUA operates on a "main stocking" philosophy. A number of stock items are
stocked at one of the retail company stockrooms in quantity sufficient to
provide for the needs of the other retail locations. The daily courier or
scheduled trips by the stockroom stake-body vehicle are used to deliver
this material where needed. We are presently studying a central warehouse
concept.
The year-to-date monthly average inventory value as of 6/30/98 (excluding
Somerset plant) is $3,552,719.
The year-to-date receipts as of 6/30/98 annualized are $4,391,220.
The year-to-date issues as of 6/30/98 annualized are $4,613,724.
The Inventory Turns Ratio as of 6/30/98 is 1.30.
Inventory Turns Ratio is defined as Total Inventory Issues for the last 12
months divided by the 12 month rolling average Inventory level. All items
in inventory are included. This includes safety stock, scrap, emergency
spares and obsolete items. Inventory at Somerset Station excluded.
The Carrying Cost for inventory is approximately 53% as of 10/31/98.
Carrying Cost (or Stores Clearing Rate) is defined as the 12 month rolling
average of the sum of storeroom expenses, storeroom overheads, related
EUASC expenses, inventory over/short, lobby stock, storeroom electric use,
misc. journal entries applied to all stock items issued by the storeroom.
We maintain stockrooms at all operating centers. The square footage is not
readily available. The Lincoln and Newport stockrooms provide for some
level of expandability.
<PAGE>
ADDRL (12/19/98)
39
1
39. High-level overview of central stores, e.g. value of inventory, annual
receipts and issues, square footage, expandability.
EUA operates on a "main stocking" philosophy. A number of stock items are
stocked at one of the retail company stockrooms in quantity sufficient to
provide for the needs of the other retail locations. The daily courier or
scheduled trips by the stockroom stake-body vehicle are used to deliver
this material where needed. We are presently studying a central warehouse
concept.
Total value of inventory (excluding Somerset plant) is $3,600,000.
Annual receipts are $730,000.
Annual issues are $760,000.
Inventory Turns Ratio (no exclusions) as of 10/31/98 is 1.30.
We maintain stockrooms at all operating centers. The square footage is not
readily available. The Lincoln and Newport stockrooms provide for some
level of expandability.
<PAGE>
DDRL (12/17/98)
56
1
56. Details of how the Company manages distribution transformer inventory.
Transformers are pre-capitalized. The inventory level of transformers is
managed by the Materials Management Department. Similar to regular
inventory items, minimums and maximums are established for the most
frequently used distribution transformers. All purchases are coordinated by
Materials Management. Engineering provides input on planned requirements. A
goal of 4% in-stock to in-service units has been established for Materials
Management. Transformer refurbishing is performed by an outside firm.
Refurbishing and junking are coordinated by Materials Management.
<PAGE>
DDRL (12/17/98)
58
1
58. List of the ten largest contracts the Company and its utility subsidiaries
have with suppliers of O&M related equipment and services.
Contract Services
DESCRIPTION 1998
VENDOR NAME OF SERVICE PROJECTED INPUTS
Asplundh Tree Expert Co. Vegetation Control $936,240 $000
Barnes Tree Service Vegetation Control 540,220
R.A. Gill Tree Service Vegetation Control 319,604
Northern Tree Service Vegetation Control 418,796 2,383
New England Tree Vegetation Control 99,253
Vegetation, Inc. Vegetation Control 69,150
Collins Crane Rigging 1,325
Clean Harbors Environmental 60,973
Environ. Protect. Serv. Transformer Refurbishin 75,833 198
QSC Tower Painting 60,000
<PAGE>
ADDRL #38
N38 38
BLACKSTONE VALLEY ELECTRIC 2
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
Asplundh Tree Trimming 56,222
Barnes Tree Services Tree Trimming 140,399
Blackstone Valley Security Security Services 0
Clean Harbor Environmental 19,603
Coopers & Lybrand Accounting 34,145
Credit Bureau Collection Fees 20,959
Dickstein, Shapiro & Moris Legal
Financial Collection Collection Fees 1,149
Isaacson, Rosenbaum Legal 743,588
McDermott, Will & Emery Legal 32,576
Northern Tree Service Tree Trimming 491,290
Ocean State Janitorial Cleaning 40,408
Osmose Wood Press Pole Treatment/Inspection 448
Stanley Bleeker, Esq. Legal 0
Tillinghast, Collins & Graham Legal 1,911
(A) Colflax Packing Conservation 1,214
(A) Delta Electric Motor Conservation 639
(A) RISE Conservation 7,690
(A) Slater Dye Works Conservation 17,313
-------
1,609,534
=========
(A) These vendors participated in Eastern Edison's conservation, load,
management programs. management programs.
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16.
Prepared by Michelle Uzzo 12/22/98
<PAGE>
<TABLE>
<CAPTION>
EASTERN EDISON COMPANY 38
PROFESSIONAL SERVICES 3
VENDOR NAME DESCRIPTION OF SERVICE 1997
<S> <C> <C> <C>
American Staffing Assoc. Employment 118,240
Asplundh Tree Trimming 919,253
Barnes Tree Service Tree Trimming 140,782
Clean Harbors Environmental
Coopers and Lybrand Accounting 62,883
Duff & Phelps Consulting 40,000
Environmental Protection Service Maintenance 44,555
First Financial Resources Collection Fees 33,933
First Security Services Security
Hanson Police Dept. Police Detail 31,478
J. D. Payroll Services Temp Services
MASS Save Consulting 342,286
McDermott,Will & Emery Legal 1,209,449
Misc. Contract Services* 1,605,966
Misc. Engineering* 38,605
Misc. Legal* 12,155
Miscellaneous* 314,463
Osmose Wood Press Pole Treatment/Inspection
Pembroke Police Dept. Police Detail
R.A. Gill Tree Service Tree Trimming 227,341
R.E. Tilgren Tree Trimming 46,695
Read, Adami, Kaiser Legal 72,599
Rockland Police Dept Police Detail 26,218
Service Master Maintenance 29,796
State Street Bank & Trust Trustee/Administrative Fee
Suburban Contract Cleaning
Town of Bridgewater Police Detail
Town of Easton Police Detail 56,526
Town of Norwell Police Detail 42,745
Town of Scituate Police Detail
Town of Stoughton Police Detail
(A) Conservation Services Group Conservation 361,903
(A) Demand Mgmt Conservation
(A) Energie Innovation Inc. Conservation 84,095
(A) Energy Conservation Conservation 123,124
(A) Energy Federation Conservation 306,904
(A) Fall Realty & Harris Energy Conservation 38,353
(A) Fleet Bank Conservation 28,182
(A) Harris Energy Systems Conservation 489,801
(A) J&R Industrial Wiring Conservation 206,124
(A) Main Street Textiles Conservation 133,990
(A) MUPAC Corp & Harris Energy Conservation 26,114
(A) National Resource Mgmt. Conservation 375,923
(A) Relocation Resources, Inc. Conservation 61,985
(A) Shaws Supermarkets Inc. Conservation 168,265
(A) Star Market & Harris Energy Conservation 31,080
(A) Stop & Shop Supermarket Co. Conservation 49,799
(A) Ware Rite & Harris Energy Conservation 32,759
(A) Whaling Mfg. Co., Inc. Conservation 29,235
-------
7,963,604
=========
</TABLE>
* Aggregate amounts to any one entity less than $25,000 have been accumulated
in this description.
(A) These vendors participated in Eastern Edison's conservation, load,
management programs. management programs.
Note: The source for this information was based on O&M codes 9, 10, 11 &
16.
<PAGE>
NEWPORT ELECTRIC CORPORATION 38
PROFESSIONAL SERVICES 4
VENDOR NAME DESCRIPTION OF SERVICE 1997
Barnes Tree Services Tree Trimming 187,206
Clean Harbor Environmental 11,989
Coopers & Lybrand Accounting 30,982
Credit Info Collection Fees 12,118
McDermott, Will & Emery Legal 16,803
Morgan, Brown & Joy Legal 340
RISE Conservation 141,057
Tillinghast, Collins & Graham Legal 45,587
------
446,062
=======
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19.
<PAGE>
EUA Service Corp. 38
PROFESSIONAL SERVICES 5
(Account # 923)
<TABLE>
<CAPTION>
VENDOR NAME DESCRIPTION OF SERVICE 1997
<S> <C>
McDermott, Will & Emery Legal 359,773
First Security Services Security 124,975
Contract Cleaning Collaborative Cleaning
Eastern Edison Company Arborist/Technical Trainers 351,846
Salomon Brothers Inc. Investment Services 107,956
Media Concepts Printing Services 114,897
Norfolk Date Data Processing Time Cards
Cambridge Reports, Inc. Customer Services 70,560
J. Flanagan & Co. Legislative Activity 48,000
DRI McGraw-Hill
Newport Electric Corp. Arborist/Technical Trainers
Twenty First Century
AUC Management Consultants Consulting
Misc Legal * 82,677
Misc Accounting 68,988
Misc EDP * 41,871
Misc Building & Maintenance 182,203
Other * 421,494
Misc Engineering 788
---
1,956,038
</TABLE>
* Payments made to payee is less than $100,000
Amounts in Bold print are estimates based on the average of 1996 & 1997.
Prepared by Michelle Uzzo 12/22108 o:\profsvs
<PAGE>
VEHICLES
56
DDRL (12/17/98) 1
54. Details of vehicles including:
- types and numbers of vehicles
- age of vehicles
- maintenance programs and replacement criteria
- fuel management programs
- criteria for assigning vehicles to non-physical workers
12/15/98
TYPE OF FLEET VEHICLE COUNT
BUCKET TRUCK, MATERIAL HANDLER 51
BUCKET TRUCK, LIGHT-DUTY 15
DIGGER -DERRICK TRUCK 8
VAN, LARGE STEP TYPE 25
VAN, SMALL 68
DUMPTRUCK 8
STAKE-BODY TRUCK 2
EFFER CRANE TRUCK 3
PICKUP TRUCK 110
SEDAN 52
TRAILER 62
MOBILE SUBSTATION, XFMR OR REGUL. 6
TRACTOR 5
FORKLIFT 11
TRACK VEHICLE 1
CRANE TRUCK 2
TANKER TRUCK 1
SPECIAL EQUIPMENT* 24
TOTAL 454
* Includes powered reel trailers, puller-tensioners, woodchippers, generator
trailer, cement mixer, tank trailer, test equipment trailers, waterpump
trailer, compressors.
AVERAGE AGE OF VEHICLES MONTHS
All Vehicles (excl. trailers, spec. equip.) 93
All Units 120
<PAGE>
DDRL (12/17/98) 54
2
54. Cont'd
MAINTENANCE PROGRAMS AND REPLACEMENT CRITERIA
EUA adheres to a preventative maintenance program based on manufacturers'
recommendations, generally accepted automotive industry practices and experience
related specifically to a particular vehicle or class of vehicles. A
computerized maintenance management system (FleetTracker) is used to track
vehicle usage in terms of miles and/or hours and scheduled maintenance periods
to determine when "A", "B" or "C" level maintenance procedures are due.
The replacement of a vehicle is considered based on the following criteria:
Aerial devices are considered for replacement based on age and condition of
the boom and chassis (particularly with respect to fiberglass strength and
metal fatigue). These vehicles are usually replaced at the 12-14 year
point.
Other large vehicles (e.g. step vans, stakebody trucks, etc.) are
considered for replacement based on condition of chassis and body. These
vehicles are usually replaced at the 12-14 year point.
Small vehicles (e.g. panel vans, pickups, etc.) are considered for
replacement based on condition of body and engine maintenance needs and are
typically replaced at a point above 130,000 miles.
FUEL MANAGEMENT PROGRAMS
PetroVend fuel management systems and VeederRoot leak detection systems are
installed at all EUA gasoline fueling stations.
<PAGE>
DDRL (12/17/98) 54
3
54. Cont'd
CRITERIA FOR ASSIGNING VEHICLES TO NON-PHYSICAL WORKERS
Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis
to firstline supervisors who are in the field most of the workday, who must be
visible to customers and within the communities, and who have on-call and
emergency responsibilities.
Vehicles with two-way radios and cellular phones are assigned on a 24-hour basis
to certain management personnel in Operations due to their emergency
responsibilities.
Vehicles are provided to certain executives as part of their compensation
package.
Other non-physical workers, such as engineers and distribution service
coordinators, have access to company vehicles during the workday.
<PAGE>
NEES Supply Chain in $000
Overall Purchases
1997 T&D purchase order spending 217,528
incl supplies, materials, services
1998 estimate 211,979
1997 po and non-po spending
Cable 16,047
Transformers 13,908
Wood poles 3,288
Meters and accessories (po only) 3,585
Contractor Services
1997 veg. mgt 17,609
Inventory
8/98 RBU inventory 14,211
9/98 distribution transformers 14,123
12/97 meters 2,762
Vehicles
Passenger 35
Trucks 1504 (incl. 318 aerial)
<PAGE>
<TABLE>
<CAPTION>
Exhibit DJH-2
Facilities
FACILITIES
in $000
Prelim DDRL #33
BOSTON W. BRIDGEWATER
<S> <C> <C> <C>
Miscellaneous 413 Note: WB excludes internal labor
M&S, Stores 170 of $1.1 million
Outside Svcs 111
IS 9
Rents 346 34
Contract Services 6 467
Overheads 31
Sub-total 383 1,204 1,587
Ownership cost for WB 2,470
(levelized)
Total 4,057
Escalate to 2000 1.03
- ---------------------------------------------------------------------------
Total savings in 2000 4,179
- ---------------------------------------------------------------------------
BOSTON lease exp 1999; assume no change in cost per sq ft
WEST BRIDGEWATER WESTBOROUGH room for 300-350
Levelized cost 2,470 additional people
60,000 sq. ft.
structures and improvements 18,860
life 40 year
carrying cost 10.50% Annual Westborough cost incl.lease ($3.6)
property tax 2.50% $5 million
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PDDRL 12/17/98
33. List of all facilities owned or leased, including the following:
(a) Address:
(b) Occupied space in square feet; space available for expansion;
(c) Description of the lease, including monthly cost, terms, and a description of assignability or change of control provisions;
(d) Number of employees using the facility, including detail as to department/function.
(e) If wned, estimate of the current market value;
(f) Whether or not the facility is known to have experienced any instances of oil or hazardous material releases which would
subject the facility to response actions under the Massachusetts or Rhode Island waste site cleanup regulations. If such releases
have occurred, provide a summary of the status of the remedial response, any future costs expected to be incurred in addressing
the release(s)and the duration of the response action(s).
(g) Provide a statement of the presence and condition of asbestos, lead or other hazardous substances that may be present in the
facility and, if present, the plan and costs for maintaining or removing the substances
Note 1 Note 3
Company (a) (b) (c) (d) (e) (f) (g)
===========================================================================================================================
<S> <C> <C> <C> <C> <C> <C>
Eastern Edison 161 Mulberry St. $23,000 N/A 102 $750,000 None None
Brockton Mass
82 Hartwell St $20,250 N/A 67 $550,000 None None
60 Hartwell St. $18,500 $250,000 Note 5
River St. $11,200 $215,000 Note 6
Fall River Mass
10 Phillips Lane $14,400 N/A 21 $1,500,000 None None
Hanover Mass
Blackstone Valley 642 Washington Highway $60,000 N/A 94 $2,000,000 Note None
Electric Lincoln, Rhode Island 4
Newport Electric 12 Turner Road Note 7 $35,000 N/A 49 $1,500,000 None None
Middletown, Rhode Island
EUA Service EUA Corporate Offices $12,800 Note 2 20 N/A None None
Corporation One Liberty Square
Boston, Mass
EUA System Operating $133,000 N/A 542 $20,000,000 None None
Center
750 West Center Street
West Bridgewater Mass
Note 1: Available for expansion: Lincoln 12000 sq. Ft., Fall River 8500 sq. ft.
Note 2: Boston Office lease and overheads are $382,450 and expires 1999
Note 3: Detail of employees by company, department/function is attached.
Note 4: See second page attachment
Note 5: Lead Paint
Note 6: Asbestos in boiler room
Note 7: Leased space to Bank of Newport - $140,000 annual net income.
</TABLE>
<PAGE>
PDRL OF 12/17/98
33. List of all facilities, owned or leased, indicating the following:
a) address;
b) occupied space in square feet; space available for expansion;
c) description of the lease, including monthly cost, terms, and a
description of assighnability or change of control provisions;
d) number of employees using the facility; including detail as to
department/function;
e) if owned, estimate of current market value;
f) whether or not the facility is known to have experienced any instances
of oil or hazardous material releases which would subject the facility
to response actions under the Massachusetts or Rhode Island waste site
cleanup regulations. If such releases have occurred, provide a summary
of the status of the remedial response, any future costs expected to
be incurred in addressing the release(s) and the duration of the
response actions(s)
g) provide a statement of the presence and condition of asbestos, lead or
other hazardous substances that may be present in the facility and, if
present, the plan and costs for maintaining or removing the
substances.
Note 4: Blackstone Valley Electric experienced a release of gasoline in
1989 from an underground storage tank at its Lincoln Operations
facility. The release was detected during an annual tightness testing,
and was estimated at approximately 100 gallons. Soil and groundwater
were impacted. A removal action was performed in 1989, and a
groundwater treatment system has been in operation since that time.
The zone of contamination has been reduced to a small area and levels
of contamination greatly reduced. BVE expects to resolve this matter
in 1999 and complete this response action with little additional
expense. The costs to complete are not expected to be material.
<PAGE>
<TABLE>
<CAPTION>
PDDRL 12/17/98
Facility Expense
33d cont.
Company EUA Service Corporation Eastern Edison Blackstone Valley Newport
Location Boston W. Bridgewater Brockton Fall River Lincoln Middletown
<S> <C> <C> <C> <C> <C>
Miscellaneous 413,400
Payroll 1,051,400 90,900 94,300 92,200 84,800
Employee Expense 10,800 500 500 500 500
Education & Training 5,300 500 500 500 500
Materials & Supplies 151,500 19,000 44,500 23,600 12,000
Stores 18,800 10,000 8,900 11,000 9,000
Outside Services 111,000
Information Systems - Hardware 9,400
Rents 345,600 33,500 25,500 500 26,400 8,500
Contract Services 5,850 467,400 104,500 69,900 128,600 59,100
Office Overheads 31,000 33,000 22,000 90,000 28,000
Totals $382,450 $2,272,500 $283,900 $241,100 $372,800 $202,400
System Total $3,755,150
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
33d
Meter OH Property
Company Address Union Reading Lines Trouble Meter Garage Stores Maint.
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Eastern Edison 161 Mulberry St. None X X X X X X X
Brockton Mass.
82 Hartwell St. IBEW X X X X X X X
Fall River Mass.
10 Phillips Lane None X X X
Hanover Mass.
Blackstone Valley 642 Washington Highway None X X X X X X X
Electric Lincoln, Rhode Island
Newport Electric 12 Turner Road BUW X X X X X X X
Middletown, Rhode Island
</TABLE>
<TABLE>
<CAPTION>
33d
UG Substation Radio & System Consumer
Company Address Union Lines Maint. Microwave Operations Service
<S> <C> <C> <C> <C> <C> <C> <C>
Eastern Edison 161 Mulberry St. None X X X
Brockton Mass.
82 Hartwell St. IBEW X X
Fall River Mass.
10 Phillips Lane None
Hanover Mass.
Blackstone Valley 642 Washington Highway None X X X X
Electric Lincoln, Rhode Island
Newport Electric 12 Turner Road BUW X X X
Middletown, Rhode Island
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PDDRL 12/17/98
33d cont.
Company Address Union Function Performed
==================================================================================================================================
<S> <C> <C> <C>
EUA Service Corporation EUA Corporate Offices None Corporate Executive Offices
One Liberty Square Treasury
Boston Mass.
EUA System Operating Center None Executive - Admin. & Support
750 West Center Street Facilities Management
West Bridgewater Mass. Internal Audit
Consumer Services
Marketing
Information Services
Human Resources
Corporate
Communications
Corporate Benefits
Risk Management
Office Services
Safety Transmission
Services Load
Forecasting Power
Supply Special
Projects Purchasing
Material Management
Rates Accounting
Customer Service
Security Real Estate
Engineering
Transmission and
Distribution
Somerset Station None Transmission Crews
1606 Riverside Avenue
Somerset Mass.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
(ALL FROM U13-60) ACC DEPN
12/31/97 @ 12/31/97 NET
<S> <C> <C> <C> <C>
WB BUILDING 18142620 4015211 14127409
LAND & LAND RIGHTS 717080 0 717080
18859700 4015211 14844489
DEPRECIATION 452158
YEARS 40
COST % OF TOTAL TAX(B)
<S> <C> <C> <C> <C> <C>
C EUASC COMMON EQUITY 2895346 11.00% 19.50% 0.
EUASC LTD 6800000 10.20% 45.81%
9695346
A SHORT TERM 5149143 6.50% 34.69%
14844489 100.00%
A - ASSUMED REMAINING BALANCE FINANCED BY EUA SHORT TERM BORROWINGS
B - COMBINED TAX RATES (FED AND STATE) OF 40%
C - USED RETURN ON COMMON EQUITY OF RETAILS
REVENUE REQUIREMENTS
<S> <C>
DEPRECIATION (% OF UNDEPRECIATED) 3.05%
CARRYING COSTS 10.50%
COUNTY TAXES 2.50%
TOTAL 16.05%
</TABLE>
<PAGE>
Exhibit DJH-2
Administrative and
General Savings
--------------------------------------------------------------------
Mercer Management Consulting
<PAGE>
<TABLE>
<CAPTION>
A&G Overheads
in $000
This savings component reflects miscellaneous overheads, such as office supplies
and personal computers; but excludes facilities and benefits related overheads
EE BVE NE Total
<S> <C> <C> <C> <C>
FERC Acct #921 730 394 201 1,325
Office supplies and expenses
employees 881
per employee (000) 1.5
(higher for service co only)
EUA PC costs configured prices of 1.9-3.4 per unit (in 000)
Annualized cost for pc, cell phones, and pagers 640
Savings per employee 3
reduced in $000 in 2000
Savings in 2000 486
162 reductions x 3
Savings in 2001 690
225 cumulative red. X 3 x I.022
Savings in 2002 733
234 cumulative red. X 3 x 1.044
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
48 Summary of other miscellaneous A&G overheads.
See attached.
<PAGE>
<TABLE>
<CAPTION>
Summary - Other Miscellaneous and A&G
Company 1997
- ------- ----
<S> <C>
Blackstone Valley Electric Company $344,714.00
Eastern Edison Company $632,170.00
Newport Electric Corporation $238,947.00
Total $1,215,831.00
=============
Blackstone Valley Electric Company
Description 1997
- ----------- ----
Industrial Association Dues $49,591.00
Other Experimental & General Research $339.00
Publishing and Distribution Information and reports
as well as other expenses of servicing Outstanding
Securities of Respondent. $37,084.00
EUA Service Corporation General and Administrative $161,923.00
R.I. Industrial Revenue Bonds Fee $8,125.00
Employee Training and Seminars $85,298.00
Citicorp Remarketing - R.I. Industrial Bonds $22,344.00
Miscellaneous $10.00
-------------
Total $344,714.00
=============
Eastern Edison Company
Description 1997
- ----------- ----
Industrial Association Dues $103,047.00
Other Experimental & General Research $701.00
Publishing and Distribution information and reports
as well as other expenses of servicing Outstanding
Securities of Respondent. $68,824.00
EUA Service Corporation General and Administrative $314,908.00
Employee Training and Seminars $138,456.00
Service Anniversary Expense $4,864.00
Miscellaneous $1,370.00
-------------
Total $632,170.00
=============
Newport Electric Corporation
Description 1997
- ----------- ----
Industrial Association Dues $24,190.00
Other Experimental & General Research $131.00
Publishing and Distribution Information and reports
as well as other expenses of servicing Outstanding
Securities of Respondent. $18,200.00
EUA Service Corporation General and Administrative $85,579.00
Employee Training and Seminars $41,155.00
Settlement Agreement $58,481.00
Remarketing Expenses $10,146.00
Miscellaneous $1,085.00
-------------
Total $236,447.00
=============
</TABLE>
<PAGE>
GP6-350 Page 1 of 2
For the Enthusiast Customize It & Buy It!
GP6-350
============================================================
Processor: Intel 350MHz Pentium II Processor w/
512K Cache
Memory: 64MB 100MHz SDRAM expandable to
256MB
Monitor: EV700 l7inch color monitor (15.9inch
viewable area)
Graphics Accelerator: Integrated nVidia 8MB
AGP Graphics Accelerator
Hard Drive: 10GB Ultra ATA hard drive added:
US$60
Floppy Drive: 3.5inch 1.44MB diskette drive
(IOMEGA Internal ZIP Drive Deleted) subtracted:
US$50
CD-ROM: 13X min./32X max. CD-ROM drive
Multimedia Package: Boston Acoustics BA635
Speakers added: US$30
Sound System: Integrated Sound Blaster AudioPCI
64D
Case: Mid Tower Case
Network Adapter: 3COM PCI 10/100 twisted pair
Ethernet
Keyboard: 104+ Keyboard
Mouse: MS IntelliMouse Mouse; Gateway mouse
pad
Additional Software: McAfee Anti Virus Software
Application Software: MS Office 97, Small
Business Edition, on CD w/Bookshelf
Operating System: Microsoft Windows 98
Service Program: Gateway Gold Service for PCs
(1 yr. Onsite)
Tape Backup Unit: TR5 IDE TBU and tape added:
US$249
============================================================
Base Price: US $1599
Configured Price: US $1888
Quantity: 1
Total Price: US $1888
============================================================
<PAGE>
============================================================
Many Gateway products are custom engineered to
Gateway specifications, which may vary from the
retail versions of the software and/or hardware in
functionality, performance or compatibility.
Prices and configurations are subject to change
without notice or obligation. The price above does
not include shipping and handling or any
applicable taxes. After your system has been
built (lead times vary), it may be shipped
via second-day shipping in the continental
U.S.
Second-day shipping within the continental U.S. is
US$95 for desktops and US$25 for portables.
Five-day shipping for Destination (R) Digital
Media Computers is US$149. All prices quoted are
in U.S. dollars.
o I would like to order this system via
the World Wide Web.
Clicking "Continue" below takes you to
our secure server. Gateway uses Secure
Sockets Layer (SSL) encryption to assure
that all information entered on the next
screen --including your credit card
number -- can only be understood by us.
After thousands of online transactions
worth millions of dollars, no Gateway
client has ever reported misappropriation
of a credit card number protected by SSL
technology. Check our article on how SSL
works and why we think it's extremely
safe to learn more.
o Please have a sales representative
contact me about this system or other Gateway
products.
Copyright (C) 1997, 1998 Gateway 2000 Inc.
All rights reserved.
Please see our ______________________. Please
send feedback to ___________________________.
<PAGE>
GP6-450 Page 1 of 2
For the Enthusiast Customize It & Buy It!
GP6-450
============================================================
Processor: Intel 450MHz Pentium II Processor w/
512K Cache
Memory: 128MB 100Mhz SDRAM expandable to
384
Monitor: VX900T 19inch color monitor (18.0 inch
viewable area) added: US$60
Graphics Accelerator: 16MB AGP Graphics
Accelerator
Hard Drive: 16.8GB 5400RPM Ultra ATA hard
drive
Floppy Drive: 3.5inch 1.44MB diskette drive &
SuperDisk LS-120 w/5 Disks added:US$60
CD-ROM: 13X min./32X max. CD-ROM drive
Multimedia Package: Boston Acoustics BA635
Speakers added: US$30
Sound System: Integrated Sound Blaster AudioPCI
64D
Fax/Modem: TelePath(R) 56K Modem added:
US$129
Case: Tower added: US$50
Network Adapter: 3COM PCI 10/100 twisted pair
Ethernet
Keyboard: 104+ Keyboard
Mouse: MS IntelliMouse Mouse; Gateway mouse
pad
Additional Software: McAfee Anti Virus Software
Application Software: MS Office 97, Professional
Edition, on CD added: US$199
Operating System: Microsoft Windows 98
Service Program: Gateway Gold Service for PCs
(lyr. Onsite)
Tape Backup Unit: TR5 IDE TBU and tape added:
US$249
============================================================
Base Price: US $2599
Configured Price: US $3376
Quantity: 1
Total Price: US $3376
============================================================
<PAGE>
Many Gateway products are custom engineered to
Gateway specifications, which may vary from the
retail versions of the software and/or hardware
in functionality, performance or compatibility.
Prices and configurations are subject to change
without notice or obligation. The price above
does not include shipping and handling or any
applicable taxes. After your system has been
built (lead times vary), it may be shipped
via second-day shipping in the continental
U.S.
Second-day shipping within the continental U.S. is
US$95 for desktops and US$25 for portables.
Five-day shipping for Destination (R) Digital
Media Computers is US$149. All prices quoted are
in U.S. dollars.
o I would like to order this system via
the World Wide Web.
Clicking "Continue" below takes you to
our secure server. Gateway uses Secure
Sockets Layer (SSL) encryption to assure
that all information entered on the next
screen --including your credit card
number -- can only be understood by us.
After thousands of online transactions
worth millions of dollars, no Gateway
client has ever reported misappropriation
of a credit card number protected by SSL
technology. Check our article on how SSL
works and why we think it's extremely
safe to learn more.
o Please have a sales representative
contact me about this system or other Gateway
products.
Copyright (C) 1997, 1998 Gateway 2000 Inc.
All rights reserved.
Please see our ______________________. Please send
feedback to ___________________________.
<PAGE>
Privileged and Confidential
ADDRL #34
34. Estimate of "personal tools" costs per employee, e.g. PC, pager, cellular
phone. (This information is needed to estimate merger savings.).
1. Workstation replacement program ended in 1997. There are about 50
workstations currently in use. They will be phased out through
attrition.
2. Replacement of PCs is a department head decision. Expected
replacements are identified in the O&M budget. A PC Replacement form
is used as a control document.
3. New PCs are identified in the O&M budget (unless they are related to a
capital project). A PC Acquisition form is used as a control document.
4. Average replacement costs and base-line specifications for the two
classes of recommended PCs is attached - #1.
5. Divisional breakdown of PCs is attached - #2.
6. Average life expectance for a PC is three years. However, older useful
PCs are recirculated to low-end users identified by department heads.
7. Department heads on an as needed basis distributes pagers and cell
phones.
8. Company annualized cost for PC's - $450,000; pagers and cell phones -
$90,000.
<PAGE>
1998 Inventory
Number of PCs by Department
Total Configurations as of 12/14/98: 584
Accounting 48
Bldg & Facil 11
CIS 78
Engineering 70
Executive 31
Garage 10
Gen. Office Svcs 2
HR 30
Info Services 62
Internal Audit 4
Meter 11
Meter Reading 11
Power Supply 15
Purchasing 6
Rates 23
Real Estate 5
Records 1
Retail Bus Svcs. 65
Safety & Risk Mgmt 7
SCADA 5
Special Projects 5
Stores Mgmt & Supp 14
Sub & Comm 13
System Operations 3
Telecommunications 3
Trans & Dist 32
Trans Svcs 7
<PAGE>
<TABLE>
<CAPTION>
Advertising
in $000
1997 1998 annualized
EUA NEES
<S> <C> <C> <C>
Addit. data req #47 825 Customer 4,318 dsm,choice related
Normalized 500 Image 50 FERC #
930.1
4,368
Savings 50%
Savings in 1997 250
Escalation to 2000 1.09
Savings in 2000 273
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
47 Summary of advertising costs.
See attached.
<PAGE>
<TABLE>
<CAPTION>
Advertising Costs - 1997 1997
------------------------ ----
Company Advertising Costs
------- -----------------
<S> <C> <C>
Co 01 Blackstone Valley Electric $215,091.17
Co 08 Eastern Edison Company $519,027.05
Co 14 Newport Electric Corporatio $90,729.57
------------
Total $824,847.79
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Association Dues
in $000
Addit data req # 45, 48
EUA 1997 Savings% Savings
<S> <C> <C>
EEI 136 25% 34
Other 41 100% 41
177 42% 75
Escalation to 2000 1.09
Savings in 2000 82
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
45 Summary of associations dues.
1997 Blackstone Newport Eastern Total
- ---- ---------- ------- ------- -----
<S> <C> <C> <C> <C>
Utility Air Regulatory Group 225 562 787
Electric Council of New England 6,983 2,745 13,665 23,393
EEI 38,842 17,780 78,980 135,602
Utility Water Act Group 2,847 2,788 5,752 11,387
Associated Industries of MA 720 720
NU College of Business 2,500 2,500
Administration
Miscellaneous 696 315 1,431 2,442
49,593 24,190 103,048 176,831
</TABLE>
<PAGE>
Benefits Administration
in $000
Expect no savings in HMO ( self insured) and group life
Minimal savings in retirement and thrift plan administration
Per conversation with NEES
Savings in 2000 50
<PAGE>
12/19/98
ADDITIONAL DUE DILIGENCE (List
#3)
REQUEST LIST
PRIVILEGED AND CONFIDENTIAL
ATTORNEY-CLIENT COMMUNICATION
ATTORNEY WORK PRODUCT
ADDRL #
46 Cost to administer benefits.
<PAGE>
<TABLE>
<CAPTION>
EASTERN UTILITIES ASSOCIATES
Responsibility Center 220 - Corporate Benefits
O&M Budget 1999
"ADDRL"12/19/98
Question #46
OTHER EXPENSES: O&M EUASC
<S> <C> <C>
XX Payroll 01 $220,000
20 Miscellaneous (NEEBC Dues) 00 $400
20 Retiree Organizations Support (700 rets @ $10.00) 00 $7,000
01 Employee Expense 05 $1,800
XX Ed. & Training 06 $3,500
20 Materials & Supplies 07 $2,000
07 Materials & Supplies - WSJ,CCH 07 $1,600
XX General Consulting - Pension & ESP* 11 $36,000*
20 Financial Education/ Retirement Planning Program 11 $23,500
20 FSA Admin. Fees-Estimated FICA tax offset is $10,000 11 $9,000
20 Executive Annual Physicals 11 $16,800
20 Split $ Consulting Fee - Vinings Management 11 $16,900
25 Cyborg Maintenance Contract 22 $12,500
Total Other Expenses: $351,000
========
* not payable from the pension trusts.
</TABLE>
<TABLE>
<CAPTION>
<PAGE>
TOTAL
BVE EECO NEWPORT EUASC TOTAL EUASC
<S> <C> <C> <C> <C> <C> <C>
Group Health 452,022 978,362 211,337 171,001 1,812,722 204,034
Dental Insurance 49,016 105,728 33,918 3,130,326 3,318,988 3,735,027
Group Life 7,154 65,696 35,153 570,642 678,645 680,876
Pension (854,720) (1,351,822) (74,320) 4,329,463 2,048,601 5,165,807
Post Retirement Benefits 1,319,782 2,284,618 588,458 356,773 4,549,631 425,693
Employee Thrift Plan 113,012 218,567 94,990 0 426,569
1,086,266 2,301,149 889,536 8,558,205 12,835,156 10,211,437
----------
12,835,156
BVE 2,367,906 0.276698653 0.2319
EECO 4,621,878 0.540083693 0.4526
NWPT 1,231,339 0.143886557 0.1206
MECO TRANS 336,584 0.039331097 0.033
8,557,707 1 0.8381
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Corporate Governance
Shareholder Services
in $000
ADDRL #43
EUA 1999 budget Million Million
Shares Price Mkt Cap
<S> <C> <C> <C> <C> <C>
Annual rpt 112 NEES 59.8 48.06 2,874
Transfer agent 87 EUA 20.4 27.81 567
NYSE 33 EUA equiv 11.8
Other 61 % increase 11.8/59.8
293 20%
Savings 80%
Savings in 1999 234
Savings in 2000 241
Trustees
ADDRL #40
1999 1998
EUA NEES
<S> <C> <C>
Outside directors 9 11
Fees 550
Other expenses 100
Total 530 650
Savings in 1999 530
Escalate to 2000 1.03
Savings in 2000 546
Total Corp Governance 787
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
43 Summary of shareholder services expenses, including the production of
the annual report, the annual meeting, mailings and other fees.
Budget for 1999
Annual Report Production 112,000
Mailing of AR and Proxy, etc. 28,000
10K printing 5,700
Proxy printing 7,000
Transfer agent fees 87,000
NYSE listing fee 33,000
Quarterly dividend enclosure 11,000
Postage and miscellaneous 9,700
---------
293,400
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE (List # 3) ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
40 Directors' fees and related expenses.
See attached summary of EUA Parent 1999 Budget for details of
information requested.
<PAGE>
<TABLE>
<CAPTION>
EUA PARENT
1999 BUDGET
1999
JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC TOTAL
--- --- --- --- --- --- --- --- --- --- --- --- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
9200 DO AMORT RESTR STK PLAN 500 500 500 500 500 500 500 500 500 500 500 500 6,000
9302 07 MISCELLANEOUS
FIDUCIARY/DIRECTORS LIB INS 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800
TOTAL 9302 07 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,733 7,737 92,800
9302 09 CORP & FISCAL
MISCELLANEOUS 200 200
9302 06 DIRECTORS FEES
ANNUAL TRUSTEE FEE 36,000 36,000 36,000 36,000 144,000
REGULARLY SCHEDULED MTGS
FULL BOARD 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 7,650 84,190
FINANCE COMM 4,250 4,250 4,250 4,250 17,000
AUDIT COMM 4,250 4,250 4,250 12,750
PENSION TRUST COMM 3,400 3,400 3,400 3,400 3,400 3,400 20,400
COMPENSATION 3,400 3,400 3,400 10,200
RETIREMENT BENEFIT 36,130 12,130 12,130 38,130 12,130 12,130 36,130 12,130 12,130 36,130 12,130 12,130 241,560
TOTAL 9302 05 84,030 26,580 24,030 87,430 19,780 27,430 84,030 15,530 27,430 90,830 19,780 23,220 530,100
TOTAL DO 92,263 34,813 32,263 95,853 28,013 35,883 92,263 23,763 35,663 99,063 28,013 31,457 629,100
9230 10 OUTSIDE LEGAL 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700
TOTAL 09 28,300 27,100 14,500 33,400 24,000 7,600 7,000 7,900 9,800 12,900 5,000 6,200 183,700
9210 02 OFFICE SUPPLIES & EXP
BANK CHARGES 400 400 400 400 400 400 400 400 400 400 400 400 4,800
9230 20 OUTSIDE ACCOUNTING
C&L AUDIT FEE 4,700 2,800 1,030 1,700 10,000
9302 10 TRANSFER AGENT FEES
COMON STOCK EXPENSE 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 1,000 1,000 2,500 18,000
TOTAL 11 1,400 5,100 5,500 1,400 1,400 2,900 1,400 1,400 2,900 2,400 1,400 4,600 32,800
TOTAL 000 121,963 58,013 52,283 130,483 53,413 46,363 100,563 33,063 40,363 114,383 34,413 42,257 845,600
</TABLE>
<PAGE>
YAHOO! FINANCE Home - Yahoo! - Help Market
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<TABLE>
<CAPTION>
New England Electric Sys. NYSE : NES
<S> <C>
Financial Links
Address: 25 Research Drive o Company News
Westborough, MA 01582 o Research Report: Basic / Detailed
Phone: (508) 389-2000 o Upgrade/Downgrade History
Fax: (508) 836-0276 o Free Annual Report
Industry: Electric Utilities o Latest Stock Price
Sector: Utilities o Insider Trades
Employees: 4,665 o SEC Filings (raw filings)
Officers: Richard P. Sergel, Pres./CEO o Message Board
Joan T. Bok, Chmn.
Cheryl A. Lafleur, Sr. VP/Secy./Counsel
Michael E. Jesanis, Sr. VP/CFO Company's Web Presence
John G. Cochrane, Treas./CAO. o Home Page
o Search Yahoo! for related links...
</TABLE>
Business Summary
NES is a public utility holding company, whose subsidiaries are engaged in the
transmission, distribution, sale and generation of electricity. For the nine
months ended 9/30/98, revenues fell 1% to $1.82 billion. Net income applicable
to Common fell 3% to $157.5 million. Revenues reflect decreases in
generation-related, fuel cost-related, and oil and gas-related revenues.
Earnings also reflect monthly contractual payments to USGen and increased
transmission wheeling costs.
<TABLE>
<CAPTION>
More from Market Guide: Highlights - Performance
Statistics at a Glance - NES Last Updated: Dec 23, 1998
<S> <C> <C> <C> <C> <C>
Price and Volume Per-Share Data Management Effectiveness
(updated Dec 23, 1998) Book Value (mrq) $26.79 Return on Assets (ttm) 4.34%
52-Week Low $38.938 Earnings (ttm) $3.39 Return on Equity (ttm) 12.66%
Recent Price $48.063 Sales (ttm) $38.91 Financial Strength
52-Week High $49.125 Cash (mrq) $8.26 Current Ratio (mrq) 1.23
Beta 0.32 Valuation Ratios Long-Term Debt/Equity (mrq) 0.63
Daily Volume (3- 148.9K Price/Book (mrq) 1.79 Total Cash (mrq) $494.3M
month avg)
Share-Related Items Price/Earnings (ttm) 14.19 Short Interest
Market Capitalization $2.88B Price/Sales (ttm) 1.24 Shares Short 23
as of Dec 8, 1998
<PAGE>
Shares Outstanding 59.8M Income Statements
Float 54.5M After-Tax Income (ttm) $231.8M Short Ratio 5.81
Dividend Information Sales (ttm) $2.48B Stock Performance
Annual Dividend $2.36 Profitability NES 24-Dec-1998 (C) Yahoo!
(indicated) Profit Margin (ttm) 9.3% _____________________________________
50|| |
45|| |
40 | |
35 | |
------------------------------------|
Jan Mar May Jul Sep Nov
big chart [ld | 5d | 3mo | 1yr | 2yr | 5 yr |
max]
Dividend Yield 4.91%
See the Profile FAQ for a description of each item above; K = thousands; M = millions; B = billions;
mrq = most-recent quarter (Sep 30, 1998); ttm = trailing twelve months through Sep 30, 1998
Market Guide offers more in-depth Company Research, Stock Screening, and Hottest Stocks and Industries on over
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Copyright (C) 1998 Yahoo! Inc. All Rights Reserved.
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Company information Copyright (C) Market Guide
Historical chart data and daily updates provided by Commodity Systems, Inc. (CSI).
Data and information is provided for informational purposes only, and is not intended for trading purposes. Neither Yahoo
nor any of its data or content providers (such as Market Guide, CSI, Reuters, Zacks, etc.) shall be liable for any errors or
delays in the content, or for any actions taken in reliance thereon.
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</TABLE>
<PAGE>
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<TABLE>
<CAPTION>
Eastern Utilities Assoc. NYSE : EUA
Financial Links
<S> <C>
Address: One Liberty Square o Company News
Boston MA 02109 o Research Report: Basic / Detailed
Phone: (617) 357-9590 o Latest Stock Price
Fax: (617) 357-7320 o Insider Trades
Industry: Electric Utilities o SEC Filings (raw filings)
Sector: Utilities o Message Board
Employees: 1,180
Officers: Donald G. Pardus, Chmn./CEO
John R. Stevens, Pres./COO Company's Web Presence
Richard M. Burns, Contr./CAO o Home Page
Clifford J. Herbert, Jr., Treas./Secy.
o Search Yahoo! for related links...
</TABLE>
Business Summary
EUA is a holding company for Blackstone, Eastern Edison, and Newport, which
provide retail electric utility services in MA and RI. EUA also operates various
service subsidiaries. For the nine months ended 9/98, revenues fell 4% to $405.4
million. Net income applicable to Common fell 4% to $26.2 million. Results
suffered from a decrease in core electric business revenues due to customer rate
reductions and the termination of the power marketing joint venture.
More from Market Guide: Highlights - Performance
<TABLE>
<CAPTION>
Statistics at a Glance - EUA Last Updated: Dec 23, 1998
Price and Volume Per-Share Data Management Effectiveness
(updated Dec 23, 1998) Book Value (mrq) $18.27 Return on Assets (ttm) 3.05%
<S> <C> <C> <C>
52-Week Low $23.563 Earnings (ttm) $1.80 Return on Equity (ttm) 9.85%
Recent Price $27.813 Sales (ttm) $26.98 Financial Strength
52-Week High $28.00 Cash (mrq) $0.33 Current Ratio (mrq) 0.71
Beta 0.50 Valuation Ratios Long-Term Debt/Equity (mrq) 0.77
Daily Volume (3- 73.9K Price/Book (mrq) 1.52 Total Cash (mrq) $6.64M
month avg) Price/Earnings (ttm) 15.45 Short Interest
Share-Related Items Price/Sales (ttm) 1.03 Shares Short
as of Dec 8, 1998 137.9
Market Capitalization $568.4M
Shares Outstanding 20.4M Income Statements Short Ratio
Float 20.2M After-Tax Income (ttm) $39.1M
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Financing Costs and Fees
in $000
Includes savings associated with lines of credit
Lines of Credit
1998 est
NEES x NEP EUA
<S> <C> <C>
Commitment fees 567 256
Lines of credit 637,000 165,000
% fee 0.089% 0.155%
Savings 100%
Savings in 1998 256
Escalation to 2000 1.06
Savings in 2000 272
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE (List #3) ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
41 Summary of any lines of credit.
See attached summary of EUA System lines of credit.
<PAGE>
<TABLE>
<CAPTION>
EUA SYSTEM
Short-Term Credit Facility Fees (1)
For 1998/1999
LINE FACILITY ANNUAL
BANK OF CREDIT FEE FEE EUA BVE EECO
<S> <C> <C> <C> <C> <C> <C>
REVOLVING CREDIT FACILITY:
BANK OF NEW YORK $100,000,000 $20,000,000 $75,000,000
(Availability: All Companies) 29% 6% 21%
$75,000,000 0.1250% $93,750 $26,786 $5,357 $20,089
OTHER CREDIT FACILITIES: $20,000,000 $75,000,000
BANK OF NEW YORK 16% 60%
(Availability: BVE,EECO, MECO) $10,000,000 0.1250% $12,500 $2,000 $7,500
STATE STREET BANK $100,000,000 $75,000,000
(Availability: EUA, EECO) 57% 43%
$15,000,000 0.2500% $37,500 $21,429 $16,071
UNION BANK OF CALIFORNIA (2) $100,000,000 $20,000,000 $75,000,000
(Availability: EUA, BVE, EECO, MECO, NECO) 8% 30%
$20,000,000 0.1875%(2) $0 40% $0 $0
$0
(Availability: EECO) $45,000,000 0.2500% $112,500 100%
ANNUAL FACILITY FEE TOTALS $165,000,000 $256,250 $48,214 $7,357 $156,161
MONTHLY ACCRUAL $4,018 $613 $13,013
BANK MECO COGENEX EUA OS SERVICE NECO TOTAL
REVOLVING CREDIT FACILITY: $30,000,000 $75,000,000 $10,000,000 $15,000,000 $25,000,000 $350,000,000
BANK OF NEW YORK 9% 21% 3% 4% 7% 100%
(Availability: All Companies) $8,036 $20,089 $2,679 $4,018 $6,696 $93,750
OTHER CREDIT FACILITIES: $30,000,000 $125,000,000
BANK OF NEW YORK 24% 100%
(Availability: BVE,EECO, MECO) $3,000 $12,500
STATE STREET BANK $175,000,000
(Availability: EUA, EECO) 100%
$37,500
$30,000,000 $25,000,000 $250,000,000
UNION BANK OF CALIFORNIA (2) 12% 10% 100%
(Availability: EUA, BVE, EECO, MECO, NECO) $0 $0 $0
$25,000,000 $75,000,000
10% 100%
(Availability: EECO) $0 $112,500
ANNUAL FACILITY FEE TOTALS $11,036 $20,089 $2,679 $4,018 $6,696 $256,250
$920 $1,674 $223 $335 $558 $21,354
MONTHLY ACCRUAL
(1) Allocation Percentages Based on March 20, 1998 SEC Order Authorizing Company Short-Term Borrowing Limitations.
(2) Facility Fee based on .1875% of the average daily unused amount of the Facility during such period. For allocation of Fee,
assumption will be credit line will be fully drawn, hence, zero fee.
September 22, 1998
JWH/d:/1231997/comfee/feebad98
</TABLE>
<PAGE>
Insurance Premiums
in $000
Data Response #102
Major Coverages 1999 EUA % Savings Savings
excl MTP
Property 90 5% 5
Property 68 5% 3
Boiler 95 5% 5
Marine Cable
Liability
General 285 50% 143
Excess 343 50% 172
Auto 94 50% 47
Pollution 191 25% 48
D&O adjusted 100 75% 75
Brokerage Fees 175 75% 131
(per phone conversation)
Total 1,441 44% 628
Escalate to 2000 1.03
Savings in 2000 646
<PAGE>
<TABLE>
<CAPTION>
INSURANCE COSTS - 1999
TYPE EECO NPT EUA BVE MTP EUA
TOTAL
<S> <C> <C> <C> <C> <C> <C>
PROPERTY 27000 21300 8200 33500 110000 200000
BOILER 13500 17800 4500 32400 141800 210000
OFFICE CONTENTS 1100 1100
EDP 10000 10000
CONT EQUIP 3178 2794 1377 2651 10000
MICROWAVE 2191 716 4336 1473 1284 10000
VALUABLE PAPERS 133 133 134 400
MARINE CABLE 95000 95000
TRANSIT 722 542 586 550 2400
CRIME 2230 590 6230 1100 850 11000
GENERAL LIABILITY 120000 45000 15000 105000 15000 300000
AUTOMOBILE 42000 14000 17500 21000 5500 100000
AUTO PHYSICAL 8350 2750 3650 4200 1050 20000
WORKERS COMP 55500 15000 19500 30000 30000 150000
D&O 15000 15000 15000 15000 122000 182000
PENSION 2493 662 7046 1195 954 12350
POLLUTION 91000 31500 15000 54000 63500 25500
UNDERGROUND TANKS 1300 2550 2050 2550 2550 11000
EXCESS LIABILITY 130500 42500 100000 70000 37000 380000
LETTER OF CREDIT 25000 25000
MONTAUP EXTRA EXP 140000 140000
BOND PREMIUM 15000 15000
SMALL CLAIM EXPENSE 247500 88000 27500 126500 60500 550000
$762,597 $392,910 $299,539 $499,881 $735,323 $2,690,250
</TABLE>
<PAGE>
DDRL #102
Question: List all liability, property, casualty, and other insurance policies
held by the Company or its subsidiaries, or if self insured, the extent of self
insurance, including limits of coverage, policy dates, premiums, insurance
brokers, and cash surrender value, if any.
Answer: The person in the organization responsible for risk management is not
involved in the data request process. At this point in the process the
information we will provide will be very limited.
Attached you will find the planned 1999 expenses by category. Once the sale of
Montaup is complete, the insurance expenses will be prorated for the remainder
of the policy year.
DDRL #103
Question: Describe all claims made by the Company or its subsidiaries under the
insurance policies carried by the Company or its subsidiaries over the past two
years in which the amount claimed exceeded $1,000,000.
Answer: To the best of my knowledge, none.
DDRL 104
Question: List and describe any pending litigation relating to insurance
coverage.
Answer: To the best of my knowledge there are two cases.
1. The family of a deceased woman in Fall River has filed a claim
against the Company. The woman died as a result of a pedestrian
truck accident involving an EUA driver in a meter van. The driver
was not found to be negligent. Maximum exposure to the Company is
$350,000.
2. A civilian has placed a claim with the Company as a result of a
manhole explosion. The civilian received burns over 30% of his
body. He has nearly fully recovered and is looking for medical
expense recovery. We expect to settle for a reasonable amount.
The maximum exposure is $350,000.
In both cases the insurance will cover anything over the $350,000. Neither case
is expected to exceed the $350,000 deductible.
DDRL #105
Question: Copies of all material correspondence with insurers or insurance
brokers or agents relating to environmental impairment liability claims.
Answer: Did not have access to the information
<PAGE>
<TABLE>
<CAPTION>
Professional Services
in $000
1997
BE EE NE Service Total
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Addit. data req #38 1,610 7,964 446 1,956 11,976
incl. ops-related Savings % Savings
Accounting 34 63 31 69 197 50% 99
Legal incl dereg
McDermott 33 1,209 17 360
Isaacson 744
Other 2 73 46 83
Total 779 1,282 63 443 2,567
adj. 1,500 33% 495
Employment 118 118 33% 39
Consulting 40 40 100% 40
Invest. Svcs 108 108 100% 108
Legislative 48 48 100% 48
Prof Svcs Total 2,011 41% 828
Escalation to 2000 1.093
Savings in 2000 905
Engineering 39 1 40
Environmental 20 12 32
Conservation 27 2,548 141 - 2,716
Facilities/Cleaning 40 162 202 incl in facilities calculation
Security 125 125 incl in facilities calculation
Misc Other 314 421 735
Tree Trimming 687 1,334 187 352 2,560
Misc Contract Svcs 1,606.0 1,606
8,016
10,027
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
38 List of professional services purchased by major area, e.g.
a) Audits and accounting
b) Legal
c) Information systems
See attached.
<PAGE>
<TABLE>
<CAPTION>
BLACKSTONE VALLEY ELECTRIC
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C>
Asplundh Tree Trimming 56,222
Barnes Tree Services Tree Trimming 140,399
Blackstone Valley Security Security Services 0
Clean Harbor Environmental 19,603
Coopers & Lybrand Accounting 34,145
Credit Bureau Collection Fees 20,959
Dickstein, Shapiro & Moris Legal
Financial Collection Collection Fees 1,149
Isaacson, Rosenbaum Legal 743,568
McDermott, Will & Emery Legal 32,578
Northern Tree Service Tree Trimming 491,290
Ocean State Janitorial Cleaning 40,408
Osmose Wood Press Pole Treatment/Inspection 448
Stanley Bleeker, Esq. Legal 0
Tillinghast, Collins & Graham Legal 1,911
(A) Coflax Packing Conservation 1,214
(A) Delta Electric Motor Conservation 639
(A) RISE Conservation 7,690
(A) Slater Dye Works Conservation 17,313
---------------------
1,809,534
=====================
(A) These vendors participated in Eastern Edison's conservation, load,
management programs, management programs.
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 16.
Prepared by Michelle Uzzo 12/22/98
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EASTERN EDISON COMPANY
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C> <C>
American Staffing Assoc. Employment 118,240
Asplundh Tree Trimming 919,253
Barnes Tree Service Tree Trimming 140,782
Clean Harbors Environmental
Coopers and Lybrand Accounting 62,883
Duff & Phelps Consulting 40,000
Environmental Protection Service Maintenance 44,555
First Financial Resources Collection Fees 33,933
First Security Services Security
Hanson Police Dept. Police Detail 31,478
J. D. Payroll Services Temp Services
MASS Save Consulting 342,286
McDermott, Will & Emery Legal 1,209,446
Misc. Contract Services* 1,605,966
Misc. Engineering* 38,605
Misc. Legal* 12,155
Miscellaneous* 314,463
Osmose Wood Press Pole Treatment/Inspection
Pembroke Police Dept. Police Detail
R.A. Gill Tree Service Tree Trimming 227,341
R.E. Tilgren Tree Trimming 46,695
Reed, Adami, Kaiser Legal 72,589
Rockland Police Dept. Police Detail 26,218
Service Master Maintenance 29,796
State Street Bank & Trust Trustee/Administrative Fee
Suburban Contract Cleaning
Town of Bridgewater Police Detail
Town of Easton Police Detail 56,526
Town of Norwell Police Detail 42,745
Town of Scituate Police Detail
Town of Stoughton Police Detail
(A) Conservation Services Group Conservation 361,903
(A) Demand Mgmt Conservation
(A) Energie Innovation Inc. Conservation 84,095
(A) Energy Conservation Conservation 123,124
(A) Energy Federation Conservation 306,904
(A) Fall Realty & Harris Energy Conservation 38,353
(A) Fleet Bank Conservation 28,182
(A) Harris Energy Systems Conservation 489,801
(A) J&R Industrial Wiring Conservation 206,124
(A) Main Street Textiles Conservation 133,990
(A) MUPAC Corp & Harris Energy Conservation 26,114
(A) National Resource Mgmt. Conservation 375,923
(A) Relocation Resources, Inc. Conservation 61,985
(A) Shews Supermarkets Inc. Conservation 168,265
(A) Star Market & Harris Energy Conservation 31,080
(A) Stop & Shop Supermarket Co. Conservation 49,799
(A) Ware Rite & Harris Energy Conservation 32,759
(A) Whaling Mfg. Co., Inc. Conservation 29,235
-------------------
7,963,604
===================
* Aggregate amounts to any one entity less than $25,000 have been
accumulated in this description.
(A) These vendors participated in Eastern Edison's conservation, load,
management programs, management programs.
NOTE: The source for this information was found on o&m codes 9, 10, 11 & 12.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
NEWPORT ELECTRIC CORPORATION
PROFESSIONAL SERVICES
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C>
Barnes Tree Services Tree Trimming 187,208
Clean Harbor Environmental 11,989
Coopers & Lybrand Accounting 30,982
Credit Info Collection Fees 12,118
McDermott, Will & Emery Legal 16,808
Morgan, Brown & Joy Legal 340
RISE Conservation 141,057
Tillinghast, Collins & Graham Legal 45,587
-----------------
446,062
=================
NOTE: The source for this information was based on o&m codes 9, 10, 11 & 19.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EUA SERVICE CORP.
PROFESSIONAL SERVICES
(Account # 923)
VENDOR NAME DESCRIPTION OF SERVICE 1997
----------- ---------------------- ----
<S> <C> <C>
McDermott, Will & Emery Legal 359,773
First Security Services Security 124,975
Contract Cleaning Collaborative Cleaning
Eastern Edison Company Arborist/Technical Trainers 351,846
Salomon Brothers Inc. Investment Services 107,986
Media Concepts Printing Services 114,897
Norfolk Data Data Processing Time Cards
Cambridge Reports, Inc. Customer Services 70,560
J. Flanagan & Co. Legislative Activity 48,000
DRI McGraw-Hill
Newport Electric Corp. Arborist/Technical Trainers
Twenty First Century
AUC Management Consultants Consulting
Misc. Legal * 82,677
Misc. Accounting * 68,988
Misc. EDP * 41,871
Misc. Building & Maintenance* 162,203
Other * 421,494
Misc. Engineering * 768
-----------------
1,956,038
=================
* Payments made to payee is less than $100,000
Amounts in Bold print are estimates based on the average of 1996 & 1997.
Prepared by Michelle Uzzo 12/22/98 a:\profsvs
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
REGULATORY EXPENSES
in $000
1997 1997
EUA NEES
<S> <C> <C> <C>
Addit. data req #42 1,002 FERC acct #928 4,008
Assessments 739
Filings and misc. 263
Total 1,002
Savings on filings and misc. 20%
Savings in 1997 53
Escalation to 2000 1.09
Savings in 2000 57
</TABLE>
<PAGE>
12/19/98 PRIVILEGED AND CONFIDENTIAL
ADDITIONAL DUE DILIGENCE ATTORNEY-CLIENT COMMUNICATION
REQUEST LIST ATTORNEY WORK PRODUCT
ADDRL #
42 Summary of regulatory expenses.
1997 Newport Blackstone Eastern Total
---- ------- ---------- ------- -----
PUC Assessment 119,983 267,118 387,101
DTE Assessment 351,663 351,663
Tariff Filings & Misc. 57,258 144,113 61,899 263,270
------- ------- ------ -------
177,241 411,231 413,562 1,002,034
<PAGE>
<TABLE>
<CAPTION>
Cost to Achieve
in $000
Total Basis for Cost Estimate
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Transaction Costs
Bankers fees 7,500 Estimate from NEES and EUA
Legal fees 3,500 Estimate for NEES and EUA
D&O liability tail coverage 400 1.5 times EUA's current annual D&O liability premium
Total Transaction Costs 11,400
- ----------------------------------------------------------------------------------------------------------------------------------
Personnel Costs
Separation/Retention 35,150
Relocation 2,750 Cost equals 90 employees required to relocate @ $25,000 per employee; also
includes $500,000 miscellaneous
Retraining 1,950 Cost includes:
Customer service training: 100 employees x 4 weeks @ $1,000 per week ($400,000)
Meter reader training: 50 employees x 1 week @ $1,000 per week ((50,000)
Transmission and distribution training: 200 employees x 3 weeks @ $1,500 per
week ($900,000)
Administrative functions training: 100 employees x 4 weeks @ $1,500 per week
($600,000)
General reorientation 250 Cost to train 500 employees x 2 days @ $250 per day ($250,000)
Total Personnel Costs 40,100
- ----------------------------------------------------------------------------------------------------------------------------------
Transition Costs
Internal Support 810 Cost equals 15 employees x 9 months @ $6,000 per month ($810,000)
No cost shown 35 employees working on transition in addition to regular workload
Outside Support 2,000 Cost for organizational and change management consultants and other outside
support
Communications 500 Costs for both internal and external communication
Facilities Consolidation 1,000 Estimate based on other transactions
Other 250 Cost of changing corporate signage, stationary, etc.
Total Transition Costs 4,560
- ----------------------------------------------------------------------------------------------------------------------------------
Information Systems
Systems Integration and Data 6,600 Cost of application integration and data conversion; cost to close one data
center
Center Consolidation
Meter Reading Hardware 600 Cost to outfit EUA meter readers with 55 new ITRON devices
Telecommunications Costs 350 Cost to connect telecommunications networks; reconfigure and reprogram customer
service center switch
Total Information Systems Costs 7,550
- ----------------------------------------------------------------------------------------------------------------------------------
Total Cost to Achieve 63,610
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D&O Tail Coverage
Conversation with Diane Kenney
Coverage Premiums
EUA in Millions in Thousands
<S> <C> <C>
Policy #1 25 232
Policy #2 10 47
35 279
Budget for tail coverage 150%
419
Cost to achieve 400
</TABLE>
<PAGE>
Hoffman, David
- ------------------------------------------------------------------------------
From: Michael J. Hirsh [[email protected]]
Sent: Monday, April 12,1999 5:49 PM
To: david-hoff man@ mercermc.corn
Subject: EUA-side transaction costs
David-
Following up on our conversation today, our transaction costs include the
following:
Banker fees$4.2 million (per contract)
Legal $1.6 million actual + est.
($.535 billed through Feb, assume $.3 added through April
and $.1/mo
Thanks.
MJH
<PAGE>
<TABLE>
Exhibit DJH-2
Miscellaneous
MODEL INPUTS
- --------------------------------------
Escalation rate 3%
- --------------------------------------
- --------------------------------------
% labor capitalized
A&G 0%
Customer 0%
T&D 35%
- --------------------------------------
- --------------------------------------
Benefits adder 32.63%
for EUA
- --------------------------------------
<S> <C> <C> <C> <C> <C>
EUA (EE)
% cap % b-t cost % a-t cost wacc
- ---------------------------
Revenue equirement ltd 45.5% 7.6% 7.6% 3.5%
Rate ps 5.5% 9.8% 16.3% 0.9%
cse 49.0% 11.5% 19.2% 9.4%
Non-IS(30 yr) 13.5% 13.7%
IS (5 yr) 28.6%
- ---------------------------
NEES(MECo)
% cap % b-t cost % a-t cost wacc
ltd 44.0% 7.5% 7.5% 3.3%
- ---------------------------
Fixed Charge Rate ps 5.9% 6.3% 10.5% 0.6%
on EUA inventory 13.7% cse 50.1% 11.0% 18.3% 9.2%
- ---------------------------
13.1%
Depreciation on distribution plant x land
depr ave plant % yrs
MECo 47,760 1,466,280 3.26% 30.7
NECo 17,744 543,775 3.26% 30.6
EE 9,139 213,037 4.29% 23.3
BV 4,067 98,925 4.11% 24.3
Average 78,710 2,322,016 3.39% 29.5
NEES 2,010,055 87%
EUA 311,961 13%
2,322,016
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
ADDRL #21
N21 % of employee benefits, taxes and unproductive time, i.e.,
Vacations, holidays, sick, jury duty. (Benefits & Unproductive /
Productive Wages).
<S> <C>
Blackstone Valley 54.24%
Eastern Edison 53.64%
Newport Electric 61.91%
EUA Service Corp 52.91%
<S> <C> <C>
% of payroll charged to O&M and to Capital O&M Capital
Blackstone Valley 23.7% 76.3%
Eastern Edison 26.4% 73.6%
Newport Electric 22.5% 77.5%
EUA Service Corporation wages billed to companies
Blackstone Valley 95.3% 4.7%
Eastern Edison 92.6% 7.4%
Newport Electric 94.6% 5.4%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Capital Payroll by Function
Payroll Capital Percent
Total Payroll To Capital
<S> <C> <C> <C> <C>
Total A&G 31,138,865 1,416,698 (Note 1) 4.55%
Total Retail Svcs 11,567,105 11,327 0.10%
Customer Service
Northboro
Inquiry 6,533,923 0 0.00%
Meters 1,445,504 16,713 1.16%
Collections 460,700 0 0.00%
Cust Ld Analysis 464,638 0 0.00%
--------- ------
8,904,765 16,713 0.19%
Providence
Inquiry 3,531,849 0 0.00%
Meter Read 2,648,213 0 0.00%
Meter OPs 1,378,950 302,358 21.93%
--------- -------
7,117,580 302,358 4.25%
MValley
Inquiry 975,652 0 0.00%
Meter Read 2,121,637 0 0.00%
Meter OPs 1,082,295 138,419 12.79%
--------- -------
4,179,584 138,419 3.31%
North Shore
Inquiry 362,948 0 0.00%
Meter Read 2,253,417 0 0.00%
Meter OPs 907,277 106,033 11.69%
--------- -------
3,523,642 106,033 3.01%
=========
M Valley/ N Shore 7,703,228 244,452 3.17%
West
Inquiry 222,012 0 0.00%
Meter Read 1,174,272 0 0.00%
Meter OPs 621,829 10,811 1.74%
--------- ------
2,018,113 10,811 0.54%
Central
Inquiry 468,606 0 0.00%
Meter Read 1,519,383 0 0.00%
Meter OPs 722,902 61,649 8.52%
--------- ------
2,578,891 61,649 2.39%
=========
Central/West 4,597,004 72,460 1.58%
Southeast
Inquiry 614,464 0 0.00%
Meter Read 1,453,783 0 0.00%
Meter OPs 634,979 27,813 4.38%
--------- ------
2,573,226 27,813 1.08%
Management 221,586 0 0.00%
Total Customer Service 30,373,079 663,796 2.19%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CAPITAL PAYROLL BY FUNCTION
Payroll Capital Percent
Total Payroll To Capital
Operations (Note A)
<S> <C> <C> <C>
Engineering 7,133,255 1,883,343 26.40%
Dispatch 3,156,387 4,485 0.14%
Const Svcs 18,732,509 12,200,687 65.13%
T&D Svcs 6,910,541 901,301 13.04%
Env/Safety 768,947 9,269 1.21%
MValley/Gseco 15,120,701 4,519,335 29.89%
North Shore 10,961,770 3,325,721 30.34%
West 7,769,538 2,259,936 29.09%
Central 16,202,800 4,890,090 30.18%
Southeast 14,412,473 4,399,649 30.53%
Providence 18,495,146 5,927,166 32.05%
Mgmt 854,059 0 0.00%
------- -
Total Operations 120,318,126 40,320,982 33.51%
Executive 1,799,736 0 0.00%
Total Wires 149,648,046 40,996,105 27.40%
Wires plus A&G 181,215,151 40,007,432 25.44%
Note A
Detail costs excludes the following:
Stores (district level) 3,823,817 42,819 1.12%
Transportation (T&D Sv) 2,774,631 44,052 1.59%
Note 1 A&G Capital payroll includes A&G credit of $1,409,148
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
This Report Is:
Name of Respondent (1) [x] An Original Date of Report Year of Report
Massachusetts Electric Company (2) [ ] A Resubmisson (Mo, Da, Yr) Dec. 31, 1997
- ----------------------------------------------------------------------------------------------------------------------------------
GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE
- ----------------------------------------------------------------------------------------------------------------------------------
1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds
and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the
to cover, (b) the general procedure for determining the amount provisions of Electric Plant Instructions 3(17) of the
capitalized, (c) the method of distribution to constrution U.S. of A.
tion jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used,
types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computa-
different types of construction, and (f) whether the overhead tions below in a manner that clearly indicates the amount
is directly or indirectly assigned. of reduction in the gross rate for tax effects.
- ----------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
---------------------------------------------------------------------------------
For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average
rate earned during the preceding three years.
- ----------------------------------------------------------------------------------------------------------------------------------
1. Components of Formula (Derived from actual book balances and actual cost rates):
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization Cost Rate
Line Title Amount Ratio (Percent) Percentage
No. (a) (b) (c) (d)
<S> <C> <C> <C> <C> <C> <C>
(1) Average Short-Term Debt S $29,054,000
(2) Short-Term Interest s 5.63%
(3) Long-Term Debt D $375,000,000 44.01% d 7.46%
(4) Preferred Stock P $50,000,000 5.87% p 6.30%
(5) Common Equity C $427,061,000 50.12% c 11.00%
(6) Total Capitalization $852,061,000 100%
(7) Average Construction
Work in Progress Balance W $17,700,000
- ----------------------------------------------------------------------------------------------------------------------------------
2. Gross Rate for Borrowed Funds S D S
s(--) + d ( -- ) (1---) 5.63%
W D+P+C W
- ----------------------------------------------------------------------------------------------------------------------------------
3. Rate for Other Funds
S P C
[ 1 - -- ] [ p(-- -) + c(--) ] 0
W D+P+C D+P+C
- ----------------------------------------------------------------------------------------------------------------------------------
4. Weighted Average Rate Actually Used for the Year:
a. Rate for Borrowed Funds - 5.71%
b. Rate for Other Funds - 0
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
This Report Is: Date of Report
Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report
Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------------
GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE
- ---------------------------------------------------------------------------------------------------------------------------------
1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds
and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the
to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the
amount capitalized, (c) the method of distribution to construction U.S. of A.
jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used,
types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computations
different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount
is directly or indirectly assigned. of reduction in the gross rate for tax effects.
- ---------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
---------------------------------------------------------------------------------
For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average
rate earned during the preceding three years.
- ---------------------------------------------------------------------------------------------------------------------------------
1. Components of Formula (Derived from actual book balances and actual cost rates):
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization Cost Rate
Line Title Amount Ratio (Percent) Percentage
No. (a) (b) (c) (d)
<S> <C> <C> <C> <C> <C>
(1) Average Short-Term Debt S $5,117,538
(2) Short-Term Interest s 6.58%
(3) Long-Term Debt D $223,000,000 45.48% d 7.62%
(4) Preferred Stock P $27,034,771 5.51% p 9.83%
(5) Common Equity C $240,213,303 49.0% c 11.50%
(6) Total Capitalization $490,248,074 100%
(7) Average Construction
Work in Progress Balance W $4,399,855
- ----------------------------------------------------------------------------------------------------------------------------------
2. Gross Rate for Borrowed Funds S D S
s(--) + d(--) (1---) 6.58%
W D+P+C W
- ----------------------------------------------------------------------------------------------------------------------------------
3. Rate for Other Funds
S P C
[ 1 - -- ] [ p(-- -) + c(--) ] 0
W D+P+C D+P+C
- ----------------------------------------------------------------------------------------------------------------------------------
4. Weighted Average Rate Actually Used for the Year:
a. Rate for Borrowed Funds - 6.58%
b. Rate for Other Funds -
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
This Report Is: Date of Report
Name of Respondent (1) [x] An Original (Mo, Da, Yr) Year of Report
Massachusetts Electric Company (2) [ ] A Resubmisson 03/31/98 Dec. 31, 1997
- ---------------------------------------------------------------------------------------------------------------------------------
GENERAL DESCRIPTION OF CONSTRUCTION OVERHEAD PROCEDURE
- ---------------------------------------------------------------------------------------------------------------------------------
1. For each construction overhead explain: (a) the nature 2. Show below the computation of allowance for funds
and extent of work, etc. the overhead charges are intended used during construction rates, in accordance with the
to cover, (b) the general procedure for determining the provisions of Electric Plant Instructions 3(17) of the
amount capitalized, (c) the method of distribution to construction U.S. of A.
jobs, (d) whether different rates are applied to different 3. Where a net-of-tax rate for borrowed funds is used,
types of construction, (e) basis of differentiation in rates show the appropriate tax effect adjustment to the computations
different types of construction, and (f) whether the overhead below in a manner that clearly indicates the amount
is directly or indirectly assigned. of reduction in the gross rate for tax effects.
- ---------------------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------
COMPUTATION OF ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION RATES
---------------------------------------------------------------------------------
For line 1(5), column (d) below, enter the rate granted in the last rate proceeding. If such is not available, use the average
rate earned during the preceding three years.
- ---------------------------------------------------------------------------------------------------------------------------------
1. Components of Formula (Derived from actual book balances and actual cost rates):
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization Cost Rate
Line Title Amount Ratio (Percent) Percentage
No. (a) (b) (c) (d)
<S> <C> <C> <C> <C> <C>
(1) Average Short-Term Debt S $3,501,308
(2) Short-Term Interest s 7.11%
(3) Long-Term Debt D $36,500,000 46.29% d 9.35%
(4) Preferred Stock P $6,129,500 7.77% p 4.81%
(5) Common Equity C $36,232,083 45.94% c 11.43%
(6) Total Capitalization $78,861,583 100%
(7) Average Construction
Work in Progress Balance W $1,965,253
- ----------------------------------------------------------------------------------------------------------------------------------
2. Gross Rate for Borrowed Funds S D S
s(--) + d(--) (1---) 7.11%
W D+P+C W
- ----------------------------------------------------------------------------------------------------------------------------------
3. Rate for Other Funds
S P C
[ 1 - -- ] [ p(-- -) + c(--) ] 0
W D+P+C D+P+C
- ----------------------------------------------------------------------------------------------------------------------------------
4. Weighted Average Rate Actually Used for the Year: a. Rate for Borrowed Funds - 7.11% b. Rate
for Other Funds - 0
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
3. Stock-based compensation
At December 31, 1997, NEES has three stock-based compensation plans and measures its compensation cost for those plans using
the method of accounting prescribed by Accounting Principles Board Opinion No. 25. Accounting for Stock Issued to Employees, and
related interpretations. The compensation cost that has been charged against income for these plans was $3.3 million, $3.7 million
and $1.6 million for 1997, 1996, and 1995, respectively. If compensation cost for stock-based compensation had been accounted for
under Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation, the 1997 cost figures shown
above would have been slightly smaller.
Total income taxes in the statements of consolidated income are as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Income taxes charged to operations $152,024 $139,199 $128,340
Income taxes charged to "Other income" (7,268) (3.018) 762
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes, as shown above, consist of the following components:
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Current income taxes $175,934 $166,509 $105,046
Deferred income taxes (29,260) (28,652) 25,578
Investment tax credits, net (1,918) (1,676) (1,522)
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes, as shown above, consist of federal and state components as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Federal income taxes $118,317 $111,573 $103,503
State income taxes 26,439 24,608 25,599
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
Investment tax credits of subsidiaries are deferred and amortized over the estimated lives of the property giving rise to the
credits. Although investment tax credits were generally eliminated by the 1986 tax legislation, additional carryforward amounts
continue to be recognized.
With regulatory approval, the subsidiaries have adopted comprehensive interperiod tax allocation (normalization) for
temporary book/tax differences.
Total income taxes differ from the amounts computed by applying the federal statutory tax rates to income before taxes. The
reasons for the differences are as follows:
- ----------------------------------------------------------------------------------------------------------------------------------
Year ended December 31 (thousands of dollars) 1997 1996 1995
- ----------------------------------------------------------------------------------------------------------------------------------
Computed rate at statutory rate $131,989 $123,053 $119,892
Increases (reductions) in tax resulting from
Reversal of deferred taxes recorded at a higher rate (2,216) (2,175) (3,306)
Amortization of investment tax credits (4,469) (4,347) (4,443)
State income tax, net of federal income tax benefit 17,185 15,995 16,639
All other differences 2,267 3,655 320
- ----------------------------------------------------------------------------------------------------------------------------------
Total income taxes $144,756 $136,181 $129,102
- ----------------------------------------------------------------------------------------------------------------------------------
<PAGE>
</TABLE>
<TABLE>
<CAPTION>
Percentage of employee benefits, taxes as a percentage of total wages.
Company Percentage
<S> <C>
Blackstone Valley Electric Co. 30.45%
Eastern Edison Co. 31.74%
Newport Electric Corp. 38.16%
EUA Service Corp. 32.75%
Composite Percentage of employee benefits, taxes as a percentage of total wages for companies listed above
Composite
Description Amount Percentage
<S> <C> <C>
Taxes & Benefits $16,030,158.00
Total Labor $49,132,790.00 32.63%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Com Energy 1997 O&M in $000
Com Elec Cambr Elec Total Elec Com Gas Total
<S> <C> <C> <C>
transmission 6,667 5,612 12,279
distribution 25,239 4,085 29,324
customer accounts 15,579 2,197 17,776
csi and sales 7,639 1,760 9,399
a&g(not adj.) 40,763 12,323 53,086 30,919
Total O&M 95,887 25,977 121,864 30,919 152,783
DSM expenditures 5,500 5,500
Net O&M 116,364 147,283
customers in 000 322.3 44.9 367.2
distribution cap. additions in millions 18.4 3.5 21.9
EUA 1997 O&M in $000
Eastern Blackstone Newport
Edison Valley Electric Total
transmission 529 616 282 1,427
distribution 16,149 6,532 3,968 26,649
customer accounts 6,779 3,228 1,107 11,114
csi and sales 7,045 3,300 1,547 11,892
a&g (not adj.) 16,417 9,241 5,429 31,087
Total O&M 46,919 22,917 12,333 82,169
DSM expenditures 5,000
Net O&M 77,169
customers in 000 190.3 90.3 35.0 315.6
distribution cap. additions in millions 9.5 3.2 2.8 15.5
EUA 77,169 EUA 77,169
COM electric 116,364 COM total 147,283
% 66% % 52%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
BEC Com Pre-Merger Savings Post-Merger
<S> <C> <C> <C> <C> <C> <C>
1/1/2000 Staffing 2,230 1,108 3,338 362 2,976
Customers in 000 670 370 1,040 1,040
Employees per 000 Customers 3.3 3.0 3.2 2.9
Incremental staffing to BEC 746 33%
Incremental customers to BEC 370 55%
NEES EUA Pre-Merger Savings Post-Merger
1/1/2000 Staffing 3,240 869 4,109 234 3,875
Customers in 000 1,340 320 1,660 1,660
Employees per 000 Customers 2.4 2.7 2.5 2.3
Incremental staffing to NEES 635 20%
Incremental customers to NEES 320 24%
1997 Ave. Customers (FERC #1)
Boston Edison 670 Com Elec 322
Cam Elec 45
COM Total 367
Com Gas 237 SEC 10-K
Mass Elec 960 Eastern 190
Narr Elec 331 Blackstone 90
Granite State 36 Newport 35
Nantucket 10 EUA Total 316
NEES Total 1,337
</TABLE>
<PAGE>
New England Electric System
Eastern Utilities Associates
R.I.P.U.C. Docket No. ______
Exhibit DJH-3
Exhibit DJH-3
Supporting Working Papers
(Confidential)
<PAGE>
AGREEMENT AND PLAN OF MERGER
and CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
TABLE OF CONTENTS
AGREEMENT AND PLAN OF MERGER...................................................1
CONSENT AGREEMENT..............................................................2
<PAGE>
Tab 1
AGREEMENT AND PLAN OF MERGER
dated as of February 1, 1999
by and among
NEW ENGLAND ELECTRIC SYSTEM,
RESEARCH DRIVE LLC
and
EASTERN UTILITIES ASSOCIATES
<PAGE>
TABLE OF CONTENTS
Page
No.
ARTICLE I
THE MERGER......................................................... 1
1.01 The Merger......................................................... 1
1.02 Effective Time..................................................... 1
1.03 Effects of the Merger.............................................. 2
ARTICLE II
CONVERSION OF SHARES............................................... 2
2.01 Conversion of Capital Stock........................................ 2
2.02 Surrender of Shares................................................ 3
2.03 Withholding Rights................................................. 4
ARTICLE III
THE CLOSING........................................................ 4
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5
4.01 Organization and Qualification..................................... 5
4.02 Capital Stock...................................................... 6
4.03 Authority.......................................................... 7
4.04 Non-Contravention; Approvals and Consents.......................... 7
4.05 SEC Reports, Financial Statements and Utility Reports.............. 8
4.06 Absence of Certain Changes or Events............................... 9
4.07 Legal Proceedings.................................................. 9
4.08 Information Supplied............................................... 9
4.09 Compliance......................................................... 10
4.10 Taxes.............................................................. 10
4.11 Employee Benefit Plans; ERISA...................................... 12
4.12 Labor Matters...................................................... 14
4.13 Environmental Matters.............................................. 15
4.14 Regulation as a Utility............................................ 17
4.15 Insurance.......................................................... 17
4.16 Nuclear Facilities................................................. 18
4.17 Vote Required...................................................... 18
4.18 Opinion of Financial Advisor....................................... 18
-i-
<PAGE>
Page
No.
4.19 Ownership of NEES Common Shares.................................... 18
4.20 State Anti-Takeover Statutes....................................... 18
4.21 Year 2000.......................................................... 19
4.22 EUA Associates..................................................... 19
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES............................. 19
5.01 Organization and Qualification..................................... 19
5.02 Authority.......................................................... 20
5.03 Capital Stock...................................................... 20
5.04 Non-Contravention; Approvals and Consents.......................... 20
5.05 Information Supplied............................................... 21
5.06 Compliance......................................................... 21
5.07 Financing.......................................................... 22
5.08 No Vote Required................................................... 22
5.09 Ownership of EUA Shares............................................ 22
5.10 Merger with The National Grid Group plc............................ 22
ARTICLE VI
COVENANTS................................................ 22
6.01 Covenants of EUA................................................... 22
6.02 Covenants of NEES.................................................. 28
6.03 Additional Covenants by NEES and EUA............................... 29
ARTICLE VII
ADDITIONAL AGREEMENTS.................................... 30
7.01 Access to Information.............................................. 30
7.02 Proxy Statement.................................................... 31
7.03 Approval of Shareholders........................................... 31
7.04 Regulatory and Other Approvals..................................... 31
7.05 Employee Benefit Plans............................................. 32
7.06 Labor Agreements and Workforce Matters............................. 34
7.07 Post Merger Operations............................................. 34
7.08 No Solicitations................................................... 35
7.09 Directors' and Officers' Indemnification and Insurance............. 36
7.10 Expenses........................................................... 37
7.11 Brokers or Finders................................................. 37
7.12 Anti-Takeover Statutes............................................. 38
7.13 Public Announcements............................................... 38
-ii-
<PAGE>
Page
No.
7.14 Restructuring of the Merger........................................ 38
ARTICLE VIII
CONDITIONS......................................................... 39
8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39
8.03 Conditions to Obligation of EUA to Effect the Merger............... 40
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER.................................. 41
9.01 Termination........................................................ 41
9.02 Effect of Termination.............................................. 43
9.03 Termination Fees................................................... 43
9.04 Amendment.......................................................... 44
9.05 Waiver............................................................. 44
ARTICLE X
GENERAL PROVISIONS................................................. 44
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements......................................................... 44
10.02 Notices............................................................ 44
10.03 Entire Agreement; Incorporation of Exhibits........................ 46
10.04 No Third Party Beneficiary......................................... 46
10.05 No Assignment; Binding Effect...................................... 46
10.06 Headings........................................................... 47
10.07 Invalid Provisions................................................. 47
10.08 Governing Law...................................................... 47
10.09 Enforcement of Agreement........................................... 47
10.10 Certain Definitions................................................ 47
10.11 Counterparts....................................................... 48
10.12 WAIVER OF JURY TRIAL............................................... 48
-iii-
<PAGE>
GLOSSARY OF DEFINED TERMS
The following terms, when used in this Agreement, have the meanings
ascribed to them in the corresponding Sections of this Agreement listed below:
"1935 Act" -- Section 4.05(b)
"Adjustment Date" -- Section 2.01(c)
"Affected Employees" -- Section 7.05(a)
"affiliate" -- Section 10.11(a)
"Agreement" -- Preamble
"Alternative Proposal" -- Section 7.08
"beneficially" -- Section 10.10(b)
"business day" -- Section 10.10(c)
"Canceled Shares" -- Section 2.02(b)
"Certificates" -- Section 2.02(b)
"Closing" -- Article III
"Closing Agreement" -- Section 4.10(j)
"Closing Date" -- Article III
"Code" -- Section 2.03
"Confidentiality Agreement" -- Section 7.01
"Constituent Entities" -- Section 1.01
"Contracts" -- Section 4.04(a)
"control," "controlling,"
"controlled by" and
"under common control with" -- Section 10.10(a)
"DOE" -- Section 4.05(b)
"Effective Time" -- Section 1.02
"Environmental Claim" -- Section 4.13(f)(i)
"Environmental Laws" -- Section 4.13(f)(ii)
"Environmental Permits" -- Section 4.13(b)
"ERISA" -- Section 4.11(a)
"ERISA Affiliate" -- Section 4.11(c)
"EUA" -- Preamble
"EUA Associates" -- Section 4.01(b)
"EUA Employee Agreements" -- Section 7.05(d)(ii)
"EUA Executives" -- Section 7.05(d)(ii)
"EUA Shares" -- Preamble
"EUA Disclosure Letter" -- Section 4.01(a)
"EUA Employee Benefit Plans" -- Section 4.11(a)
"EUA Financial Statements" -- Section 4.05(a)
"EUA Nuclear Facilities" -- Section 4.16
"EUA Material Adverse Effect" -- Section 4.01(a)
"EUA Required Consents" -- Section 4.04(a)
"EUA Required Statutory Approvals" -- Section 4.04(b)
"EUA SEC Reports" -- Section 4.05(a)
-iv-
<PAGE>
"EUA Shareholders' Approval" -- Section 7.03
"EUA Shareholders' Meeting" -- Section 7.03
"EUA Significant Subsidiary" -- Section 7.08
"EUA Shares" -- Preamble
"EUA Trust Agreement" -- Section 1.03
"EUA Voting Debt -- Section 4.02(d)
"Evaluation Material" -- Section 7.01(a)
"Exchange Act" -- Section 4.05(a)
"Exchange Fund" -- Section 2.02(a)
"Extended Termination Date" -- Section 9.01(b)
"FCC" -- Section 4.05(b)
"FERC" -- Section 4.05(b)
"Final Order" -- Section 8.01(d)
"Governmental Authority" -- Section 4.04(a)
"Hazardous Materials" -- Section 4.13(f)(iii)
"HSR Act" -- Section 7.04(a)
"Indemnified Liabilities" -- Section 7.09(a)
"Indemnified Party" -- Section 7.09(a)
"Indemnified Parties" -- Section 7.09(a)
"Information Systems" -- Section 4.21
"Initial Termination Date" -- Section 9.01(b)
"IRS" -- Section 4.10(m)
"knowledge" -- Section 10.11(d)
"laws" -- Section 4.04(a)
"Lien" -- Section 4.02(b)
"LLC" -- Preamble
"Massachusetts Secretary" -- Section 1.02
"Merger" -- Preamble
"Merger Consideration" -- Section 2.01(b)(ii)
"MGL" -- Section 1.01
"National Grid Group" -- Section 5.10
"National Grid Merger Agreement" -- Section 5.10
"NEES" -- Preamble
"NEES Disclosure Letter" -- Section 5.03
"NEES Material Adverse Effect" -- Section 5.01
"NEES-EUA Regulatory Approvals" -- Section 7.04(b)
"NEES-EUA Regulatory Proceedings" -- Section 7.04(c)
"NEES Required Consents" -- Section 5.04(a)
"NEES Required Statutory Approvals" -- Section 5.04(b)
"NEES-NGG Regulatory Approvals" -- Section 7.04(c)
"NEES-NGG Regulatory Proceedings" -- Section 7.04(c)
"NEES-NGG Required Statutory Approvals"-- Section 7.04
"NEES-NGG Transactions" -- Section 7.04
"NEES Shares" -- Section 5.03
-v-
<PAGE>
"NEES Trust Agreement" -- Section 5.01
"NGG Circular" -- Section 7.02
"NRC" -- Section 4.05(b)
"Options" -- Section 4.02(a)
"orders" -- Section 4.04(a)
"Out-of-Pocket Expenses" -- Section 9.03(a)
"Paying Agent" -- Section 2.02(a)
"PBGC" -- Section 4.11(g)
"person" -- Section 10.11(e)
"Per Share Amount" -- Section 2.01(b)(ii)
"Post Closing Plans" -- Section 7.05(b)
"Proxy Statement" -- Section 4.08(a)
"Release" -- Section 4.13(f)(iv)
"Representatives" -- Section 10.11(f)
"SEC" -- Section 4.05(a)
"Securities Act" -- Section 4.05(a)
"Subsidiary" -- Section 10.11(g)
"Surviving Entity" -- Section 1.01
"Tax Ruling" -- Section 4.10(j)
"Taxes" -- Section 4.10
"Tax Return" -- Section 4.10
"US GAAP" -- Section 4.05(a)
"Yankee Companies" -- Section 4.16
"Y2K Consultant" -- Section 6.01(o)
-vi-
<PAGE>
This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this
"Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM,
a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a
Massachusetts limited liability company which is directly and indirectly wholly
owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust
("EUA").
WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA
and the members of LLC have each determined that it is advisable and in the best
interests of their respective shareholders and members to consummate, and have
approved, the business combination transaction provided for herein in which LLC
would merge with and into EUA, with EUA being the surviving entity (the
"Merger"), pursuant to the terms and conditions of this Agreement, as a result
of which NEES will own, directly or indirectly, all of the issued and
outstanding common shares of EUA (the "EUA Shares");
WHEREAS, NEES, LLC and EUA desire to make certain representations,
warranties and agreements in connection with the Merger and also to prescribe
various conditions to the Merger;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements set forth in this Agreement, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereto hereby agree as follows:
ARTICLE I
THE MERGER
1.01 The Merger. Upon the terms and subject to the conditions of this
Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be
merged with and into EUA in accordance with Section 2 of Chapter 182 and Section
59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective
Time, the separate existence of LLC shall cease and EUA shall continue as the
surviving entity in the Merger. EUA, after the Effective Time, is sometimes
referred to herein as the "Surviving Entity" and EUA and LLC are sometimes
referred to herein as the "Constituent Entities". The effect and consequences of
the Merger shall be as set forth in Article II.
1.02 Effective Time. Subject to the provisions of this Agreement, on
the Closing Date (as defined in Article III), a certificate of merger shall be
executed and filed by EUA and LLC with the Secretary of the Commonwealth of
Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective
at the time of the filing of the certificate of merger relating to the Merger
with the Massachusetts Secretary, or at such later time as is specified in the
certificate of merger (such date and time being referred to herein as the
"Effective Time").
<PAGE>
1.03 Effects of the Merger. At the Effective Time, the Agreement and
Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately
prior to the Effective Time shall be the agreement and declaration of trust of
the Surviving Entity, until thereafter amended as provided by law and such
agreement and declaration of trust. Subject to the foregoing, the additional
effects of the Merger shall be as provided in the applicable provisions of
Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability
Company Act of Massachusetts.
ARTICLE II
CONVERSION OF SHARES
2.01 Conversion of Capital Stock. At the Effective Time, by virtue of
the Merger and without any action on the part of the holder thereof:
(a) Membership Interests of LLC. Each one percent of the issued
and outstanding membership interests in LLC shall be converted into one
transferable certificate of participation or share of the Surviving Entity.
(b) Conversion of EUA Shares.
(i) Cancellation of Treasury Shares and Shares Owned by
NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares
and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as
defined in Section 10.11) of NEES shall be canceled and retired and shall cease
to exist and no cash or other consideration shall be delivered in exchange
therefor.
(ii) Conversion of EUA Shares. Each EUA Share issued and
outstanding immediately prior to the Effective Time (other than shares to be
canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted
in accordance with the provisions of this Section 2.01 into the right to receive
cash in the amount (the "Per Share Amount") of $31.00 as such amount may
hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger
Consideration"), payable, without interest, to the holder of such EUA Share,
upon surrender, in the manner provided in Section 2.02 hereof, of the
certificate formerly evidencing such share.
(c) Adjustment in Amount of Merger Consideration. In the event
that the Closing Date shall not have occurred on or prior to the date that is
the six (6) month anniversary of the date on which EUA Shareholders' Approval is
obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for
each day after the Adjustment Date up to and including the day which is one day
prior to the earlier of the Closing Date and the Extended Termination Date, by
an amount equal to $0.003.
-2-
<PAGE>
2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the
Effective Time, NEES shall designate a bank or trust company reasonably
acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the
holders of EUA Shares in connection with the Merger to receive the funds to
which holders of EUA Shares shall become entitled pursuant to Section
2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or
after the Effective Time, NEES or LLC shall make or cause to be made available
to the Paying Agent immediately available funds in amounts and at the times
necessary for the payment of the Merger Consideration upon surrender of
Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b),
it being understood that any and all interest or other income earned on funds
made available to the Paying Agent pursuant to this Section 2.02(a) shall belong
to and shall be paid (at the time provided for in Section 2.02(e)) as directed
by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be
invested by the Paying Agent as directed by NEES or LLC.
(b) Exchange Procedure. As soon as practicable after the
Effective Time, the Paying Agent shall mail to each holder of record of a
certificate or certificates (the "Certificates") which immediately prior to the
Effective Time represented outstanding EUA Shares (the "Canceled Shares") that
were canceled and became instead the right to receive the Merger Consideration
pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as
NEES and EUA may reasonably agree (which shall specify that delivery shall be
effected, and risk of loss and title to the Certificates shall pass, only upon
actual delivery of the Certificates to the Paying Agent) and (ii) instructions
for effecting the surrender of the Certificates in exchange for the Merger
Consideration. Upon surrender of a Certificate or Certificates to the Paying
Agent for cancellation (or to such other agent or agents as may be appointed by
NEES and are reasonably acceptable to EUA), together with a duly executed letter
of transmittal and such other documents as the Paying Agent shall require, the
holder of such Certificate shall be entitled to receive the Merger Consideration
in exchange for each EUA Share formerly evidenced by such Certificate which such
holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of
a transfer of ownership of Canceled Shares which is not registered in the
transfer records of EUA, the Merger Consideration in respect of such Canceled
Shares may be given to the transferee thereof if the Certificate or Certificates
representing such Canceled Shares is presented to the Paying Agent, accompanied
by all documents required to evidence and effect such transfer and by evidence
satisfactory to the Paying Agent that any applicable stock transfer taxes have
been paid. At any time after the Effective Time, each Certificate shall be
deemed to represent only the right to receive the Merger Consideration subject
to and upon the surrender of such Certificate as contemplated by this Section
2.02. No interest shall be paid or will accrue on the Merger Consideration
payable to holders of Certificates pursuant to Section 2.01(b)(ii).
(c) No Further Ownership Rights in EUA Shares. The Merger
Consideration paid upon the surrender of Certificates in accordance with the
terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective
Time in full satisfaction of all rights pertaining to EUA Shares represented
thereby. From and after the Effective Time, the share transfer books of EUA
shall be closed and there shall be no further registration of transfers thereon
of EUA Shares which were outstanding immediately prior to the Effective Time.
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If, after the Effective Time, Certificates are presented to NEES for any reason,
they shall be canceled and exchanged as provided in this Section 2.02.
(d) Lost, Stolen or Destroyed Certificates. In the event any
owner of any Certificate shall claim that such Certificate shall have been lost,
stolen or destroyed, upon the making of an affidavit of that fact by the owner
of such Certificate and delivery of that affidavit to the Paying Agent and, if
required by NEES or LLC, the posting by such person of a bond in customary
amount as indemnity against any claim that may be made against NEES, EUA or the
Surviving Entity with respect to such Certificate, the Paying Agent will issue
in exchange for such lost, stolen or destroyed Certificate the Merger
Consideration payable upon due surrender of, and deliverable pursuant to this
Section 2.02 in respect of, EUA Shares to which such Certificate relates.
(e) Termination of Exchange Fund. Any portion of the Exchange
Fund which remains undistributed to the shareholders of EUA for one (1) year
after the Effective Time shall be delivered to the Surviving Entity, upon
demand, and any Shareholders of EUA who have not theretofore complied with this
Article II shall thereafter look only to the Surviving Entity (subject to
abandoned property, escheat and other similar laws) as general creditors for
payment of their claim for the Merger Consideration payable upon due surrender
of the Certificates held by them. None of NEES, LLC or the Surviving Entity
shall be liable to any former holder of EUA Shares for the Merger Consideration
delivered to a public official pursuant to any applicable abandoned property,
escheat or similar law.
2.03 Withholding Rights. Each of the Surviving Entity and NEES shall
be entitled to deduct and withhold from the consideration otherwise payable
pursuant to this Agreement to any holder of EUA Shares such amounts as it is
required to deduct and withhold with respect to the making of such payment under
the Internal Revenue Code of 1986, as amended (the "Code"), or any other
provision of state, local or foreign tax law. To the extent that amounts are so
withheld by the Surviving Entity or NEES, as the case may be, such withheld
amounts shall be treated for all purposes of this Agreement as having been paid
to the holder of EUA Shares in respect of which such deduction and withholding
was made by the Surviving Entity or NEES, as the case may be.
ARTICLE III
THE CLOSING
The closing of the Merger and other transactions contemplated hereby
(the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher
& Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local
time, on the second business day following satisfaction or waiver (where
applicable) of the conditions set forth in Article VIII (other than those
conditions that by their nature are to be fulfilled at the Closing, but subject
to the fulfillment or waiver of such conditions), unless another date, time or
place is agreed to in writing by the parties hereto (the "Closing Date").
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA
EUA represents and warrants to NEES and LLC as follows:
4.01 Organization and Qualification. (a) EUA is a voluntary
association duly organized, validly existing and in good standing under the laws
of the Commonwealth of Massachusetts and has full power, authority and legal
right to own its property and assets and to transact the business in which it is
engaged. Each of EUA's Subsidiaries is a corporation duly organized or
incorporated, validly existing and in good standing under the laws of its
jurisdiction of organization or incorporation and has full corporate power and
authority to conduct its business as and to the extent now conducted and to own,
use and lease its assets and properties, except where failure to be so organized
or incorporated, existing and in good standing or to have such power and
authority, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA
Material Adverse Effect" means a material adverse effect on the business,
assets, results of operations, condition (financial or otherwise) or prospects
of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries
is duly qualified, licensed or admitted to do business and is in good standing
in each jurisdiction in which the ownership, use or leasing of its assets and
properties, or the conduct or nature of its business, makes such qualification,
licensing or admission necessary, except where failure to be so qualified,
licensed or admitted and in good standing, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect. Section
4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA
concurrently with the execution and delivery of this Agreement (the "EUA
Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or
organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized
capital stock, (iii) the number of issued and outstanding shares of capital
stock of such Subsidiary and (iv) the number of shares of such Subsidiary held
of record by EUA. EUA has previously delivered to NEES correct and complete
copies of the EUA Trust Agreement and the certificate or articles of
organization or incorporation and bylaws (or other comparable charter documents)
of its Subsidiaries.
(b) Section 4.01 of the EUA Disclosure Letter sets forth a
description as of the date hereof, of all EUA Associates, including (i) the name
of each such entity and EUA's interest therein and (ii) a brief description of
the principal line or lines of business conducted by each such entity. For
purposes of this Agreement "EUA Associates" shall mean any corporation or other
entity (including partnerships and other business associations) that is not a
Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly
or indirectly, owns an equity interest (other than short-term investments in the
ordinary course of business) if such corporation or other entity (including
partnerships and other business associations) contributes five percent or more
of EUA's consolidated revenues, assets, income or costs.
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4.02 Capital Stock. (a) The authorized equity securities of EUA
consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and
outstanding as of the close of business on January 29, 1999. As of the close of
business on January 29, 1999, no EUA Shares were held in the treasury of EUA.
Since such date there has been no change in the sum of the issued and
outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly
authorized, validly issued, fully paid and nonassessable. Except pursuant to
this Agreement and except as described in Section 4.02 of the EUA Disclosure
Letter, on the date hereof there are no outstanding subscriptions, options,
warrants, rights (including share appreciation rights), preemptive rights or
other contracts, commitments, understandings or arrangements, including any
right of conversion or exchange under any outstanding security, instrument or
agreement (together, "Options"), obligating EUA or any of its Subsidiaries to
issue or sell any shares of equity securities of EUA or to grant, extend or
enter into any Option with respect thereto. The EUA Disclosure Letter sets forth
all capital stock authorized, issued and outstanding at subsidiary levels as of
the close of business on January 29, 1999.
(b) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the
outstanding shares of capital stock of each Subsidiary of EUA are duly
authorized, validly issued, fully paid and nonassessable and are owned,
beneficially and of record, by EUA or a Subsidiary, which is wholly owned,
directly or indirectly, by EUA, free and clear of any liens, claims, mortgages,
encumbrances, pledges, security interests, equities and charges of any kind
(each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date
of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i)
outstanding Options obligating EUA or any of its Subsidiaries to issue or sell
any shares of capital stock of any Subsidiary of EUA or to grant, extend or
enter into any such Option or (ii) voting trusts, proxies or other commitments,
understandings, restrictions or arrangements in favor of any person other than
EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with
respect to the voting of, or the right to participate in, dividends or other
earnings on any capital stock of any Subsidiary of EUA.
(c) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are
no outstanding contractual obligations of EUA or any Subsidiary of EUA to
repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of
any Subsidiary of EUA or to provide funds to, or make any investment (in the
form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or
any other person.
(d) As of the date of this Agreement, no bonds, debentures,
notes or other indebtedness of EUA or any Subsidiary of EUA having the right to
vote (or which are convertible into or exercisable for securities having the
right to vote) (together "EUA Voting Debt") on any matters on which Shareholders
may vote are issued or outstanding nor are there any outstanding Options
obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt
or to grant, extend or enter into any Option with respect thereto.
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4.03 Authority. EUA has full power and authority to enter into this
Agreement, to perform its obligations hereunder and, subject to obtaining EUA
Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required
Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger
and other transactions contemplated hereby. The execution, delivery and
performance of this Agreement by EUA and the consummation by EUA of the Merger
and other transactions contemplated hereby have been duly authorized by all
necessary action on the part of EUA, subject to obtaining EUA Shareholders'
Approval with respect to the consummation of the Merger and the other
transactions contemplated hereby. This Agreement has been duly and validly
executed and delivered by EUA and constitutes a legal, valid and binding
obligation of EUA enforceable against EUA in accordance with its terms, except
as enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
4.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by EUA do not, and the performance by EUA of its
obligations hereunder and the consummation of the Merger and other transactions
contemplated hereby will not, conflict with, result in a violation or breach of,
constitute (with or without notice or lapse of time or both) a default under,
result in or give to any person any right of payment or reimbursement,
termination, cancellation, modification or acceleration of, or result in the
creation or imposition of any Lien upon any of the assets or properties of EUA
or any of its Subsidiaries or any of the terms, conditions or provisions of (i)
the EUA Trust Agreement or the certificates or articles of incorporation or
organization or bylaws (or other comparable charter documents) of EUA's
Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval,
EUA Required Consents, EUA Required Statutory Approvals and the taking of any
other actions described in this Section 4.04, (x) any statute, law, rule,
regulation or ordinance (together, "laws"), or any judgment, decree, order,
writ, permit or license (together, "orders"), of any court, tribunal,
arbitrator, authority, agency, commission, official or other instrumentality of
the United States, any foreign country or any domestic or foreign state, county,
city or other political subdivision (a "Governmental Authority") applicable to
EUA or any of its Subsidiaries or any of their respective assets or properties,
or (y) subject to obtaining the third-party consents set forth in Section 4.04
of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond,
mortgage, security agreement, indenture, license, franchise, permit, concession,
contract, lease or other instrument, obligation or agreement of any kind
(together, "Contracts") to which EUA or any of its Subsidiaries is a party or by
which EUA or any of its Subsidiaries or any of their respective assets or
properties is bound, excluding from the foregoing clauses (x) and (y) such
conflicts, violations, breaches, defaults, payments or reimbursements,
terminations, cancellations, modifications, accelerations and creations and
impositions of Liens which, individually or in the aggregate, could not
reasonably be expected to have an EUA Material Adverse Effect.
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(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by EUA or the consummation by
EUA of the Merger and other transactions contemplated hereby except as described
in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain
could not reasonably be expected to result in an EUA Material Adverse Effect
(the "EUA Required Statutory Approvals," it being understood that references in
this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean
making such declarations, filings or registrations; giving such notices;
obtaining such authorizations, consents or approvals; and having such waiting
periods expire as are necessary to avoid a violation of law).
4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA
delivered to NEES prior to the execution of this Agreement a true and complete
copy of each form, report, schedule, registration statement, registration
exemption, if applicable, definitive proxy statement and other document
(together with all amendments thereof and supplements thereto) filed by EUA or
any of its Subsidiaries with the Securities and Exchange Commission (the "SEC")
under the Securities Act of 1933, as amended, and the rules and regulations
thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as
amended, and the rules and regulations thereunder (the "Exchange Act") since
December 31, 1995 (as such documents have since the time of their filing been
amended or supplemented, the "EUA SEC Reports"), which are all the documents
(other than preliminary materials) that EUA and its Subsidiaries were required
to file with the SEC under the Securities Act and the Exchange Act since such
date. As of their respective dates, EUA SEC Reports (i) complied as to form in
all material respects with the requirements of the Securities Act or the
Exchange Act, as the case may be, and (ii) did not contain any untrue statement
of a material fact or omit to state a material fact required to be stated
therein or necessary in order to make the statements therein, in light of the
circumstances under which they were made, not misleading. Each of the audited
consolidated financial statements and unaudited interim consolidated financial
statements (including, in each case, the notes, if any, thereto) included in EUA
SEC Reports (the "EUA Financial Statements") complied as to form in all material
respects with the published rules and regulations of the SEC with respect
thereto, were prepared in accordance with U.S. generally accepted accounting
principles ("US GAAP") applied on a consistent basis during the periods involved
(except as may be indicated therein or in the notes thereto and except with
respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly
present (subject, in the case of the unaudited interim financial statements, to
normal, recurring year-end audit adjustments (which are not expected to be,
individually or in the aggregate, materially adverse to EUA and its Subsidiaries
taken as a whole)) the consolidated financial position of EUA and its
consolidated subsidiaries as at the respective dates thereof and the
consolidated results of their operations and cash flows for the respective
periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure
Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in
EUA Financial Statements for all periods covered thereby.
(b) All filings (other than immaterial filings) required to be
made by EUA or any of its Subsidiaries since December 31, 1995, under the Public
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Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the
Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state
laws and regulations, have been filed with the SEC, the Federal Energy
Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the
Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission
(the "FCC") or any appropriate state public utility commissions (including,
without limitation, to the extent required, the state public utility regulatory
agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and
Connecticut as the case may be, including all forms, statements, reports,
agreements (oral or written) and all documents, exhibits, amendments and
supplements appertaining thereto, including but not limited to all rates,
tariffs, franchises, service agreements and related documents and all such
filings complied, as of their respective dates, in all material respects with
all applicable requirements of the appropriate statutes and the rules and
regulations thereunder.
4.06 Absence of Certain Changes or Events. Except as set forth in
Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports
filed prior to the date of this Agreement since December 31, 1997, EUA and each
of EUA's Subsidiaries have conducted its business only in the ordinary course of
business consistent with past practice and there has not been, and no fact or
condition exists which, individually or in the aggregate, has or could
reasonably be expected to have an EUA Material Adverse Effect.
4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed
prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure
Letter and except for environmental matters which are governed by Section 4.13,
(i) there are no actions, claims, hearings, suits, arbitrations or proceedings
pending or, to the knowledge of EUA or any of its Subsidiaries, threatened
against, specifically relating to or affecting, and, to the knowledge of EUA or
any of its Subsidiaries, there are no Governmental Authority investigations or
audits pending or threatened against, specifically relating to or affecting, EUA
or any of its Subsidiaries or any of their respective assets and properties
which, individually or in the aggregate, could reasonably be expected to have an
EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is
subject to any order of any Governmental Authority which, individually or in the
aggregate, could reasonably be expected to have an EUA Material Adverse Effect.
4.08 Information Supplied. (a) The proxy statement relating to EUA
Shareholders' Meeting, as amended or supplemented from time to time (as so
amended and supplemented, the "Proxy Statement"), and any other documents to be
filed by EUA with the SEC (including, without limitation, under the 1935 Act) or
any other Governmental Authority in connection with the Merger and other
transactions contemplated hereby will comply as to form in all material respects
with the requirements of the Exchange Act, the Securities Act and the 1935 Act,
as applicable, and will not, on the date of their respective filings or, in the
case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and
at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain
any untrue statement of a material fact or omit to state any material fact
necessary in order to make the statements therein, in light of the circumstances
under which they are made, not misleading.
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(b) Notwithstanding the foregoing provisions of this Section
4.08, no representation or warranty is made by EUA with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by NEES or LLC for inclusion or incorporation by reference therein.
4.09 Compliance. Except as set forth in Section 4.09 of the EUA
Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date
hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the
knowledge of EUA, under investigation with respect to any violation of, or has
been given notice or been charged with any violation of, any law, statute,
order, rule, regulation, ordinance or judgment (including, without limitation,
any applicable environmental law, ordinance or regulation) of any Governmental
Authority, except for possible violations which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as
disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's
Subsidiaries have all permits, licenses, franchises and other governmental
authorizations, consents and approvals necessary to conduct their businesses as
presently conducted except for such failures which could not reasonably be
expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's
Subsidiaries is in breach or violation of, or in default in the performance or
observance of any term or provision of, (i) the EUA Trust Agreement, in the case
of EUA, or articles of incorporation or organization or by-laws, in the case of
EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture,
mortgage, loan agreement, note, lease, bond, license, approval or other
instrument to which it is a party or by which EUA or any Subsidiary of EUA is
bound or to which any of their respective property is subject, except for
possible violations, breaches or defaults which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure
Letter:
(a) Filing of Timely Tax Returns. EUA and each of its
Subsidiaries have timely filed all Tax Returns required to be filed by each of
them under applicable law. All Tax Returns were (and, as to Tax Returns not
filed as of the date hereof, will be) true, complete and correct;
(b) Payment of Taxes. EUA and each of its Subsidiaries have,
within the time and in the manner prescribed by law, paid (and until the Closing
Date will pay within the time and in the manner prescribed by law) all Taxes
that are currently due and payable except for those contested in good faith and
for which adequate reserves have been taken;
(c) Tax Reserves. EUA and its Subsidiaries have established (and
until the Closing Date will maintain) on their books and records adequate
reserves for all Taxes and for any liability for deferred income taxes in
accordance with GAAP;
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(d) Extensions of Time for Filing Tax Returns. Neither EUA nor
any of its Subsidiaries has requested any extension of time within which to file
any Tax Return, which Tax Return has not since been filed;
(e) Waivers of Statute of Limitations. Neither EUA nor any of
its Subsidiaries has in effect any extension, outstanding waivers or comparable
consents regarding the application of the statute of limitations with respect to
any Taxes or Tax Returns;
(f) Expiration of Statute of Limitations. The Tax Returns of
EUA, each of its Subsidiaries and any affiliated, consolidated, combined or
unitary group that includes EUA or any of its Subsidiaries either have been
examined and settled with the appropriate Tax authority or closed by virtue of
the expiration of the applicable statute of limitations for all years through
and including 1993;
(g) Audit, Administrative and Court Proceedings. No audits or
other administrative proceedings or court proceedings are presently pending or
threatened with regard to any Taxes or Tax Returns of EUA or any of its
Subsidiaries (other than those being contested in good faith and for which
adequate reserves have been established) and no issues have been raised in
writing by any Tax authority in connection with any Tax or Tax Return;
(h) Tax Liens. There are no Tax liens upon any asset of EUA or
any of its Subsidiaries except liens for Taxes not yet due.
(i) Powers of Attorney. No power of attorney currently in force
has been granted by EUA or any of its Subsidiaries concerning any Tax matter;
(j) Tax Rulings. Neither EUA nor any of its Subsidiaries has,
during the five year period prior to the date of this Agreement, received a Tax
Ruling (as defined below) or entered into a Closing Agreement (as defined below)
with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a
written ruling of a taxing authority relating to Taxes. "Closing Agreement", as
used in this Agreement, shall mean a written and legally binding agreement with
a taxing authority relating to Taxes;
(k) Availability of Tax Returns. EUA and its Subsidiaries have
made available to NEES complete and accurate copies, covering all years ending
on or after December 31, 1993, of (i) all Tax Returns, and any amendments
thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports
received from any taxing authority relating to any Tax Return filed by EUA or
any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or
any of its Subsidiaries with any taxing authority.
(l) Tax Sharing Agreements. No agreements relating to the
allocation or sharing of Taxes exist between or among EUA and any of its
Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member
of an affiliated group filing a consolidated federal income tax return (other
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than a group the common parent of which was EUA) or (ii) has any liability for
Taxes of any Person (other than EUA or its Subsidiaries) under United States
Treasury Regulation Section 1.1502-6 (or any provision of state, local), or
foreign law, as a transferee or successor, by contract or otherwise;
(m) Code Section 481 Adjustments. Neither EUA nor any of its
Subsidiaries is required to include in income any adjustment pursuant to Code
Section 481(a) by reason of a voluntary change in accounting method initiated by
EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has
not proposed any such adjustment or change in accounting method;
(n) Code Sections 6661 and 6662. All transactions that could
give rise to an understatement of federal income tax, and within the meaning of
Code Section 6662 have been adequately disclosed (or, with respect to Tax
Returns filed following the Closing, will be adequately disclosed) on the Tax
Returns of EUA and its Subsidiaries in accordance with Code Section
6662(d)(2)(B);
(o) Intercompany Transactions. Neither EUA nor any of its
Subsidiaries has engaged in any intercompany transactions within the meaning of
Treasury Regulations ss. 1.1502-13 for which any income or gain will remain
unrecognized as of the close of the last taxable year prior to the Closing Date;
and
(p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries
is required to file a foreign tax return.
"Taxes" as used in this Agreement, shall mean any federal, state,
county, local or foreign taxes, charges, fees, levies, or other assessments,
including all net income, gross income, premiums, sales and use, ad valorem,
transfer, gains, profits, windfall profits, excise, franchise, real and personal
property, gross receipts, capital stock, production, business and occupation,
employment, disability, payroll, license, estimated, stamp, custom duties,
severance or withholding taxes, other taxes or similar charges of any kind
whatsoever imposed by any governmental entity, whether imposed directly on a
Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar
provision of state, local or foreign law), as a transferee or successor, by
contract or otherwise and includes any interest and penalties on or additions to
any such taxes or in respect of a failure to comply with any requirement
relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a
report, return or other information required to be supplied to a governmental
entity with respect to Taxes including, where permitted or required, combined,
unitary or consolidated returns for any group of entities.
4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan"
(as defined in Section 3(3) of the Employee Retirement Income Security Act of
1974, as amended ("ERISA")), bonus, deferred compensation, share option or other
written agreement relating to employment or fringe benefits for employees,
former employees, officers, trustees or directors of EUA or any of its
Subsidiaries effective as of the date hereof or providing benefits as of the
date hereof to current employees, former employees, officers, trustees or
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directors of EUA or pursuant to which EUA or any of its subsidiaries has or
could reasonably be expected to have any liability (collectively, the "EUA
Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure
Letter, is in material compliance with applicable law, and has been administered
and operated in all material respects in accordance with its terms. Each EUA
Employee Benefit Plan which is intended to be qualified within the meaning of
Section 401(a) of the Code has received a favorable determination letter from
the IRS as to such qualification and, to the knowledge of EUA, no event has
occurred and no condition exists which could reasonably be expected to result in
the revocation of, or have any adverse effect on, any such determination.
(b) Complete and correct copies of the following documents have
been made available to NEES as of the date of this Agreement: (i) all EUA
Employee Benefit Plans and any related trust agreements or insurance contracts,
(ii) the most current summary descriptions of each EUA Employee Benefit Plan
subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto
for each EUA Employee Benefit Plan subject to such reporting, (iv) the most
recent determination of the IRS with respect to the qualified status of each EUA
Employee Benefit Plan that is intended to qualify under Section 401(a) of the
Code, (v) the most recent accountings with respect to each EUA Employee Benefit
Plan funded through a trust and (vi) the most recent actuarial report of the
qualified actuary of each EUA Employee Benefit Plan with respect to which
actuarial valuations are conducted.
(c) Except as set forth in Section 4.11(c) of the EUA Disclosure
Letter, neither EUA nor any Subsidiary maintains or is obligated to provide
benefits under any EUA Employee Benefit Plan (other than as an incidental
benefit under a Plan qualified under Section 401(a) of the Code) which provides
health or welfare benefits to retirees or other terminated employees other than
benefit continuations as required pursuant to Section 601 of ERISA. Each EUA
Employee Benefit Plan subject to the requirements of Section 601 of ERISA has
been operated in material compliance therewith. EUA has not contributed to a
nonconforming group health plan (as defined in Code Section 5000(c)) and no
person under common control with EUA within the meaning of Section 414 of the
Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a)
that is or could reasonably be expected to be a liability of EUA's.
(d) Except as set forth in Section 4.11(d) of the EUA Disclosure
Letter, each EUA Employee Benefit Plan covers only employees who are employed by
EUA or a Subsidiary (or former employees or beneficiaries with respect to
service with EUA or a Subsidiary).
(e) Except as set forth in Section 4.11(e) of the EUA Disclosure
Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other
corporation or organization controlled by or under common control with any of
the foregoing within the meaning of Section 4001 of ERISA has, within the
five-year period preceding the date of this Agreement, at any time contributed
to any "multiemployer plan," as that term is defined in Section 4001 of ERISA.
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(f) No event has occurred, and there exists no condition or set
of circumstances in connection with any EUA Employee Benefit Plan, under which
EUA or any Subsidiary, directly or indirectly (through any indemnification
agreement or otherwise), could be subject to any liability under Section 409 of
ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code
except for instances of non-compliance which, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect.
(g) Neither EUA nor any ERISA Affiliate has incurred any
liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section
302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been
satisfied in full and no event or condition exists or has existed which could
reasonably be expected to result in any such material liability. As of the date
of this Agreement, no "reportable event" within the meaning of Section 4043 of
ERISA has occurred with respect to any EUA Employee Benefit Plan that is a
defined benefit plan under Section 3(35) of ERISA.
(h) Except as set forth in Section 4.11(h) of the EUA Disclosure
Letter, no employer securities, employer real property or other employer
property is included in the assets of any EUA Employee Benefit Plan.
(i) Full payment has been made of all material amounts which EUA
or any affiliate thereof was required under the terms of EUA Employee Benefit
Plans to have paid as contributions to such plans on or prior to the Effective
Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which
is subject to Part III of Subtitle B of Title I of ERISA has incurred any
"accumulated funding deficiency" within the meaning of Section 302 of ERISA or
Section 412 of the Code, whether or not waived.
(j) Except as set forth in Section 4.11(j) of the EUA Disclosure
Letter, no amounts payable under any EUA Employee Benefit Plan or other
agreement, contract, or arrangement will fail to be deductible for federal
income tax purposes by virtue of Section 280G or Section 162(m) of the Code.
4.12 Labor Matters. As of the date hereof, except as set forth in
Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries is a party to any material collective bargaining agreement or other
labor agreement with any union or labor organization. To the knowledge of EUA,
as of the date hereof, there is no current union representation question
involving employees of EUA or any of its Subsidiaries, nor does EUA know of any
activity or proceeding of any labor organization (or representative thereof) or
employee group to organize any such employees. Except as set forth in Section
4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice,
employment discrimination or other employment-related complaint or proceeding
against EUA or any of its Subsidiaries pending or, to the knowledge of EUA,
threatened, which has or could reasonably be expected to have an EUA Material
Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or
lockout pending, or, to the knowledge of EUA, threatened, against or involving
EUA or any of its Subsidiaries which has or could reasonably be expected to
have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim,
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suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries,
threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any
Governmental Authority investigation pending or threatened, in respect of which
any trustee, director, officer, employee or agent of EUA or any of its
Subsidiaries is or may be entitled to claim indemnification from EUA or any of
its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and
their respective articles of incorporation and by-laws, in the case of EUA's
Subsidiaries, or as provided in the indemnification agreements listed in Section
4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the
EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all
federal, state and local laws with respect to employment practices and labor
relations, including, without limitation, any provisions relating to affirmative
action, employment discrimination, wages, hours, collective bargaining, and the
payment of social security and similar taxes, safety and health regulations and
mass layoffs and plant closings except for such instances of noncompliance
which, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect.
4.13 Environmental Matters. Except as disclosed in EUA SEC Reports
filed prior to the date of this Agreement or in Section 4.13 of the EUA
Disclosure Letter:
(a) (i) Each of EUA and its Subsidiaries is in compliance with
all applicable Environmental Laws (as hereinafter defined), except where the
failure to be in compliance, in the aggregate could not reasonably be expected
to result in an EUA Material Adverse Effect; and
(ii) Neither EUA nor any of its Subsidiaries has received
any written communication from any person or Governmental Authority that alleges
that EUA or any of its Subsidiaries is not in such compliance (including the
materiality qualifier set forth in clause (i) above) with applicable
Environmental Laws.
(b) Each of EUA and its Subsidiaries has obtained all
environmental, health and safety permits and governmental authorizations
(collectively, the "Environmental Permits") necessary for the construction of
their facilities and the conduct of their operations, as applicable, and all
such Environmental Permits are in good standing or, where applicable, a renewal
application has been timely filed and agency approval is expected in the
ordinary course of business, and EUA and its Subsidiaries are in compliance with
all terms and conditions of the Environmental Permits, except where the failure
have such Environmental Permits, file a renewal application for such
Environmental Permits, or to be in compliance with such Environmental Permits,
in the aggregate could not reasonably be expected to result in an EUA Material
Adverse Effect.
(c) There is no Environmental Claim (as hereinafter defined)
that could, individually or in the aggregate, reasonably be expected to have an
EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries;
(ii) against any person or entity whose liability for any Environmental Claim
EUA or any of its Subsidiaries has or may have retained or assumed either
contractually or by operation of law; or (iii) against any real or personal
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property or operations which EUA or any of its Subsidiaries owns, leases or
manages, in whole or in part.
(d) To the knowledge of EUA there have not been any material
Releases (as hereinafter defined) of any Hazardous Material (as hereinafter
defined) that would be reasonably likely to form the basis of any material
Environmental Claim against EUA or any of its Subsidiaries, or against any
person or entity whose liability for any material Environmental Claim EUA or any
of its Subsidiaries has or may have retained or assumed either contractually or
by operation of law, except for any Environmental Claim that, individually or in
the aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
(e) To the knowledge of EUA with respect to any predecessor of
EUA or any of its Subsidiaries, there is no material Environmental Claim pending
or threatened, and there has been no Release of Hazardous Materials that could
reasonably be expected to form the basis of any material Environmental Claim
except for any Environmental Claim that, individually or in the aggregate, could
not be reasonably be expected to have an EUA Material Adverse Effect.
(f) As used in this Section 4.13:
(i) "Environmental Claim" means any and all written
administrative, regulatory or judicial actions, suits, demands, demand letters,
directives, claims, liens, investigations, proceedings or notices or
noncompliance, liability or violation by any person or entity (including any
Governmental Authority) alleging potential liability (including, without
limitation, potential responsibility or liability for enforcement, investigatory
costs, cleanup costs, governmental response costs, removal costs, remedial
costs, natural resources damages, property damages, personal injuries or
penalties) arising out of, based on or resulting from
(A) the presence, or Release or threatened Release into the
environment, of any Hazardous Materials at any
location, whether or not owned, operated, leased or
managed by EUA or any of its Subsidiaries; or
(B) circumstances forming the basis of any violation, or
alleged violation, of any Environmental Law; or
(C) any and all claims by any third party seeking damages,
contribution, indemnification, cost recovery,
compensation or injunctive relief resulting from the
presence or Release of any Hazardous Materials;
(ii) "Environmental Laws" means all federal, state and local
laws, rules and regulations and binding interpretation thereof, relating to
pollution, the environment (including, without limitation, ambient air, surface
water, groundwater, land surface or subsurface strata) or protection of human
health as it relates to the environment including, without limitation, laws and
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regulations relating to Releases or threatened Releases of Hazardous
Materials, or otherwise relating to the manufacture, generation, processing,
distribution, use, treatment, storage, disposal, transport or handling of
Hazardous Materials;
(iii) "Hazardous Materials" means (A) any petroleum or
petroleum products, radioactive materials, asbestos in any form that is or could
become friable, urea formaldehyde foam insulation, and transformers or other
equipment that contain dielectric fluid containing polychlorinated biphenyls;
and (B) any chemicals, materials or substances which are now defined as or
included in the definition of "hazardous substances", "hazardous wastes",
"hazardous materials", "extremely hazardous wastes", "restricted hazardous
wastes", "toxic substances", "toxic pollutants", or words of similar import,
under any Environmental Law; and (c) any other chemical, material, substance or
waste, exposure to which is now prohibited, limited or regulated under any
Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x)
operates or (y) stores, treats or disposes of Hazardous Materials; and
(iv) "Release" means any release, spill, emission, leaking,
injection, deposit, disposal, discharge, dispersal, leaching or migration into
the atmosphere, soil, surface water, groundwater or property.
4.14 Regulation as a Utility. (a) EUA is a public utility holding
company registered under Section 5, and subject to the provisions, of the 1935
Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA
that are "public utility companies" within the meaning of Section 2(a)(5) of the
1935 Act and lists the jurisdictions where each such Subsidiary is subject to
regulation as a public utility company or public service company. Except as set
forth above and as set forth in Section 4.14 of the EUA Disclosure Letter,
neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to
regulation as a public utility or public service company (or similar
designation) by the federal government of the United States, any state in the
United States or any political subdivision thereof, or any foreign country.
(b) As used in this Section 4.14, the terms "subsidiary company"
and "affiliate" shall have the respective meanings ascribed to them in Section
2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act.
4.15 Insurance. Except as set forth in Section 4.15 of the EUA
Disclosure Letter, each of EUA and its Subsidiaries is, and has been
continuously since January 1, 1994, insured with financially responsible
insurers in such amounts and against such risks and losses as are customary in
all material respects for companies in the United States conducting the business
conducted by EUA and its Subsidiaries during such time period. Except as set
forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries has received any notice of cancellation or termination with respect
to any material insurance policy of EUA or any of its Subsidiaries. The
insurance policies of EUA and each of its Subsidiaries are valid and enforceable
policies.
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4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of
EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power
Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a
minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described
in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities").
With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric
Company holds the required operating licenses from the NRC. With respect to the
Yankee Companies, each Yankee Company holds its own operating license from the
NRC. Because it is a minority stockholder or a minority joint owner, Montaup
Electric Company does not have responsibility for the operation of EUA Nuclear
Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or
as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge
of EUA, neither EUA nor any of its Subsidiaries is in violation of any
applicable health, safety, regulatory and other legal requirement, including NRC
laws and regulations and Environmental Laws, applicable to EUA Nuclear
Facilities except for such failure to comply as could not reasonably be expected
to have a material adverse effect with respect to EUA Nuclear Facilities and the
ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear
Facilities maintains emergency plans designed to respond to an unplanned release
therefrom of radioactive materials into the environment and insurance coverages
consistent with industry practice. EUA has funded, or has caused the funding of,
its portion of the decommissioning cost of each of the EUA Nuclear Facilities
and the storage of spent nuclear fuel consistent with the most recently approved
plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as
set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA,
no EUA Nuclear Facility is as of the date of this Agreement on the List of
Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the
NRC.
4.17 Vote Required. The affirmative vote of two-thirds of the
outstanding EUA Shares voting as a single class (with each EUA Share having one
vote per share) with respect to the approval of the Merger and other
transactions contemplated hereby is the only vote of the holders of any class or
series of equity securities of EUA or its Subsidiaries required to approve this
Agreement and approve the Merger and other transactions contemplated hereby.
4.18 Opinion of Financial Advisor. EUA has received the opinion of
Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that,
as of such date, the Merger Consideration is fair from a financial point of view
to the holders of EUA Shares. A true and complete copy of the written opinion
will be delivered to NEES promptly after receipt thereof by EUA.
4.19 Ownership of NEES Common Shares. Neither EUA nor any of its
Subsidiaries or other affiliates beneficially owns any NEES Common Shares.
4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions
so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply
to this Agreement, the Merger or other transactions contemplated hereby or
thereby.
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4.21 Year 2000. The Information Systems operated by EUA and its
Subsidiaries which is used in the conduct of their business is capable of
providing or being adapted to provide uninterrupted millennium functionality to
record, store, process and present calendar dates falling on or after January 1,
2000 in substantially the same manner and with the same functionality as such
Information Systems record, store, process and present such calendar dates
falling on or before December 31, 1999 other than such interruptions in
millennium functionality that could not, individually or in the aggregate,
reasonably be expected to result in a EUA Material Adverse Effect. EUA
reasonably believes as of the date hereof that the remaining cost of adaptations
referred to in the foregoing sentence will not exceed the amounts reflected in
the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding
the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o)
hereof and of the implementation of any recommendations by such Y2K Consultant
actually made by EUA that are not already part of EUA's compliance plan as of
the date hereof). "Information Systems" means mainframe and midrange hardware,
operating system software and applications programs; network and desktop (PC)
hardware, operating system software and applications programs; EDI (Electronic
Date Interchange) and FTP (File Transfer Protocol) software; and embedded
systems hardware and applications software.
4.22 EUA Associates. The representations and warranties set forth in
Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all
material respects with regard to EUA Associates.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES
NEES represents and warrants to EUA as follows:
5.01 Organization and Qualification. NEES is a voluntary association
duly organized, validly existing and in good standing under the laws of the
Commonwealth of Massachusetts and has full power, authority and legal right to
own its property and assets and to transact the business in which it is engaged.
Each of the NEES Subsidiaries is a corporation duly organized or incorporated,
validly existing and in good standing under the laws of its jurisdiction of
organization or incorporation and has full corporate power and authority to
conduct its business as and to the extent now conducted and to own, use and
lease its assets and properties, except where failure to be so organized or
incorporated, existing and in good standing or to have such power and authority,
individually or in the aggregate, could not reasonably be expected to have a
NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material
Adverse Effect" means a material adverse effect on the business, assets, results
of operations, condition (financial or otherwise) or prospects of NEES and its
Subsidiaries taken as a whole. LLC is a limited liability company validly
existing under the laws of the Commonwealth of Massachusetts. LLC was formed
solely for the purpose of engaging in the Merger and other transactions
contemplated hereby, has engaged in no other business activities (other than in
connection with the formation and capitalization of LLC pursuant to or in
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accordance with the LLC Agreement (as defined below)) and has conducted its
operations only as contemplated hereby and by the LLC Agreement. Each of NEES
and its Subsidiaries is duly qualified, licensed or admitted to do business and
is in good standing in each jurisdiction in which the ownership, use or leasing
of its assets and properties, or the conduct or nature of its business, makes
such qualification, licensing or admission necessary, except where failure to be
so qualified, licensed or admitted and in good standing, individually or in the
aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect. NEES has previously delivered to EUA correct and complete copies of its
Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles
of association of LLC.
5.02 Authority. Each of NEES and LLC has full power and authority to
enter into this Agreement, and to perform its obligations hereunder, and to
consummate the Merger and other transactions contemplated hereby. The execution,
delivery and performance of this Agreement by each of NEES and LLC and the
consummation by each of NEES and LLC of the Merger and other transactions
contemplated hereby have been duly authorized by all necessary corporate action
on the part of NEES and all necessary action on the part of LLC. This Agreement
has been duly and validly executed and delivered by each of NEES and LLC and
constitutes a legal, valid and binding obligation of each of NEES and LLC
enforceable against each of NEES and LLC in accordance with its terms, except as
enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
5.03 Capital Stock. The authorized equity securities of NEES consists
of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986
shares were issued and outstanding as of the close of business on January 29,
1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares
were held in the treasury of NEES. All of the issued and outstanding NEES Shares
are duly authorized, validly issued, fully paid and nonassessable. Except as may
be provided by the New England Electric System Companies' Incentive Share Plan,
the New England Electric System Companies Incentive Thrift Plan I, the New
England Electric System Companies Incentive Thrift Plan II, the New England
Electric Companies Long-Term Performance Share Award Plan, and the New England
Electric System Directors' annual retainer shares, and except as set forth in
Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES
and LLC concurrently with the execution and delivery of this Agreement (the
"NEES Disclosure Letter"), on the date hereof there are no outstanding Options
obligating NEES or any of its Subsidiaries to issue or sell any shares of equity
securities of NEES or to grant, extend or enter into any Option with respect
thereto.
5.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by each of NEES and LLC do not, and the performance
by each of NEES and LLC of its obligations hereunder and the consummation of the
Merger and other transactions contemplated hereby will not, conflict with,
result in a violation or breach of, constitute (with or without notice or lapse
of time or both) a default under, result in or give to any person any right of
payment or reimbursement, termination, cancellation, modification or
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acceleration of, or result in the creation or imposition of any Lien upon any of
the assets or properties of NEES, or LLC under, any of the terms, conditions or
provisions of (i) the NEES Agreement and Declaration of Trust or the articles of
organization of LLC, (ii) subject to the actions described in paragraph (b) of
this Section, (x) any laws or orders of any Governmental Authority applicable to
NEES or LLC or any of their respective assets or properties, or (y) subject to
obtaining the third-party consents (the "NEES Required Consents") set forth in
Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a
party or by which NEES or any of its Subsidiaries or any of their respective
assets or properties is bound, excluding from the foregoing clauses (x) and (y)
conflicts, violations, breaches, defaults, terminations, modifications,
accelerations and creations and impositions of Liens which, individually or in
the aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect.
(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by NEES or LLC or the
consummation by NEES or LLC of the Merger and other transactions contemplated
hereby except as described in Section 5.04 of the NEES Disclosure Letter or the
failure of which to obtain could not reasonably be expected to result in a NEES
Material Adverse Effect (the "NEES Required Statutory Approvals," it being
understood that references in this Agreement to "obtaining" such NEES Required
Statutory Approvals shall mean making such declarations, filings or
registrations; giving such notices; obtaining such authorizations, consents or
approvals; and having such waiting periods expire as are necessary to avoid a
violation of law).
5.05 Information Supplied. (a) The information supplied by NEES or LLC
and included in the Proxy Statement with the written consent of NEES or LLC, as
the case may be, will not, at the date mailed to EUA's Shareholders or at the
time of EUA Shareholder's Meeting, contain any untrue statements of a material
fact or omit to state any material fact required to be stated therein or
necessary in order to make the statements therein, in light of the circumstances
under which they were made, not misleading.
(b) Notwithstanding the foregoing provisions of this Section
5.05, no representation or warranty is made by NEES with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by EUA for inclusion or incorporation by reference therein or based on
information which is not made in or incorporated by reference in such documents
but which should have been disclosed pursuant to this Section 5.05.
5.06 Compliance. Except as set forth in Section 5.06 of the NEES
Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date
hereof, NEES is not in violation of, is, to the knowledge of NEES, under
investigation with respect to any violation of, or has been given notice or been
charged with any violation of, any law, statute, order, rule, regulation,
ordinance or judgment (including, without limitation, any applicable
environmental law, ordinance or regulation) of any Governmental Authority,
except for possible violations which, individually or in the aggregate, could
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not reasonably be expected to have a NEES Material Adverse Effect. Except as set
forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES
Reports filed prior to the date hereof, NEES and its Subsidiaries have all
material permits, licenses and other governmental authorizations, consents and
approvals necessary to conduct their businesses as presently conducted which are
material to the operation of the businesses of NEES. NEES is not in breach or
violation of, or in default in the performance or observance of, any term or
provision of, and no event has occurred which, with lapse of time or action by a
third party, could result in a default by NEES under (i) the NEES Agreement and
Declaration of Trust or by-laws or (ii) any contract, commitment, agreement,
indenture, mortgage, loan agreement, note, lease, bond, license, approval or
other instrument to which it is a party or by which NEES is bound or to which
any of their respective property is subject, except for possible violations,
breaches or defaults which, individually or in the aggregate, could not
reasonably be expected to have a NEES Material Adverse Effect.
5.07 Financing. NEES has or will have available, prior to the
Effective Time, sufficient cash in immediately available funds to pay or to
cause LLC to pay the Merger Consideration pursuant to Article II hereof and to
consummate the Merger and other transactions contemplated hereby.
5.08 No Vote Required. No vote of the NEES Shares or of any class or
series of equity securities of NEES or its Subsidiaries is necessary for the
approval of the Merger and other transactions contemplated hereby.
5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries
or other affiliates beneficially owns any EUA Shares.
5.10 Merger with The National Grid Group plc. NEES has entered into an
Agreement and Plan of Merger dated as of December 11, 1998 by and among The
National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly
known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to
Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of
this Agreement to National Grid Group, and National Grid Group has given NEES
its written consent to enter into this Agreement and consummate the Merger on
the terms set forth in this Agreement. Prior to the execution of this Agreement,
NEES has provided EUA with a copy of such written consent.
ARTICLE VI
COVENANTS
6.01 Covenants of EUA. At all times from and after the date hereof
until the Effective Time, EUA covenants and agrees as to itself and its
Subsidiaries that (except as expressly contemplated or permitted by this
Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to
the extent that NEES shall otherwise previously consent in writing):
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(a) Ordinary Course. EUA and each of its Subsidiaries shall
conduct their businesses only in, and EUA and each of its Subsidiaries shall not
take any action except in, the ordinary course consistent with good utility
practice. Without limiting the generality of the foregoing, EUA and its
Subsidiaries shall use all commercially reasonable efforts to preserve intact in
all material respects their present business organizations and reputation, to
maintain in effect all existing permits, to keep available the services of their
key officers and employees, to maintain their assets and properties in good
working order and condition, ordinary wear and tear excepted, to maintain
insurance on their tangible assets and businesses in such amounts and against
such risks and losses as are currently in effect, to preserve their
relationships with customers and suppliers and others having significant
business dealings with them and to comply in all material respects with all laws
and orders of all Governmental Authorities applicable to them.
(b) Charter Documents. EUA shall not, nor shall it permit any of
its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the
case of EUA, and its certificate or articles of incorporation or organization or
bylaws (or other comparable charter documents), in the case of EUA's
Subsidiaries.
(c) Dividends. EUA shall not, nor shall it permit any of its
Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other
distributions in respect of, any of its capital stock or share capital, except:
(A) that EUA may continue the declaration and payment of
regular quarterly dividends on EUA Shares with usual
record and payment dates not, in any fiscal year, in
excess of the dividend for the comparable period in the
prior fiscal year;
(B) that the Subsidiaries of EUA set forth in Section
6.01(c) of the EUA Disclosure Letter may continue the
declaration and payment of dividends on preferred stock
in accordance with the terms of such stock, with the
record and payment dates and in the amounts set forth
in Section 6.01(c) of the EUA Disclosure Letter;
(C) if the Effective Time does not occur between a record
date and payment date of a regular quarterly dividend,
for a special dividend on EUA Shares with respect to
the quarter in which the Effective Time occurs with a
record date on or prior to the date on which the
Effective Time occurs, which does not exceed an amount
equal to the product of (x) the number of days between
the last payment date of a regular quarterly dividend
and the record date of such special dividend,
multiplied by (y) $.0045; and
(D) for dividends and distributions (including liquidating
distributions) by a direct or indirect Subsidiary of
EUA to its parent.
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(ii) split, combine, subdivide, reclassify or take similar action with respect
to any of its capital stock or share capital or issue or authorize or propose
the issuance of any other securities in respect of, in lieu of or in
substitution for shares of its capital stock or comprised in its share capital,
(iii) adopt a plan of complete or partial liquidation or resolutions providing
for or authorizing such liquidation or a dissolution, merger, consolidation,
restructuring, recapitalization or other reorganization or (iv) directly or
indirectly redeem, repurchase or otherwise acquire any shares of its capital
stock or any Option with respect thereto except:
(A) in connection with intercompany purchases of capital
stock or share capital,
(B) for the purpose of funding EUA's dividend reinvestment
and share purchase plan in accordance with past
practice, or
(C) subject to EUA's obligations under the Securities Act
and the Exchange Act, pursuant to EUA's previously
announced share repurchase program provided that the
number of EUA Shares repurchased does not exceed
3,000,000 and the price paid per share does not exceed
95% of the Per Share Amount.
(d) Share Issuances. EUA shall not, nor shall it permit any of
its Subsidiaries to, issue, deliver or sell, or authorize or propose the
issuance, delivery or sale of, any shares of its capital stock or any Option
with respect thereto (other than the issuance by a wholly owned Subsidiary of
its capital stock to its direct or indirect parent corporation, or modify or
amend any right of any holder of outstanding shares of capital stock or Options
with respect thereto).
(e) Acquisitions. EUA shall not, nor shall it permit any of its
Subsidiaries to acquire or agree to acquire (by merging or consolidating with,
or by purchasing a substantial equity interest in or substantial portion of the
assets of, or by any other manner) any business or any corporation, partnership,
association or other business organization or division thereof.
(f) Dispositions. EUA shall not, nor shall it permit any of its
Subsidiaries to sell, lease, securitize, grant any security interest in or
otherwise dispose of or encumber any of its assets or properties, other than
dispositions in the ordinary course of its business consistent with past
practice and having an aggregate value of less than $1,000,000 for each
disposition and $5,000,000 in the aggregate.
(g) Indebtedness. EUA shall not, nor shall it permit any of its
Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed
or guaranteed or otherwise assumed, including, without limitation, the issuance
of debt securities or warrants or rights to acquire debt) or enter into any
"keep well" or other agreement to maintain any financial condition of another
Person or enter into any arrangement having the economic effect of any of the
foregoing other than (i) short-term indebtedness in the ordinary course of
business consistent with past practice (such as the issuance of commercial paper
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or the use of existing credit facilities) in amounts not exceeding the amounts
set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term
indebtedness in connection with the refinancing of existing indebtedness either
at its stated maturity or at a lower cost of funds (calculating such cost on an
aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in
favor of wholly owned Subsidiaries of EUA in connection with the conduct of the
business of such wholly owned Subsidiaries of EUA not aggregating more than
$1,000,000.
(h) Capital Expenditures. Except (i) as required by law or (ii)
as reasonably deemed necessary by EUA after consulting with NEES following a
catastrophic event, such as a major storm, EUA shall not, nor shall it permit
any of its Subsidiaries to make any capital expenditures or commitments during
any fiscal year that is in excess of 110% of (i) the aggregate amount set forth
in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its
Subsidiaries that are public utility companies within the meaning of Section
2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the
EUA Disclosure Letter with respect to each of EUA's other Subsidiaries.
(i) Employee Benefits. EUA shall not, nor shall it permit any of
its Subsidiaries to enter into, adopt, amend (except as may be required by
applicable law) or terminate any EUA Employee Benefit Plan, or other agreement,
arrangement, plan or policy between EUA or one of its Subsidiaries and one or
more of its trustees, directors, officers, employees or former employees, or,
except for normal increases in the ordinary course of business, (a) increase in
any manner the compensation or fringe benefits of any trustee, director or
executive officer, (b) increase in any manner the compensation or fringe
benefits of any employee, (c) pay any benefit not required by any plan or
arrangement in effect as of the date hereof or, (d) cause any trustee, director,
officer, employee or former employee of EUA to accrue or receive additional
benefits, accelerate vesting or accelerate the payment of any benefits under any
EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA,
prior to the Closing Date, shall take all necessary action and make all
necessary amendments to its stock-based plans so that all such plans will be in
a form that allows the plans to function after the Effective Time and after any
merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to
the Closing Date, shall take all necessary actions, in a manner satisfactory to
NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity
nor their affiliates' stock or securities will be required to be held in, or
distributed pursuant to, any EUA Employee Benefit Plan.
(j) Labor Matters. Notwithstanding any other provision of this
Agreement to the contrary, EUA or its Subsidiaries may negotiate successor
collective bargaining agreements to those referenced in Section 4.12 hereof, and
may negotiate other collective bargaining agreements or arrangements as required
by law or for the purpose of implementing the agreements referenced in Section
4.12 hereof. EUA will keep NEES informed as to the status of, and will consult
with NEES as to the strategy for, all negotiations with collective bargaining
representatives. EUA and its Subsidiaries shall act prudently and reasonably and
consistent with their obligation under applicable law in such negotiations.
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(k) Discharge of Liabilities. EUA shall not, nor shall it permit
its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities
or obligations (absolute, accrued, asserted or unasserted, contingent or
otherwise), other than the payment, discharge or satisfaction, in the ordinary
course of business consistent with past practice (which includes the payment of
final and unappealable judgments) or in accordance with their terms, of
liabilities reflected or reserved against in, or contemplated by, the most
recent consolidated financial statements (or the notes thereto) of such party
included in EUA SEC Reports, or incurred in the ordinary course of business
consistent with past practice.
(l) Contracts. EUA shall not, nor shall it permit its
Subsidiaries, except in the ordinary course of business consistent with past
practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to
modify, amend, terminate or fail to use commercially reasonable efforts to renew
any material Contract to which EUA or any of its Subsidiaries is a party or
waive, release or assign any material rights or claims or (ii) to enter into any
new material Contracts except as expressly permitted by Sections 6.01 (f), (g)
or (i) and 7.06 hereof.
(m) Equity Investments. EUA shall not, nor shall it permit its
Subsidiaries or affiliates to, make equity contributions to non-affiliates or to
its non-utility Subsidiaries.
(n) Loans. EUA shall not, nor shall it permit its Subsidiaries
or affiliates to, loan money to non-affiliates or to its non-utility
Subsidiaries.
(o) Year 2000. EUA, within 15 days of the date of this
Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a
detailed assessment of the adequacy and state of completion of its Year 2000
Program, including but not limited to assessment and testing of its customer,
accounting, and operational systems. The Y2K Consultant and scope of work of the
Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be
completed as soon thereafter as practicable. EUA shall have such assessment
updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA
shall allow designated NEES personnel and representatives access to the Y2K
Consultant's personnel, reports and recommendations and access to EUA's
personnel, documents, and information related to the Y2K issue. EUA and the
third party shall meet with such designated NEES personnel and representatives
on a periodic basis (but not less frequently than monthly) to update NEES on
EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section
9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K
Consultant.
(p) Insurance. EUA shall, and shall cause its Subsidiaries to,
maintain with financially responsible insurance companies (or through
self-insurance, consistent with past practice) insurance in such amounts and
against such risks and losses as are customary for companies engaged in their
respective businesses.
(q) 1935 Act. EUA shall not, nor shall it permit any of its
Subsidiaries to, engage in any activities which would cause a change in its
status, or that of its Subsidiaries, under the 1935 Act.
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(r) Regulatory Matters. Subject to applicable law and except for
non-material filings in the ordinary course of business consistent with past
practice, EUA shall consult with NEES prior to implementing any changes in its
or any of its Subsidiaries' rates or charges, standards of service or accounting
or executing any agreement with respect thereto that is otherwise permitted
under this Agreement and shall, and shall cause its Subsidiaries to, deliver to
NEES a copy of each such filing or agreement at least four (4) business days
prior to the filing or execution thereof so that NEES may comment thereon. EUA
shall, and shall cause its Subsidiaries to, make all such filings (i) only in
the ordinary course of business consistent with past practice or (ii) as
required by a Governmental Authority or regulatory agency with appropriate
jurisdiction.
(s) Accounting. EUA shall not, nor shall it permit any of its
Subsidiaries to make any changes in their accounting methods, policies or
procedures, except as required by law, rule, regulation or applicable generally
accepted accounting principles;
(t) Tax Status. Neither EUA nor any of its Subsidiaries shall
(i) make or rescind any material express or deemed election relating to Taxes,
(ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii)
settle or compromise any material claim, action, suit, litigation, proceeding,
arbitration, investigation, audit, or controversy relating to Taxes or (iv)
change in any material respect any of its methods of reporting income,
deductions or accounting for federal income tax purposes from those employed in
the preparation of its federal income Tax Return for the taxable year ending
December 31, 1997, except as may be required by applicable law.
(u) No Breach. EUA shall not, nor shall it permit any of its
Subsidiaries to willfully take or fail to take any action that would or is
reasonably likely to result in (i) a material breach of any provision of this
Agreement or (ii) its representations and warranties set forth in this Agreement
being untrue in any material respect on and as of the Closing Date.
(v) Advice of Changes. EUA shall confer with NEES on a regular
and frequent basis with respect to EUA's business and operations and other
matters relevant to the Merger to the extent permitted by law, and shall
promptly advise NEES, orally and in writing, of any material change or event,
including, without limitation, any complaint, investigation or hearing by any
Governmental Authority (or communication indicating the same may be
contemplated) or the institution or threat of material litigation; provided that
EUA shall not be required to make any disclosure to the extent such disclosure
would constitute a violation of any applicable law or regulation.
(w) Notice and Cure. EUA will notify NEES in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to EUA, that causes or will or may be likely to cause any covenant or agreement
of EUA under this Agreement to be breached or that renders or will render untrue
in any material respect any representation or warranty of EUA contained in this
Agreement. EUA also will notify NEES in writing of, and will use all
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commercially reasonable efforts to cure, before the Closing, any material
violation or breach, as soon as practical after it becomes known to EUA, of any
representation, warranty, covenant or agreement made by EUA. No notice given
pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(x) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, EUA will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to the other's obligations contained in
this Agreement and to consummate and make effective the Merger and other
transactions contemplated by this Agreement, and EUA will not, nor will it
permit any of its Subsidiaries to, take or fail to take any action that could be
reasonably expected to result in the nonfulfillment of any such condition.
(y) Third Party Standstill Agreements. Except as provided in
Section 7.08 hereto, during the period from the date of this Agreement through
the Effective Time, neither EUA nor any of its Subsidiaries shall terminate,
amend, modify or waive any provision of any confidentiality or standstill
agreement to which it is a party. During such period, EUA shall take all steps
necessary to enforce, to the fullest extent permitted under applicable law, the
provisions of any such agreement.
6.02 Covenants of NEES. At all times from and after the date hereof
until the Effective Time, NEES covenants and agrees that (except as expressly
contemplated or permitted by this Agreement or to the extent that EUA shall
otherwise previously consent in writing):
(a) No Breach. NEES shall not, nor shall it permit any of its
Subsidiaries to, except as otherwise expressly provided for in this Agreement,
willfully take or fail to take any action that would or is reasonably likely to
result in (i) a material breach of any of its covenants or agreements contained
in this Agreement or (ii) any of its representations and warranties set forth in
Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this
Agreement being untrue in any material respect on and as of the Closing Date.
(b) Advice of Changes. NEES shall confer with EUA on a regular
and frequent basis with respect to any matter having, or which, insofar as can
be reasonably foreseen, could reasonably be expected to have, a NEES Material
Adverse Effect or materially impair the ability of NEES to consummate the Merger
and other transactions contemplated hereby; provided that NEES shall not be
required to make any disclosure to the extent such disclosure would constitute a
violation of any applicable law or regulation.
(c) Notice and Cure. NEES will notify EUA in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to NEES, that causes or will or may be likely to cause any covenant or agreement
of NEES under this Agreement to be breached or that renders or will render
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untrue in any material respect any representation or warranty of NEES contained
in this Agreement. NEES also will notify EUA in writing of, and will use all
commercially reasonable efforts to cure before the Closing, any material
violation or breach, as soon as practical after it becomes known to such party,
of any representation, warranty, covenant or agreement made by NEES. No notice
given pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(d) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, NEES will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to its obligations contained in this
Agreement and to consummate and make effective the Merger and other transactions
contemplated by this Agreement, and NEES will not, nor will it permit any of its
Subsidiaries to, take or fail to take any action that could be reasonably
expected to result in the nonfulfillment of any such condition.
(e) Conduct of Business of LLC. Prior to the Effective Time,
except as may be required by applicable law and subject to the other provisions
of this Agreement, NEES shall cause LLC to (i) perform its obligations under
this Agreement in accordance with its terms, and (ii) not engage directly or
indirectly in any business or activities of any type or kind and not enter into
any agreements or arrangements with any person, or be subject to or bound by any
obligation or undertaking, which is inconsistent with this Agreement.
(f) Certain Mergers. NEES shall not, and shall not permit any of
its Subsidiaries to, acquire or agree to acquire by merging or consolidating
with, or by purchasing a substantial portion of the assets of or equity in, or
by any other manner, any business or any corporation, partnership, association
or other business organization or division thereof, or otherwise acquire or
agree to acquire any assets if the entering into of a definitive agreement
relating to or the consummation of such acquisition, merger or consolidation
could reasonably be expected to (i) impose any material delay in the obtaining
of, or significantly increase the risk of not obtaining, any authorizations,
consents, orders, declarations or approvals of any Governmental Authority
necessary to consummate the Merger or the expiration or termination of any
applicable waiting period, (ii) significantly increase the risk of any
Governmental Authority entering an order prohibiting the consummation of the
Merger, (iii) significantly increase the risk of not being able to remove any
such order on appeal or otherwise or (iv) materially delay the consummation of
the Merger.
6.03 Additional Covenants by NEES and EUA.
(a) Control of Other Party's Business. Nothing contained in this
Agreement shall give NEES, directly or indirectly, the right to control or
direct EUA's operations prior to the Effective Time. Nothing contained in this
Agreement shall give EUA, directly or indirectly, the right to control or direct
NEES' operations prior to the Effective Time. Prior to the Effective Time, each
of EUA and NEES shall exercise, consistent with the terms and conditions of this
Agreement, complete control and supervision over its respective operations.
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(b) Transition Steering Team. As soon as reasonably practicable
after the date hereof, NEES and EUA shall create a special transition steering
team, with representation from EUA and NEES, that will develop recommendations
concerning the future structure and operations of EUA after the Effective Time,
subject to applicable law. The members of the transition steering team shall be
appointed by the Chief Executive Officers of NEES and EUA. The functions of the
transition steering team shall include (i) to direct the exchange of information
and documents between the parties and their Subsidiaries as contemplated by
Section 7.01 and (ii) the development of regulatory plans and proposals,
corporate organizational and management plans, workforce combination proposals,
and such other matters as they deem appropriate.
ARTICLE VII
ADDITIONAL AGREEMENTS
7.01 Access to Information. EUA shall, and shall cause each of its
Subsidiaries to, and shall use commercially reasonable efforts to cause EUA
Associates to, throughout the period from the date hereof to the Effective Time
to the extent permitted by law, (i) provide NEES and its Representatives with
full access, upon reasonable prior notice and during normal business hours, to
all facilities, operations, officers (including EUA's environmental, health and
safety personnel), employees, agents and accountants of EUA and its Subsidiaries
and Associates and their respective assets, properties, books and records, to
the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal
obligation not to provide access or to the extent that such access would not
constitute a waiver of the attorney client privilege and does not unreasonably
interfere with the business and operations of EUA and its Subsidiaries and
Associates and (ii) furnish promptly to such persons (x) a copy of each report,
statement, schedule and other document filed or received by EUA or any of its
Subsidiaries pursuant to the requirements of federal or state securities laws
and each material report, statement, schedule and other document filed with any
other Governmental Authority, and (y) all other information and data (including,
without limitation, copies of Contracts, EUA Employee Benefit Plans, and other
books and records) concerning the business and operations of EUA and its
Subsidiaries as NEES or any of its Representatives reasonably may request. No
review pursuant to this Section 7.01 or otherwise shall affect any
representation or warranty contained in this Agreement or any condition to the
obligations of the parties hereto. Any such information or material obtained
pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such
term is defined in the letter agreement dated as of December 18, 1998 between
EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms
of the Confidentiality Agreement. NEES may provide information or materials that
it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01
to National Grid Group; the treatment by National Grid Group of such information
or material shall be governed by the terms of the letter agreement dated as of
December 21, 1998 between EUA and National Grid Group.
7.02 Proxy Statement. As soon as reasonably practicable after the
date of this Agreement, EUA shall prepare and file the Proxy Statement with the
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SEC. NEES and EUA shall cooperate with each other in the preparation of the
Proxy Statement and any amendment or supplement thereto, and EUA shall promptly
notify NEES of the receipt of any comments of the SEC with respect to the Proxy
Statement and of any requests by the SEC for any amendment or supplement thereto
or for additional information, and shall promptly provide to NEES copies of all
correspondence between EUA or any of its Representatives and the SEC with
respect to the Proxy Statement (except reports from financial advisors other
than with the consent of such financial advisors). Each of the parties hereto
shall furnish all information concerning itself which is required or customary
for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the
Proxy Statement and have due regard to any comments NEES may make in relation to
the Proxy Statement. EUA shall give NEES and its counsel the opportunity to
review the Proxy Statement and all responses to requests for additional
information by and replies to comments of the SEC before their being filed with,
or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best
efforts, after consultation with the other parties hereto, to respond promptly
to all such comments of and requests by the SEC. After obtaining the consent of
EUA, which consent shall not be unreasonably withheld, NEES may provide
information supplied to NEES by EUA to National Grid Group for inclusion of such
information in the Super Class 1 circular ("NGG Circular") to be issued to
shareholders of National Grid Group in connection with approval by such
shareholders of the National Grid Merger Agreement. NEES shall use its best
efforts to provide EUA with a draft of any portion of the NGG Circular with
information relating to EUA prior to the issuance of the NGG Circular.
7.03 Approval of Shareholders. EUA shall, through its Board of
Trustees, duly call, give notice of, convene and hold a meeting of its
shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the
approval of the Merger and other transactions contemplated hereby (the "EUA
Shareholders' Approval") as soon as reasonably practicable after the date
hereof; provided, however, subject to the fiduciary duties of its Board of
Trustees and the requirements of applicable law, EUA shall include in the Proxy
Statement the recommendation of the Board of Trustees of EUA that the
Shareholders of EUA approve the Merger and the other transactions contemplated
hereby, and shall use its reasonable best efforts to obtain such approval.
7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party
hereto shall file or cause to be filed with the Federal Trade Commission and the
Department of Justice any notifications required to be filed by its respective
"ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated
thereunder with respect to the Merger and other transactions contemplated
hereby. Such parties will use all commercially reasonable efforts to make such
filings in a timely manner and to respond on a timely basis to any requests for
additional information made by either of such agencies.
(b) Other Regulatory Approvals. Each party shall cooperate and
use its best efforts to promptly prepare and file all necessary applications,
notices, petitions, filings and other documents with, and to use all
commercially reasonable efforts to obtain all necessary permits, consents,
approvals and authorizations of, all Governmental Authorities necessary or
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advisable to obtain the EUA Required Statutory Approvals, the NEES Required
Statutory Approvals and the approvals of the state utility commissions referred
to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The
parties agree that they will consult with each other with respect to obtaining
the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have
primary responsibility for the preparation and filing of any related
applications, filings or other material with the SEC, the FERC, the NRC and
state utility commissions. EUA shall have the right to review and approve in
advance drafts of and final applications, filings and other material (including
material with respect to proposed settlements) submitted to or filed with the
SEC, the FERC, the NRC and state utility commissions or parties to such
proceedings before such Governmental Authority, which approval shall not be
unreasonably withheld or delayed.
(c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge
that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA
Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the
regulatory approvals (the "NEES-NGG Regulatory Approvals") required to
consummate the transactions contemplated by the National Grid Merger Agreement.
NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA
Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the
prosecution by National Grid Group and NEES of the proceedings relating to the
NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but
recognize that one or more of the NEES-EUA Regulatory Proceedings may be
consolidated with one or more of the NEES-NGG Regulatory Proceedings by the
relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA
reasonably apprised of the status of the NEES-NGG Regulatory Proceedings.
7.05 Employee Benefit Plans.
(a) For a period of twelve (12) months immediately following the
Closing Date, the compensation, benefits and coverage provided to those
non-union individuals who continue to be employees of the Surviving Entity (the
"Affected Employees") pursuant to employee benefit plans or arrangements
maintained by NEES or the Surviving Entity shall be, in the aggregate, not less
favorable (as determined by NEES and the Surviving Entity using reasonable
assumptions and benefit valuation methods) than those provided, in the
aggregate, to such Affected Employees immediately prior to the Closing Date. In
addition to the foregoing, NEES shall, or shall cause the Surviving Entity to,
pay any Affected Employee whose employment is terminated by NEES or the
Surviving Entity within twelve (12) months of the Closing Date a severance
benefit package equivalent to the severance benefit package that would be
provided under the NEES Standard Severance Plan as in effect on the date hereof.
(b) NEES shall, or shall cause the Surviving Entity to, give the
Affected Employees full credit for purposes of eligibility, vesting, benefit
accrual (including, without limitation, benefit accrual under any defined
benefit pension plans) and determination of the level of benefits under any
employee benefit plans or arrangements maintained by NEES or the Surviving
Entity in effect as of the Closing Date for such Affected Employees' service
with EUA or any Subsidiary of EUA (or any prior employer) to the same extent
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recognized by EUA or such Subsidiary immediately prior to the Closing Date. With
respect to any employee benefit plan or arrangement established by NEES, EUA or
the Surviving Entity after the Closing Date (the "Post Closing Plans"), service
shall be credited in accordance with the terms of such Post Closing Plans.
(c) NEES shall, or shall cause the Surviving Entity to, (i)
waive all limitations as to preexisting conditions, exclusions and waiting
periods with respect to participation and coverage requirements applicable to
the Affected Employees under any welfare benefit plan established to replace any
EUA welfare benefit plans in which such Affected Employees may be eligible to
participate after the Closing Date, other than limitations or waiting periods
that are already in effect with respect to such Affected Employees and that have
not been satisfied as of the Closing Date under any welfare plan maintained for
the Affected Employees immediately prior to the Closing Date, and (ii) provide
each Affected Employee with credit for any co-payments and deductibles paid
prior to the Closing Date in satisfying any applicable deductible or
out-of-pocket requirements under any welfare plans that such Affected Employees
are eligible to participate in after the Closing Date.
(d)(i) NEES shall, or shall cause the Surviving Entity and its
Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect
on the date hereof; provided, however, that this Section 7.05(d)(i) is not
intended to prevent NEES or the Surviving Entity from exercising their rights
with respect to all EUA Employee Benefit Plans solely in accordance with their
terms, including but not limited to the right to alter, terminate or otherwise
amend such EUA Employee Benefit Plans.
(ii) NEES shall, or shall cause the Surviving Entity and
its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, (A) all employment severance, consulting and
retention agreements or arrangements as in effect on the date hereof, as set
forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in
accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or
arrangements, the "EUA Employee Agreements" and the individuals who are parties
to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee
Benefit Plans in which such EUA Executives participate; provided, however, that
this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity
from exercising their rights with respect to the EUA Employee Agreements and the
EUA Employee Benefit Plans in which such EUA Executives participate, in each
case solely in accordance with their terms, including but not limited to the
right to alter, terminate or otherwise amend such EUA Employee Agreements and
EUA Employee Benefit Plans.
(e) Notwithstanding the foregoing, NEES and the Surviving Entity
and its subsidiaries shall neither be required to or prevented from merging
EUA's benefit plans, agreements, or arrangements into NEES or the Surviving
Entity and its subsidiaries benefit plans, agreements, or arrangements or from
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replacing EUA's benefit plans, agreements or arrangements with NEES or the
Surviving Entity and its subsidiaries benefit plans, agreements or arrangements.
7.06 Labor Agreements and Workforce Matters.
(a) Labor Agreements. NEES shall honor, or shall cause the
appropriate subsidiaries of the Surviving Entity to honor, all collective
bargaining agreements of EUA or its subsidiaries in effect as of the Effective
Time until their expiration; provided, however, that this undertaking is not
intended to prevent NEES or the Surviving Entity and its subsidiaries from
exercising their rights with respect to such collective bargaining agreements
and in accordance with their terms, including any right to amend, modify,
suspend, revoke or terminate any such contract, agreement, collective bargaining
agreement or commitment or portion thereof.
(b) Workforce Matters. Subject to applicable law and obligations
under applicable collective bargaining agreements, for a period of 2 years
following the Effective Time, any reductions in workforce in respect of
employees of the Surviving Entity and its Subsidiaries shall be made on a fair
and equitable basis as determined by the Surviving Entity, with due
consideration to prior experience and skills, and any employee whose employment
is terminated or job is eliminated during such period shall be entitled to
participate on a fair and equitable basis as determined by NEES or the Surviving
Entity in the job opportunity and employment placement programs offered by NEES
or the Surviving Entity or any of their Subsidiaries for which they are
eligible. Any workforce reductions carried out following the Effective Time by
the Surviving Entity and its Subsidiaries shall be done in accordance with all
applicable collective bargaining agreements and all laws and regulations
governing the employment relationship and termination thereof including, without
limitation, the Worker Adjustment and Retraining Notification Act, and the
regulations promulgated thereunder, and any comparable state or local law.
7.07 Post Merger Operations.
(a) NEES Advisory Board. If the Merger is consummated, then,
promptly following the closing of the merger contemplated by the National Grid
Merger Agreement, NEES shall take such action as is necessary to cause all of
the members of the Board of Directors of EUA to be appointed to serve on the
advisory board to be formed pursuant to Section 7.07(e) of the National Grid
Merger Agreement.
(b) Charities. The parties agree that provision of charitable
contribution and community support within the New England region serves a number
of important goals. After the Effective Time, NEES intends to cause the
Surviving Entity to provide charitable contributions and community support
within the New England region at annual levels substantially comparable to the
annual level of charitable contributions and community support provided,
directly or indirectly, by EUA and its public utility subsidiaries within the
New England region during 1998.
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7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a)
that neither it nor any of its Subsidiaries shall, and it shall use its best
efforts to cause its Representatives (as defined in Section 10.10) not to,
knowingly initiate, solicit or encourage, directly or indirectly, any inquiries
or any proposal or offer (including, without limitation, any proposal or offer
to its Shareholders) with respect to a merger, consolidation or other business
combination including EUA or any of its significant Subsidiaries (as defined in
Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than
EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or
similar transaction (including, without limitation, a tender or exchange offer)
involving the purchase of (i) all or any significant portion of the assets of
EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the
outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the
capital stock of any EUA Significant Subsidiary (any such proposal or offer
being hereinafter referred to as an "Alternative Proposal"), or engage in any
negotiations concerning, or provide any confidential information or data to, or
have any other discussions with, any person or group relating to an Alternative
Proposal, or otherwise knowingly facilitate any effort or attempt to make or
implement an Alternative Proposal other than from NEES and its affiliates; (b)
that it will immediately cease and cause to be terminated any existing
activities, discussions or negotiations with any parties with respect to any
Alternative Proposal; and (c) that it will notify NEES immediately if any such
inquiries, proposals or offers are received by, any such information is
requested from, or any such negotiations or discussions are sought to be
initiated or continued with, it or any of such persons; provided, however, that,
prior to receipt of the EUA Shareholders' Approval, nothing contained in this
Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing
information to (but only pursuant to a confidentiality agreement in customary
form and having terms and conditions no less favorable to EUA than the
Confidentiality Agreement (as defined in Section 7.01)) or entering into
discussions or negotiations with any person or group that makes an unsolicited
Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees
of EUA, based upon advice of outside counsel with respect to fiduciary duties,
determines in good faith that such action is necessary for the Board of Trustees
to act in a manner consistent with its fiduciary duties to Shareholders under
applicable law, (B) the Board of Trustees of EUA has reasonably concluded in
good faith (after consultation with its financial advisors) that the person or
group making such Alternative Proposal will have adequate sources of financing
to consummate such Alternative Proposal and that such Alternative Proposal is
likely to be more favorable to EUA's shareholders than the Merger, (C) prior to
furnishing such information to, or entering into discussions or negotiations
with, such person or group, EUA provides written notice to NEES to the effect
that it is furnishing information to, or entering into discussions or
negotiations with, such person or group, which notice shall identify such person
or group and the material terms of the Alternative Proposal in reasonable
detail, and (D) EUA keeps NEES promptly informed of the status and all material
information with respect to any such discussions or negotiations; and (ii) to
the extent required, complying with Rule 14e-2 promulgated under the Exchange
Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall
(x) permit EUA to terminate this Agreement (except as specifically provided in
Article IX), (y) permit EUA to enter into any agreement with respect to an
Alternative Proposal for so long as this Agreement remains in effect (it being
agreed that for so long as this Agreement remains in effect, EUA shall not enter
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into any agreement with any person or group that provides for, or in any way
knowingly facilitates, an Alternative Proposal (other than a confidentiality
agreement under the circumstances described above)), or (z) affect any other
obligation of EUA under this Agreement.
7.09 Directors' and Officers' Indemnification and Insurance.
(a) Indemnification. To the extent, if any, not provided by an
existing right of indemnification or other agreement or policy, from and after
the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the
fullest extent permitted by applicable law, indemnify, defend and hold harmless
each person who is now, or has been at any time prior to the date hereof, or who
becomes prior to the Effective Time, (x) an officer, trustee or director or (y)
an employee covered as of the date hereof (to the extent of the coverage
extended as of the date hereof) of EUA or any Subsidiary of EUA (each an
"Indemnified Party," and collectively, the "Indemnified Parties") against (i)
all losses, expenses (including reasonable attorney's fees and expenses),
claims, damages or liabilities or, subject to the first proviso of the next
succeeding sentence, amounts paid in settlement, arising out of actions or
omissions occurring at or prior to the Effective Time (and whether asserted or
claimed prior to, at or after the Effective Time) that are, in whole or in part,
based on or arising out of the fact that such person is or was a director,
trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified
Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based
on or arise out of or pertain to the transactions contemplated by this
Agreement, in each case, to the extent permitted by the EUA Trust Agreement or
the indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter. In the event of any such loss, expense, claim, damage or liability
(whether or not arising before the Effective Time), (i) NEES shall, or shall
cause the Surviving Entity to, pay the reasonable fees and expenses of counsel
selected by the Indemnified Parties, which counsel shall be reasonably
satisfactory to NEES or the Surviving Entity, as appropriate, promptly after
statements therefor are received and otherwise advance to such Indemnified Party
upon request, reimbursement of documented expenses reasonably incurred, in
either case to the extent not prohibited by the EUA Trust Agreement or the
indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter upon receipt of an undertaking by or on behalf of such director, trustee
or officer to repay such amounts as and to the extent required by the EUA Trust
Agreement or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of
any such matter and (iii) any determination required to be made with respect to
whether an Indemnified Party's conduct complies with the standards set forth
under the EUA Trust Agreement or the indemnification agreements set forth in
Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation
or by-laws or similar governing documents of the Surviving Entity shall be made
by independent counsel mutually acceptable to the Surviving Entity and the
Indemnified Party; provided, however, that the Surviving Entity shall not be
liable for any settlement effected without its written consent (which consent
shall not be unreasonably withheld) and provided further that no indemnification
shall be made if such indemnification is prohibited by the EUA Trust Agreement
or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter.
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(b) Insurance. For a period of six years after the Effective
Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be
maintained in effect an extended reporting period for current policies of
directors' and officers' liability insurance for the benefit of such persons who
are currently covered by such policies of EUA on terms no less favorable than
the terms of such current insurance coverage or (ii) shall provide tail coverage
for such persons which provides such persons with coverage for a period of six
years for acts prior to the Effective Time on terms no less favorable than the
terms of such current insurance coverage.
(c) Successors. In the event the Surviving Entity or any of its
successors or assigns (i) consolidates with or merges into any other person or
entity and shall not be the continuing or surviving corporation or entity of
such consolidation or merger or (ii) transfers all or substantially all of its
properties and assets to any person or entity, then and in either such case,
proper provisions shall be made so that the successors and assigns of the
Surviving Entity, as applicable, shall assume the obligations set forth in this
Section 7.09.
(d) Survival of Indemnification. To the fullest extent permitted
by law, from and after the Effective Time, all rights to indemnification as of
the date hereof in favor of the employees, agents, directors, trustees and
officers of EUA and EUA's Subsidiaries with respect to their activities as such
prior to the Effective Time, as provided in the EUA Trust Agreement or the
respective certificates of incorporation and by-laws or similar governing
documents in effect on the date hereof, or otherwise in effect on the date
hereof, shall survive the Merger and shall continue in full force and effect for
a period of not less than six years from the Effective Time.
(e) Benefit. The provisions of this Section 7.09 are intended to
be for the benefit of, and shall be enforceable by, each Indemnified Party, his
or her heirs and his or her representatives.
(f) Amendment of the EUA Trust Agreement. NEES shall not, and
shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement
to in any way limit the indemnification provided to the Indemnified Parties
under this Section 7.09.
7.10 Expenses. Except as set forth in Section 9.03, whether or not
the Merger is consummated, all costs and expenses incurred in connection with
the Merger and other transactions contemplated hereby shall be paid by the party
incurring such cost or expense, except that the filing fees in connection with
the filings required under the HSR Act and the 1935 Act shall be paid by NEES.
7.11 Brokers or Finders. EUA represents, as to itself and its
affiliates, that no agent, broker, investment banker, financial advisor or other
firm or person is or will be entitled to any broker's, finder's or investment
banker's fee or any other commission or similar fee in connection with the
Merger and other transactions contemplated by this Agreement except Salomon
Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance
with EUA's agreement with such firm, and EUA shall indemnify and hold NEES
harmless from and against any and all claims, liabilities or obligations with
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respect to any other such fee or commission or expenses related thereto asserted
by any person on the basis of any act or statement alleged to have been made by
EUA or its affiliates.
7.12 Anti-Takeover Statutes. If any "fair price", "moratorium",
"business combination", "control share acquisition" or other form of
anti-takeover statute or regulation shall become applicable to the Merger or
other transactions contemplated hereby, EUA and the members of the Board of
Trustees of EUA shall grant such approvals and take such actions consistent with
their fiduciary duties and in accordance with applicable law as are reasonably
necessary so that the Merger and other transactions contemplated hereby may be
consummated as promptly as practicable on the terms contemplated hereby and
otherwise act to eliminate or minimize the effects of such statute or regulation
on the Merger and other transactions contemplated hereby.
7.13 Public Announcements. Except as otherwise required by law or the
rules of any applicable securities exchange or national market system or any
other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA
will not, and will not permit any of their respective Subsidiaries or
Representatives to, issue or cause the publication of any press release or make
any other public announcement with respect to the Merger and other transactions
contemplated by this Agreement without the consent of the other party, which
consent shall not be unreasonably withheld. NEES and EUA will cooperate with
each other in the development and distribution of all press releases and other
public announcements with respect to the Merger and other transactions
contemplated hereby, and will furnish the other with drafts of any such releases
and announcements as far in advance as practicable.
7.14 Restructuring of the Merger. It may be preferable to effectuate
a business combination between NEES and EUA by means of an alternative structure
to the Merger. Accordingly, if, prior to satisfaction of the conditions
contained in Article VIII hereto, NEES proposes the adoption of an alternative
structure that otherwise substantially preserves for NEES and EUA the economic
benefits of the Merger and will not materially delay the consummation thereof,
then the parties shall use their respective best efforts to effect a business
combination among themselves by means of a mutually agreed upon structure other
than the Merger that so preserves such benefits; provided, however, that prior
to closing any such restructured transaction, all material third party and
Governmental Authority declarations, filings, registrations, notices,
authorizations, consents or approvals necessary for the effectuation of such
alternative business combination shall have been obtained and all other
conditions to the parties' obligations to consummate the Merger and other
transactions contemplated hereby, as applied to such alternative business
combination, shall have been satisfied or waived.
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ARTICLE VIII
CONDITIONS
8.01 Conditions to Each Party's Obligation to Effect the Merger. The
respective obligation of each party to effect the Merger and other transactions
contemplated hereby is subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following conditions:
(a) Shareholder Approval. EUA Shareholders' Approval shall have
been obtained.
(b) HSR Act. Any waiting period (and any extension thereof)
applicable to the consummation of the Merger under HSR shall have expired or
been terminated.
(c) Injunctions or Restraints. No court of competent
jurisdiction or other competent Governmental Authority shall have enacted,
issued, promulgated, enforced or entered any law or order (whether temporary,
preliminary or permanent) which is then in effect and has the effect of making
illegal or otherwise restricting, preventing or prohibiting consummation of the
Merger or other transactions contemplated hereby.
(d) Governmental and Regulatory and Other Consents and
Approvals. The NEES Required Statutory Approvals and EUA Required Statutory
Approvals shall have been obtained prior to the Effective Time, and shall have
become Final Orders (as hereinafter defined). The Final Orders shall not,
individually or in the aggregate, impose terms and conditions that (i) could
reasonably be expected to have an EUA Material Adverse Effect; (ii) could
reasonably be expected to have a NEES Material Adverse Effect; or (iii)
materially impair the ability of the parties to complete the Merger. The parties
shall have received Final Orders from the Massachusetts Department of
Telecommunications and Energy and the Rhode Island Public Utilities Commission
pertaining to the recovery of costs (including, without limitation, transaction
premium and integration costs) associated with the Merger that are materially
consistent with existing policy and previous orders of such agencies. "Final
Order" for all purposes of this Agreement means action by the relevant
regulatory authority which has not been reversed, stayed, enjoined, set aside,
annulled or suspended with respect to which any waiting period prescribed by law
before the Merger and other transactions contemplated hereby may be consummated
has expired, and as to which all conditions to be satisfied before the
consummation of such transactions prescribed by law, regulation or order have
been satisfied.
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger.
The obligation of NEES and LLC to effect the Merger and other transactions
contemplated hereby is further subject to the satisfaction or waiver at or prior
to the Closing, of each of the following additional conditions (all or any of
which may be waived in whole or in part by NEES and LLC in the sole discretion):
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(a) Representations and Warranties. The representations and
warranties made by EUA in this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "EUA Material Adverse Effect", shall be true and correct as so
made as of the Closing Date as though so made on and as of the Closing Date,
except to the extent expressly given as of a specified date, except where the
failure of such representations and warranties to be true and correct as so made
does not have and could not reasonably be expected to have, individually or in
the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to
NEES a certificate, dated the Closing Date and executed in the name and on
behalf of EUA by its Chairman of the Board, President or any Executive or Senior
Vice President, to such effect.
(b) Performance of Obligations. EUA shall have performed and
complied with, in all material respects, each agreement, covenant and obligation
required by this Agreement to be so performed or complied with by EUA at or
prior to the Closing, and EUA shall have delivered to NEES a certificate, dated
the Closing Date and executed in the name and on behalf of EUA by its Chairman
of the Board, President or any Executive or Senior Vice President, to such
effect.
(c) Material Adverse Effect. No EUA Material Adverse Effect
shall have occurred and there shall exist no facts or circumstances which in the
aggregate could reasonably be expected to have an EUA Material Adverse Effect.
(d) EUA Required Consents. All EUA Required Consents shall have
been obtained by EUA, except where the failure to receive such EUA Required
Consents could not reasonably be expected to (i) have an EUA Material Adverse
Effect, or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
8.03 Conditions to Obligation of EUA to Effect the Merger. The
obligation of EUA to effect the Merger and other transactions contemplated
hereby is further subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following additional conditions (all or any of which may
be waived in whole or in part by EUA in its sole discretion):
(a) Representations and Warranties. The representations and
warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07,
5.08 and 5.09 of this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "NEES Material Adverse Effect," shall be true and correct as so
made as of the Closing Date, except to the extent expressly given as of a
specified date and except where the failure of such representations and
warranties to be so true and correct as so made does not have and could not
reasonably be expected to have, individually or in the aggregate, a NEES
Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC
shall each have delivered to EUA a certificate, dated the Closing Date and
executed in the name and on behalf of NEES by any director of NEES and in the
name and on behalf of LLC by a member of its management committee its Chairman
of the Board, President or any Executive or Senior Vice President to such
effect.
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(b) NEES Required Consents. All NEES Required Consents shall
have been obtained by NEES, except where the failure to receive such NEES
Required Consents could not reasonably be expected to (i) have a NEES Material
Adverse Effect or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
(c) Performance of Obligations. NEES and LLC shall have
performed and complied with, in all material respects, each agreement, covenant
and obligation required by this Agreement to be so performed or complied with by
NEES or LLC at or prior to the Closing, and NEES and LLC shall each have
delivered to EUA a certificate, dated the Closing Date and executed in the name
and on behalf of NEES by its Chairman of the Board, President or any Executive
or Senior Vice President, or on behalf of LLC by a member of its management
committee to such effect.
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER
9.01 Termination. This Agreement may be terminated, and the Merger
and other transactions contemplated hereby may be abandoned, at any time prior
to the Effective Time, whether prior to or after EUA Shareholders' Approval
(except as otherwise provided in Section 9.01(c) below):
(a) By mutual written agreement of the Board of Directors of
NEES and Board of Trustees of EUA, respectively;
(b) By EUA or NEES, by written notice to the other, if the
Closing Date shall not have occurred on or before December 31, 1999 (the
"Initial Termination Date"); provided, however, that the right to terminate the
Agreement under this Section 9.01(b) shall not be available to any party whose
failure to fulfill any obligation under this Agreement has been the cause of, or
resulted in, the failure of the Effective Time to occur on or before such date;
and provided, further, that if on the Initial Termination Date the conditions to
the Closing set forth in Section 8.01(d) shall not have been fulfilled but all
other conditions to the Closing shall be fulfilled or shall be capable of being
fulfilled, then the Initial Termination Date shall be extended for four (4)
months beyond the Initial Termination Date (the "Extended Termination Date");
(c) By NEES, by written notice to EUA, if EUA Shareholders'
Approval shall not have been obtained at a duly held meeting of such
Shareholders, including any adjournments thereof;
(d) By EUA or NEES, if any applicable state or federal law or
applicable law of a foreign jurisdiction or any order, rule or regulation is
adopted or issued that has the effect, as supported by the written opinion of
outside counsel for such party, of prohibiting the Merger or other transactions
contemplated hereby, or if any court of competent jurisdiction or any
Governmental Authority shall have issued a nonappealable final order, judgment
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or ruling or taken any other action having the effect of permanently
restraining, enjoining or otherwise prohibiting the Merger or other transactions
contemplated hereby (provided that the right to terminate this Agreement under
this Section 9.01(d) shall not be available to any party that has not defended
such lawsuit or other legal proceeding (including seeking to have any stay or
temporary restraining order entered by any court or other Governmental Authority
vacated or reversed)).
(e) By EUA upon ten (10) days' prior notice to NEES if the Board
of Trustees of EUA determines in good faith, that termination of this Agreement
is necessary for the Board of Trustees of EUA to act in a manner consistent with
its fiduciary duties to Shareholders under applicable law by reason of an
unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B)
of Section 7.08 having been made; provided that
(A) The Board of Trustees of EUA shall determine based
on advice of outside counsel with respect to the Board of
Trustees' fiduciary duties that notwithstanding a binding
commitment to consummate an agreement of the nature of this
Agreement entered into in the proper exercise of its applicable
fiduciary duties, and notwithstanding all concessions which may
be offered by NEES in negotiation entered into pursuant to clause
(B) below, it is necessary pursuant to such fiduciary duties that
the trustees reconsider such commitment as a result of such
Alternative Proposal, and
(B) prior to any such termination, EUA shall, and
shall cause its respective financial and legal advisors to,
negotiate with NEES to make such adjustments in the terms and
conditions of this Agreement as would enable EUA to proceed with
the Merger or other transactions contemplated hereby on such
adjusted terms;
and provided further that EUA's ability to terminate this Agreement pursuant to
this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES
of any amounts owed by it pursuant to Section 9.03(a);
(f) By EUA, by written notice to NEES, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of NEES hereunder (other than a breach
described in clause (ii)), and such breach shall not have been remedied within
twenty (20) days after receipt by NEES of notice in writing from EUA, specifying
the nature of such breach and requesting that it be remedied; or (ii) NEES shall
fail to deliver or cause to be delivered the amount of cash to the Paying Agent
required pursuant to Section 2.02(a) at a time when all conditions to NEES's
obligation to close have been satisfied or otherwise waived in writing by NEES.
(g) By NEES, by written notice to EUA, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of EUA hereunder, and such breach shall not
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have been remedied within twenty (20) days after receipt by EUA of notice in
writing from NEES, specifying the nature of such breach and requesting that it
be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify
in any manner adverse to NEES its approval of the Merger and other transactions
contemplated hereby or its recommendation to its shareholders regarding the
approval of this Agreement, the Merger and other transactions contemplated
hereby, (B) shall approve or recommend or take no position with respect to an
Alternative Proposal or (C) shall resolve to take any of the actions specified
in clause (A) or (B).
9.02 Effect of Termination. If this Agreement is validly terminated
by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith
become null and void and there shall be no liability or obligation on the part
of either EUA or NEES (or any of their respective Representatives or
affiliates), except that the provisions of this Section 9.02, Sections 7.10,
7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply
following any such termination.
9.03 Termination Fees. (a) In the event that (i) this Agreement is
terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall
have made an Alternative Proposal that has not been withdrawn and this Agreement
is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B)
by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a
definitive agreement with respect to such Alternative Proposal is executed
within two years after such termination, then EUA shall pay to NEES, by wire
transfer of same day funds, either on the date contemplated in Section 9.01(e)
if applicable, or otherwise, within five (5) business days after such
termination, a termination fee of $20 million, plus an amount equal to all
documented out-of-pocket expenses and fees incurred by NEES arising out of, or
in connection with or related to, the Merger and other transactions contemplated
hereby, not in excess of $5 million in the aggregate.
(b) In the event that this Agreement is terminated by either
NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i)
the conditions to the Closing set forth in Section 8.01(d) shall not have been
fulfilled, (ii) if the date of termination is any date other than a date which
is on or after the Extended Termination Date, all conditions contained in
Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or
are capable of being fulfilled as of such date, and (iii) the merger
contemplated by the National Grid Merger Agreement has not yet been consummated,
then NEES shall pay to EUA, by wire transfer of same day funds, within five (5)
business days after such termination, a termination fee of $10 million, plus an
amount equal to all documented out-of-pocket expenses and fees incurred by EUA
arising out of, or in connection with or related to, the Merger and other
transactions contemplated hereby, not in excess of $5 million in the aggregate.
(c) Nature of Fees. The parties agree that the agreements
contained in this Section 9.03 are an integral part of the Merger and the other
transactions contemplated hereby and constitute liquidated damages and not a
penalty. The parties further agree that if any party is or becomes obligated to
pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive
such termination fee shall be the sole remedy of the other party with respect to
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the facts and circumstances giving rise to such payment obligation. If this
Agreement is terminated by a party as a result of a willful breach of a
representation, warranty, covenant or agreement by the other party, including a
termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue
any remedies available to it at law or in equity and shall be entitled to
recover any additional amounts thereunder. Notwithstanding anything to the
contrary contained in this Section 9.03, if one party fails to promptly pay to
the other any fee or expense due under this Section 9.03, in addition to any
amounts paid or payable pursuant to such Section, the defaulting party shall pay
the costs and expenses (including legal fees and expenses) in connection with
any action, including the filing of any lawsuit or other legal action, taken to
collect payment, together with interest on the amount of any unpaid fee at the
publicly announced prime rate of Citibank, N.A. from the date such fee was
required to be paid.
9.04 Amendment. This Agreement may be amended, supplemented or
modified by action taken by or on behalf of the Board of Directors of NEES or
the Board of Trustees of EUA at any time prior to the Effective Time, whether
prior to or after EUA Shareholders' Approval shall have been obtained, but after
such adoption and approval only to the extent permitted by applicable law. No
such amendment, supplement or modification shall be effective unless set forth
in a written instrument duly executed and delivered by or on behalf of each
party hereto.
9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by
action taken by or on behalf of its Board of Directors or Board of Trustees,
respectively, may to the extent permitted by applicable law (i) extend the time
for the performance of any of the obligations or other acts of the other parties
hereto, (ii) waive any inaccuracies in the representations and warranties of the
other parties hereto contained herein or in any document delivered pursuant
hereto or (iii) waive compliance with any of the covenants, agreements or
conditions of the other parties hereto contained herein. No such extension or
waiver shall be effective unless set forth in a written instrument duly executed
by or on behalf of the party extending the time of performance or waiving any
such inaccuracy or non-compliance. No waiver by any party of any term or
condition of this Agreement, in any one or more instances, shall be deemed to be
or construed as a waiver of the same or any other term or condition of this
Agreement on any future occasion.
ARTICLE X
GENERAL PROVISIONS
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements. The representations, warranties, covenants and agreements contained
in this Agreement or in any instrument delivered pursuant to this Agreement
shall not survive the Merger but shall terminate at the Effective Time, except
for the agreements contained in Article I and Article II, in Sections 7.05,
7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective
Time.
10.02 Notices. All notices, requests and other communications
hereunder must be in writing and will be deemed to have been duly given only if
-44-
<PAGE>
delivered personally or by facsimile transmission or sent by overnight courier
(providing proof of delivery) to the parties at the following addresses or
facsimile numbers:
If to NEES or LLC, to:
New England Electric System
25 Research Drive
Westborough, MA 01582
Attn: Richard P. Sergel
President and Chief Executive Officer
Telephone: (508) 389-2764
Facsimile: (508) 366-5498
with a copy to:
Skadden, Arps, Slate, Meagher & Flom LLP
919 Third Avenue
New York, NY 10022
Attn: Sheldon S. Adler, Esq.
Telephone: (212) 735-3000
Facsimile: (212) 735-2000
If to EUA, to:
Eastern Utilities Associates
One Liberty Square
Boston, MA 02109
Attn: Donald G. Pardus
Chairman and Chief Executive Officer
Telephone: (617) 357-9590
Facsimile: (617) 357-7320
with a copy to:
Winthrop, Stimson, Putnam & Roberts
1 Battery Park Plaza
New York, NY 10004
Attn: David P. Falck
Telephone: (212) 858-1000
Facsimile: (212) 858-1500
All such notices, requests and other communications will (i) if
delivered personally to the address as provided in this Section, be deemed given
-45-
<PAGE>
upon delivery, (ii) if delivered by facsimile transmission to the facsimile
number as provided in this Section, be deemed given when sent, provided that the
facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if
delivered by mail in the manner described above to the address as provided in
this Section, be deemed given one business day after delivery (in each case
regardless of whether such notice, request or other communication is received by
any other person to whom a copy of such notice, request or other communication
is to be delivered pursuant to this Section). Any party from time to time may
change its address, facsimile number or other information for the purpose of
notices to that party by giving notice specifying such change to the other
parties hereto.
10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement
supersedes all prior discussions and agreements, both written and oral, among
the parties hereto with respect to the subject matter hereof, other than the
Confidentiality Agreement, which shall survive the execution and delivery of
this Agreement in accordance with its terms, and contains, together with the
Confidentiality Agreement, the sole and entire agreement among the parties
hereto with respect to the subject matter hereof.
(b) The EUA Disclosure Letter, the NEES Disclosure Letter and
any Exhibit attached to this Agreement and referred to herein are hereby
incorporated herein and made a part hereof for all purposes as if fully set
forth herein.
10.04 No Third Party Beneficiary. The terms and provisions of this
Agreement are intended solely for the benefit of each party hereto and their
respective successors or permitted assigns, and except as provided in Article II
and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit
of the persons entitled to therein, and may be enforced by any of such persons),
it is not the intention of the parties to confer third-party beneficiary rights
upon any other person.
10.05 No Assignment; Binding Effect. Neither this Agreement nor any
right, interest or obligation hereunder may be assigned, in whole or in part, by
operation of law or otherwise, by any party hereto without the prior written
consent of the other parties hereto and any attempt to do so will be void,
except that LLC may assign any or all of its rights, interests and obligations
hereunder to another direct or indirect wholly owned Subsidiary of NEES,
provided that any such Subsidiary agrees in writing to be bound by all of the
terms, conditions and provisions contained herein and provided further that such
assignment (i) does not require a greater vote for EUA's Shareholder Approval,
(ii) does not require a subsequent vote following EUA's Shareholders Meeting, or
(iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES,
as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required
Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals,
or the NEES Required Consents. Subject to the preceding sentence, this Agreement
is binding upon, inures to the benefit of and is enforceable by the parties
hereto and their respective successors and assigns.
-46-
<PAGE>
10.06 Headings. The headings used in this Agreement have been
inserted for convenience of reference only and do not define, modify or limit
the provisions hereof.
10.07 Invalid Provisions. If any provision of this Agreement is held
to be illegal, invalid or unenforceable under any present or future law or
order, and if the rights or obligations of any party hereto under this Agreement
will not be materially and adversely affected thereby, (i) such provision will
be fully severable, (ii) this Agreement will be construed and enforced as if
such illegal, invalid or unenforceable provision had never comprised a part
hereof, and (iii) the remaining provisions of this Agreement will remain in full
force and effect and will not be affected by the illegal, invalid or
unenforceable provision or by its severance herefrom.
10.08 Governing Law. This Agreement shall be governed by and
construed in accordance with the laws of the Commonwealth of Massachusetts.
10.09 Enforcement of Agreement. The parties hereto agree that
irreparable damage would occur in the event that any of the provisions of this
Agreement was not performed in accordance with its specified terms or was
otherwise breached. It is accordingly agreed that the parties shall be entitled
to an injunction or injunctions to prevent breaches of this Agreement and to
enforce specifically the terms and provisions hereof in any court of competent
jurisdiction, this being in addition to any other remedy to which they are
entitled at law or in equity.
10.10 Certain Definitions. As used in this Agreement:
(a) except as provided in Section 4.14, the term "affiliate," as
applied to any person, shall mean any other person directly or indirectly
controlling, controlled by, or under common control with, that person; for
purposes of this definition, "control" (including, with correlative meanings,
the terms "controlling," "controlled by" and "under common control with"), as
applied to any person, means the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of that
person, whether through the ownership of voting securities, by contract or
otherwise;
(b) a person will be deemed to "beneficially" own securities if
such person would be the beneficial owner of such securities under Rule 13d-3
under the Exchange Act, including securities which such person has the right to
acquire (whether such right is exercisable immediately or only after the passage
of time);
(c) the term "business day" means a day other than Saturday,
Sunday or any day on which banks located in the Massachusetts are authorized or
obligated to close;
(d) the term "knowledge" or any similar formulation of
"knowledge" shall mean, with respect to any party hereto, the actual knowledge
after due inquiry of the executive officers of NEES and its Subsidiaries or EUA
and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES
Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided
-47-
<PAGE>
that as used in Section 4.13 the term "knowledge" shall also include the
knowledge of the environmental, health and safety personnel of EUA;
(e) the term "person" shall include individuals, corporations,
partnerships, trusts, limited liability companies, other entities and groups
(which term shall include a "group" as such term is defined in Section 13(d)(3)
of the Exchange Act);
(f) the "Representatives" of any entity shall have the same
meaning as set forth in the Confidentiality Agreement;
(g) the term "Subsidiary" means any corporation or other entity,
whether incorporated or unincorporated, in which such party directly or
indirectly owns at least a majority of the voting power represented by the
outstanding capital stock or other voting securities or interests having voting
power under ordinary circumstances to elect a majority of the directors or
similar members of the governing body, or otherwise to direct the management and
policies, or such corporation or entity.
10.11 Counterparts. This Agreement may be executed in any number of
counterparts, each of which will be deemed an original, but all of which
together will constitute one and the same instrument and will become effective
when one or more counterparts have been signed by each party and delivered to
the other parties.
10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE
FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY
JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING
TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON
CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO
REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY
OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK
TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER
PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER
THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
-48-
<PAGE>
IN WITNESS WHEREOF, each party hereto has caused this Agreement to be
signed by its officer thereunto duly authorized as of the date first above
written.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability therefor.
EASTERN UTILITIES ASSOCIATES
By: /s/ Donald G. Pardus
-----------------------------------
Name: Donald G. Pardus
Title: Chairman
The name "Eastern Utilities Associates" is the designation of the Trustees of
EUA for the time being in their collective capacity but not personally, under a
Declaration of Trust dated April 2, 1928, as amended, a copy of which amended
Declaration of Trust has been filed in the office of the Secretary of The
Commonwealth of Massachusetts and elsewhere as required by law; and all persons
dealing with EUA must look solely to the trust property for the enforcement of
any claim against EUA, as neither the Trustees nor the officers or shareholders
of EUA assume any personal liability for obligations entered into on behalf of
EUA.
RESEARCH DRIVE LLC
By: /s/ John G. Cochrane
-----------------------------------
Name: John G. Cochrane
Title: Manager
-49-
<PAGE>
Tab 2
CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
CONSENT AGREEMENT
This Consent Agreement (the "Agreement") is entered into as of
February 1, 1999 between The National Grid Group, p1c, a public limited company
incorporated under the laws of England and Wales ("NGG") and New England
Electric System, a Massachusetts business trust ("NEES").
WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly
owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as
of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC
will merge (the "Merger") with and into NEES with NEES being the surviving
entity and becoming a wholly owned subsidiary of NGG;
WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business
Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement
and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger
Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC
with and into EUA with EUA being the surviving entity and becoming a wholly
owned subsidiary of NEES; and
WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is
required to obtain the consent of NGG before entering into the EUA Merger
Agreement and with respect to certain actions relating to the consummation of
the transactions set forth therein.
NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties hereby agree as
follows:
1. Consent to EUA Merger Agreement. Subject to the terms and
conditions of this Consent, NGG hereby consents to NEES entering into the EUA
Merger Agreement with EUA in the form set forth in Exhibit A and agrees that,
subject to the immediately following sentence, the consummation by NEES of the
transactions contemplated by the EUA Merger Agreement in accordance with the
term thereof shall not constitute a breach by NEES of the terms of the Merger
Agreement. NEES and NGG acknowledge that the financing necessary to consummate
the EUA Merger was not contemplated when NEES and NGG agreed to the limitations
set forth in Article VI of the Merger Agreement and NGG consents to such
financing provided that such financing is consistent with the financing
parameters set forth on Exhibit B hereto. NGG also consents to the formation and
<PAGE>
capitalization of Research Drive LLC by NEES for the purpose of effecting the
EUA Merger as contemplated in the EUA Merger Agreement.
2. Access to Information. Subject to the following sentence, NEES
hereby agrees to provide NGG with reasonable access to any information it
receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to
consult with NGG on a regular basis concerning the status of EUA and the EUA
Merger. NGG hereby acknowledges that any such material that is "Evaluation
Material" (as such term is defined in the letter agreement dated as of December
21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be
governed by the terms of the Confidentiality Agreement.
3. Regulatory Filings. NEES hereby agrees that NGG shall have the
right to review in advance, and that NEES will consult with NGG and give due
regard to NGG's views concerning, any applications, notices, petitions, filings
and other documents filed with any Governmental Authority (as defined in the EUA
Merger Agreement) in connection with the EUA Merger which could reasonably be
expected to have a material adverse effect on NGG's or NEES' ability to
consummate the Merger or which could reasonably be expected to adversely affect
in any material manner any material benefit of the Merger to NGG or NEES.
4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will
not, without the prior written consent of NGG, amend or modify the EUA Merger
Agreement in any material respect, including, without limitation, amend or
otherwise modify any provision of the EUA Merger Agreement providing for or
relating to the amount, type or structure of the Merger Consideration (as
defined in the EUA Merger Agreement) or agree to any additional or different
amount, type or structure for the Merger Consideration (as so defined).
5. Acknowledgment. NGG and NEES acknowledge and agree that the
covenants set forth in Article VI of the Merger Agreement do not reflect the
operations of EUA if the EUA Merger is consummated prior to the Effective Time
(as defined in the Merger Agreement). In the event that the EUA Merger is
consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate
in good faith to make appropriate modifications to such covenants set forth in
Section 6.01 of the Merger Agreement to reflect the operations of EUA.
6. Termination and Amendment. This Consent Agreement and the
obligations of NEES hereunder shall terminate upon the earlier to occur of (i)
the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the
Merger, in each case without any further action by the parties hereto. Except as
<PAGE>
provided in the preceding sentence, this Consent can not be terminated or
amended in any material respect prior to the termination of the EUA Merger
Agreement without the prior written consent of EUA. The foregoing sentence is
intended for the benefit of EUA and may be enforced by EUA.
7. Notices. NEES hereby agrees to provide NGG with copies of all
notices and other communications it sends to EUA and all notices and other
communications it receives from EUA under the EUA Merger Agreement. All notices
and other communications provided under this Agreement must be in writing and
shall be given in the same manner and to the same parties as set forth in
Section 10.02 of the Merger Agreement.
8. Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
9. Governing Law and Waiver of Jury Trial. This Agreement shall be
governed by and construed in accordance with the laws of the State of New York
applicable to a contract executed and performed in such State, without giving
effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO
THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL
BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR
RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER
THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR
ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH
OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING
WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN
INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS
AND CERTIFICATIONS IN THIS SECTION.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: /s/ Fiona B. Smith
-----------------------------------
Name: Fiona B. Smith
Title: Company Secretary
NEW ENGLAND ELECTRIC SYSTEM
By: ___________________________
Name:
Title:
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: ______________________________
Name:
Title:
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES
(not legible)
<PAGE>
EXHIBIT B - Financing Parameters
Financing will be in an amount of up to $630 M provided through a
group of banks. The financing (i) will be prepayable, (ii) will have a term not
to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv)
will have other terms and conditions usual and customary for transactions of
this nature.
<PAGE>
Filing with the Vermont Public Service Board
<PAGE>
[DOWNS RACHLIN & MARTIN PLLC]
July 12, 1999
VIA FEDERAL EXPRESS
Mrs. Susan M. Hudson, Clerk
Vermont Public Service Board
112 State Street
Drawer 20
Montpelier, VT 05620-2701
Re: Petition of New England Power Company
Dear Mrs. Hudson:
Enclosed for filing on behalf of New England Power Company ("New England Power")
are one original and six copies of each of the following:
1. Petition of New England Power;
2. Prefiled Testimony of Jennifer K. Zschokke, with Exhibits.
New England Power requests consent to merge with Montaup Electric Company,
pursuant to 30 V.S.A. s. 109.
Also attached are the Notice of Appearance of Downs Rachlin & Martin PLLC on
behalf of New England Power, Statement of Notice Required and form of notice,
and a Certificate of Service.
Copies of this filing have been provided to James Volz, Dr. William Steinhurst,
and Thomas Dunn at the Department of Public Service.
<PAGE>
[DOWNS RACHLIN & MARTIN PLLC]
Mrs. Susan M. Hudson -2- July 12, 1999
Kindly acknowledge receipt of this filing by date stamping the duplicate copy of
this letter provided for this purpose, and returning it to me in the enclosed
stamped envelope. Thank you for your assistance in this matter.
Very truly yours,
DOWNS RACHLIN & MARTIN PLLC
Attorneys for New England Power Company
By: /s/ Nancy S. Malmquist
---------------------------
Nancy S. Malmquist
Enclosures
cc: Thomas G. Robinson, Esq.
Carlos A. Gavilondo, Esq.
<PAGE>
APPEARANCE
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
Petition of New England Power Company )
pursuant to 30 V.S.A. s.109, to merge with ) Docket No. __________
Montaup Electric Company )
APPEARANCE
Downs Rachlin & Martin PLLC, appears for the petitioner, New England
Power Company. Provide copies of all filings in this docket to:
Nancy S. Malmquist, Esq.
Downs Rachlin & Martin PLLC
90 Prospect Street
P.O. Box 99
St. Johnsbury, VT 05819-0099
and to
Carlos A. Gavilondo, Esq.
Thomas G. Robinson, Esq.
New England Power Company
25 Research Drive
Westborough, MA 01582-0099
St. Johnsbury, Vermont. July 12, 1999.
Respectfully submitted,
DOWNS RACHLIN & MARTIN PLLC
Attorneys for New England
Power Company
By: /s/ Nancy S. Malmquist
-----------------------------------
Nancy S. Malmquist
2
<PAGE>
STATEMENT OF NOTICE REQUIRED
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
Petition of New England Power Company )
pursuant to 30 V.S.A. s.109, to merge with ) Docket No. __________
Montaup Electric Company )
STATEMENT OF NOTICE REQUIRED
The petitioner, New England Power Company, hereby states that notice
of the above-captioned petition is required, pursuant to Subsection 109 of Title
30, Vermont Statutes Annotated, to the Department of Public Service, and to such
other persons as the Board directs. Exhibit A is a proposed form of notice to
the public, if required.
St. Johnsbury, Vermont. July 12, 1999
DOWNS RACHLIN & MARTIN PLLC
Attorneys for New England Power Company
By: /s/ Nancy S. Malmquist
-----------------------------------
Nancy S. Malmquist
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
Take notice that, on July 13, 1999, New England Power Company, a company
qualified to transact business in Vermont as a foreign corporation, petitioned
the Vermont Public Service Board, pursuant to 30 V.S.A. s. 109, for consent to
merge with Montaup Electric Company. Take notice further that the Public Service
Board will hold a hearing on this petition at ___________________ in
______________________ on __________, 1999, at _____________. Any person wishing
to intervene in this proceeding should give written notice thereof to the Board
by July 30, 1999. Any questions or filings concerning this petition should be
made to:
Mrs. Susan M. Hudson, Clerk
Vermont Public Service Board
112 State Street
Drawer 20
Montpelier, VT 05620-2701
<PAGE>
CERTIFICATE OF SERVICE
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
Petition of New England Power Company )
pursuant to 30 V.S.A. s. 109, to ) Docket No. __________
merge with Montaup Electric Company )
CERTIFICATE OF SERVICE
Downs Rachlin & Martin PLLC, certifies that it has provided three
copies of the above-captioned petition, including its appearance, a statement of
notice required, this certificate and related prefiled testimony and exhibits,
to the Vermont Department of Public Service, by first-class mail, postage
prepaid, with one copy provided to the Department's Director of Public Advocacy,
one copy to the Department's Director of Utility Planning, Dr. William
Steinhurst, and one copy to the Department's Chief Engineer, Thomas Dunn.
St. Johnsbury, Vermont. July 12, 1999
DOWNS RACHLIN & MARTIN PLLC
Attorneys for New England Power Company
By: /s/ Nancy S. Malmquist
-----------------------------------
Nancy S. Malmquist
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
Petition of New England Power Company, )
pursuant to 30 V.S.A. s. 109, to ) Docket No. __________
merge with Montaup Electric Company )
PETITION
This is a petition by New England Power Company (herein "NEP").
I.
By this petition, NEP represents that:
1. NEP is a Massachusetts corporation that owns and operates
properties in Massachusetts, New Hampshire, Connecticut, Maine and Vermont,
including transmission lines, and is a transmission subsidiary of New England
Electric System ("NEES"); NEP owns properties in several Vermont communities
used primarily for the transmission of electricity;
2. NEP has qualified to transact business in Vermont as a foreign
corporation but does not engage in local distribution of electricity therein;
3. NEES is a registered holding company under the Public Utility
Holding Company Act of 1935 ("Holding Company Act") and owns the common equity
of several electric utility companies, including NEP, Narragansett Electric
Company ("Narragansett"), Massachusetts Electric Company ("Mass Electric"),
Nantucket Electric Company, and Granite State Electric Company;
<PAGE>
4. Eastern Utilities Associates ("EUA") is a registered holding
company under the Holding Company Act and owns directly or indirectly the common
equity of several electric utility companies, including Montaup Electric Company
("Montaup"), Blackstone Valley Electric Company ("BVE"), Newport Electric
Corporation ("Newport"), and Eastern Edison Company ("Eastern");
5. On February 1, 1999, NEES, EUA, and Research Drive LLC ("Research
Drive"), a directly and indirectly wholly-owned subsidiary of NEES, entered into
an Agreement and Plan of Merger ("EUA Agreement"), pursuant to which EUA will
become a wholly-owned subsidiary of NEES;
6. As soon as practicable after the closing of the merger transaction
with EUA, NEES intends to merge the operating companies of EUA (none of which
operate in Vermont) with and into the operating companies of NEES. NEES intends
to merge Montaup with and into NEP, pursuant to which NEP will be the surviving
entity (and will continue to be wholly-owned by NEES). Similarly, NEES intends
to merge Eastern into Mass Electric, and BVE and Newport with and into
Narragansett.
7. Following the merger of Montaup into NEP, NEP will remain a
separate corporation wholly owned by NEES and will continue to own and conduct a
public service business subject to the jurisdiction of the Board;
8. The proposed merger of Montaup with and into NEP requires a finding
of general good and the issuance of a certificate of consent by the Board
pursuant to 30 V.S.A. s.109; and
9. The proposed merger of Montaup with and into NEP will promote the
general good of Vermont and will not result in obstructing of preventing
competition.
-2-
<PAGE>
II.
In support of this petition, NEP prefiles testimony and supporting
exhibits by the following witness:
Witness Subject Matter
Jennifer K. Zschokke Overview; description of merger transaction; general
good promoted by merger of Montaup with and into NEP.
III.
NEP requests that the Board:
A. Appoint a Hearing Officer to hear, schedule a prehearing conference
for, and issue notice of the opportunity for hearing on this petition, in
accordance with 30 V.S.A. s.109;
B. Find that the merger of Montaup with and into NEP will promote the
general good of the State of Vermont and issue a certificate of consent
therefor;
C. Find that the merger of Montaup with and into NEP will not result
in obstructing or preventing competition in the purchase or sale of any product,
service or commodity, in the sale, purchase or manufacture of which Montaup and
NEP are engaged; and
D. Take such other measures as in the Board's judgment are necessary
for a full and expeditious resolution of this petition.
Respectfully submitted,
NEW ENGLAND POWER COMPANY
By: Downs Rachlin & Martin PLLC
Attorneys for New England Power Company
By: /s/ Nancy S. Malmquist
----------------------------------------
Nancy S. Malmquist
Date: July 12, 1999
-3-
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
- ----------------------------------------
)
In Re: New England Power Company )
) Docket No. _____
Petition For Approval of Merger with )
Montaup Electric Company )
- ----------------------------------------
TESTIMONY
OF
JENNIFER K. ZSCHOKKE
<PAGE>
STATE OF VERMONT
PUBLIC SERVICE BOARD
- ----------------------------------------
)
In Re: New England Power Company )
) Docket No. _____
Petition For Approval of Merger with )
Montaup Electric Company )
- ----------------------------------------
TESTIMONY
OF
JENNIFER K. ZSCHOKKE
Table of Contents
Page
I. Qualifications.................................................... 1
II. Purpose of Filing................................................. 1
III. Description of the Transactions................................... 3
VI. Benefits Created by the Merger.................................... 6
<PAGE>
<TABLE>
<CAPTION>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 1 of 11
<S> <C>
1 I. Qualifications.
2 Q. Please state your name, title, and business address.
3 A. My name is Jennifer K. Zschokke. I am Manager of Finance for New England Power
4 Service Company (NEPSCO), a New England Electric System (NEES) Company. My
5 business address is 25 Research Drive, Westborough, MA 01582.
6
7 Q. Please describe your educational background and training.
8 A. I have earned a Bachelor of Arts degree in Management Science from Westminster
9 College and a Masters of Science in Finance from Boston College.
10
11 Q. Please describe your professional experience.
12 A. I joined NEPSCO in 1987 as an assistant financial analyst and have been promoted several
13 times within the Finance Department, most recently to Manager in 1998. My
14 responsibilities include the long and short-term financing of NEES and its subsidiaries. In
15 addition, the Finance Department provides a variety of financial advisory services to other
16 functions in the NEES System.
17
18 II. Purpose of Filing.
19 Q. What is the purpose of this filing?
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 2 of 11
1 A. On February 1, 1999, NEES, Eastern Utilities Associates ("EUA"), and Research Drive
2 LLC ("Research Drive"), a directly and indirectly wholly owned subsidiary of NEES
3 entered into an Agreement and Plan of Merger ("EUA Agreement"), through which EUA
4 will become a wholly owned subsidiary of NEES. Upon the closing of the EUA
5 transaction, it is NEES's intention to consolidate and merge New England Power
6 Company ("NEP") with Montaup Electric Company ("Montaup") (together, the
7 "Companies"). This filing requests the Vermont Public Service Board (the "Board") to
8 approve the merger of NEP and Montaup.
9
10 Q. Please describe the entities and transactions that relate to this filing?
11 A. NEES is a registered holding company under the Public Utility Holding Company Act of
12 1935 ("Holding Company Act") and owns the common equity of several electric utility
13 companies, including NEP, Narragansett, Massachusetts Electric Company, Nantucket
14 Electric Company, and Granite State Electric Company.
15 EUA also is a registered holding company under the Holding Company Act and
16 owns directly or indirectly the common equity of several electric utility companies,
17 including Montaup, Blackstone Valley Electric Company ("BVE"), Newport Electric
18 Corporation ("Newport"), and Eastern Edison Company ("Eastern Edison" or "Eastern").
19
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 3 of 11
1 Q. What issues will your testimony address?
2 A. I will briefly describe both the merger of the parent companies and the merger of NEP and
3 Montaup. I also will describe the benefits of the mergers in support of the Companies'
4 Petition for approval of the merger of Montaup into NEP.
5
6 III. Description of the Transactions.
7 Q. Ms. Zschokke, would you please describe the parent company merger between NEES and
8 EUA?
9 A. The transaction is set forth in the EUA Agreement included as Exhibit JKZ-1. Pursuant to
10 the EUA Agreement, Research Drive will merge with and into EUA with EUA becoming
11 a wholly owned subsidiary of NEES. The merger agreement contains terms and
12 conditions which are typical to a merger transaction. Closing of the NEES-EUA merger
13 has been approved by EUA shareholders and is subject to obtaining required regulatory
14 approvals. The NEES-EUA merger does not, however, require this Board's approval.
15
16 Q. Please describe the merger of the underlying operating companies?
17 A. As soon as practicable after the parent company merger, NEES intends to merge the
18 operating companies of EUA with the operating companies of NEES. As shown on
19 Exhibit JKZ-2, Montaup will merge into NEP. In Massachusetts, Eastern Edison will
20 merge with and into Massachusetts Electric Company ("Mass. Electric"), and in Rhode
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 4 of 11
1 Island, BVE and Newport will merge with and into Narragansett, with Narragansett being
2 the sole surviving entity. Because NEP is a Vermont utility, the merger of Montaup with
3 and into NEP requires approval by the Board.
4
5 Q. Please describe where NEP and Montaup fit into the organizational structure of the NEES
6 and EUA systems, respectively.
7 A. NEP is a direct subsidiary of NEES. This means that NEES owns 100% of the common
8 stock of NEP. Montaup is an indirect subsidiary of EUA and 100% of its common equity
9 is owned by Eastern. However, Eastern is contemplating a spin off of 100% of its
10 ownership of the common stock of Montaup to EUA prior to the NEES's acquisition of
11 EUA. The spinoff of Montaup by Eastern would i) complete the functional unbundling of
12 the generation business from the distribution business through the complete corporate
13 separation of Eastern and Montaup, ii) eliminate any risk that Eastern may have associated
14 with its direct ownership of Montaup pertaining to, for example, contingent liabilities and
15 nuclear ownership, iii) isolate Eastern's capital structure so that it applies to distribution
16 ratemaking only, and iv) simplify EUA's corporate structure. Following the spinoff,
17 Montaup will be a direct subsidiary of EUA, just as NEP is a direct subsidiary of NEES.
18 NEP operates in several states, which include Massachusetts, Rhode Island, New
19 Hampshire, and Vermont. Montaup operates in Massachusetts and Rhode Island. Both
20 NEP and Montaup have minority interests in nuclear properties in Connecticut, Maine,
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 5 of 11
1 New Hampshire and Vermont as well as a fossil unit in Maine. Since the divestiture of
2 substantially all of its generating business in 1998, NEP is primarily a transmission
3 company. Montaup recently completed the sale of the Canal, Somerset, and Wyman 4
4 generating stations. Therefore, Montaup is primarily a transmission company going
5 forward similar to NEP.
6 In addition, NEP and Montaup each recover through FERC-approved, wholesale
7 Contract Termination Charges (CTC's), stranded costs associated with prior investments
8 in the generating business. NEP and Montaup collect CTC's from affiliated and
9 nonaffiliated customers.
10
11 Q. Please describe the balance sheets of NEP and Montaup?
12 A. Please see Exhibit JKZ-3 and JKZ-4, respectively. At year end 1998, NEP's balance sheet
13 was approximately four times the size of Montaup's. NEP's assets and liabilities totaled
14 $2.415 billion and Montaup's assets and liabilities totaled $641 million. As of year end,
15 NEP owned $458 million of net utility plant, most of which is transmission and Montaup
16 owned about $341 million of net utility plant, which still included the Somerset units
17 subsequently sold on April 27, 1999. Both NEP and Montaup have significant regulatory
18 assets which represent the future collection of Contract Termination Charges. As for
19 capital structure, NEP and Montaup have similar capitalization ratios as of year end 1998.
20
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 6 of 11
1 Q. What are the financial transactions necessary to implement the consolidation of Montaup
2 and NEP?
3 A. Montaup will merge with and into NEP, and their balance sheets will be consolidated. We
4 are assuming as part of this transaction, NEP will use its cash on hand to pay off
5 Montaup's debentures and preferred stock currently held by Eastern. In addition, $147
6 million of common equity is expected to be repaid to the direct parent of Montaup.
7
8 Q. Have you prepared pro forma financial statements for the merger of NEP and Montaup?
9 A. Yes. Exhibit JKZ-5 illustrates the impact of the merger of Montaup and NEP, and the
10 repayment by Montaup of its debt and preferred stock. As permitted by accounting rules,
11 the balance sheet of the combined entity will reflect the sum of the balance sheets of the
12 separate entities prior to the subsidiary merger.
13
14 VI. Benefits Created by the Merger.
15 Q. Would you summarize the benefits created through the merger of NEP and Montaup?
16 A. In considering the benefits of the NEP-Montaup merger, it is important to consider that
17 such merger arises out of and directly relates to the merger occurring at the parent
18 company level. The two mergers, taken together, will result in the creation of substantial
19 benefits which can be used to provide improved service at lower cost to customers.
20 Specifically, the mergers produce synergies which are typical of utility combinations.
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 7 of 11
1 These synergies build on efficiencies already achieved by the Companies, which are
2 already among the lowest cost utilities in New England.
3
4 Q. How will the cost savings you described be achieved?
5 A. The cost savings will come from a variety of categories. Approximately 70 percent of the
6 savings will come from eliminating approximately 250 positions from the combined
7 NEES-EUA organization. These reductions come from across the organization.
8 Administrative areas such as accounting and finance, where significant redundancies exist
9 between the two organizations, will be reduced. EUA's and NEES' customer service
10 operations will be integrated to handle increased volumes at a lower unit cost. The unit
11 cost of field operations will also be reduced through standardization and mutual support.
12 The remainder of the operating savings will come from disposing of duplicate facilities,
13 realizing greater purchasing power, and eliminating redundant administrative costs, such
14 as corporate governance expense. The cost savings achieved by the mergers ultimately
15 will be shared with customers through lower and more stable rates.
16
17 Q. Are there any other areas of cost savings or efficiencies created by the mergers?
18 A. Yes. Most utility mergers include as savings the costs of building one rather than two sets
19 of new information systems (usually customer or financial) at some time in the future.
20 Both NEES and EUA have older customer information systems. The cost of replacing
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 8 of 11
1 these systems would currently be in excess of $10 million per company. When combined,
2 the costs are cut in half. Although it is difficult to pinpoint the timeframe in which the
3 savings will occur, the savings are real and will provide future benefits.
4 In addition, we expect the higher credit ratings of the NEES companies to lead to
5 financing savings as the debt of the EUA companies is refinanced over time.
6
7 Q. Are there any benefits that are directly produced for NEP's transmission customers?
8 A. Yes. As the result of the merger, NEP's transmission rates to NEP's existing open-access
9 transmission customers will be reduced. First, because Montaup's transmission rates are
10 on average lower than NEP's, the combination of the two Companies will lower NEP's
11 FERC-filed, open access transmission rates. Secondly, the efficiency gains discussed above
12 will automatically flow to NEP's open access, transmission customers through NEP cost
13 of service formula transmission rate. Both factors will produce savings for NEP's
14 transmission customers following the merger.
15
16 Q. Will the merger prevent or obstruct competition in Vermont?
17 A. No. Other than its minority share in Vermont Yankee, Montaup owns no facilities and no
18 business in Vermont. As a result, the merger will have no affect on the power markets in
19 this state. In addition, both NEP and Montaup have divested substantially all of their non-
20 nuclear generating entitlements and have focused instead on the transmission business
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 9 of 11
1 which remains regulated by FERC. The transaction has passed the Hart-Scott-Rodino
2 screen for adverse effects on competition. Finally, the Companies have filed a competitive
3 analysis with FERC as part of their application under s. 203 of the Federal Power Act that
4 demonstrates that the merger will not have an adverse effect on competition in the New
5 England market. See Affidavit of Henry Kahwaty in FERC Docket EC99-70-000. As a
6 result, we do not believe that the merger of NEP and Montaup will prevent or obstruct
7 competition in Vermont.
8
9 Q. What will the impact be on employees from the mergers?
10 A. Although the merger of the two organizations is expected to reduce employment by about
11 250 positions in the combined companies in Massachusetts and Rhode Island, we believe
12 that these employee reductions can be achieved predominantly through attrition or
13 voluntary early retirement and without significant involuntary layoffs.
14
15 Q. Are NEES and EUA taking steps to mitigate the loss of positions following the NEES-
16 EUA merger?
17 A. Yes. In anticipation of the merger's approval, we have placed a limitation on hiring for
18 our company. The NEES companies expect to have a significant number of vacant
19 positions by the time the transaction closes. Natural attrition at EUA is expected to add
20 more positions. We are making every effort to leave these positions vacant until
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 10 of 11
1 employees affected by the acquisition have an opportunity to be considered for a position.
2 Beyond vacancies and attrition, we can economically offer 200 to 250 NEES and EUA
3 employees a voluntary early retirement program. Through these measures, we expect to
4 meet our workforce reduction targets without having a significant impact on individual
5 employees.
6 NEES has also agreed in the merger agreement to honor EUA's collective
7 bargaining agreements and to provide non-union employees joining the NEES companies
8 with compensation and benefits in the aggregate at least equivalent to those obtained prior
9 to the merger for a year following closing. EUA employees joining the NEES system will
10 find that the compensation and benefit philosophies of the two companies are very similar,
11 allowing us to merge benefit plans without significant disruption to employees.
12
13 Q. Are other regulatory approvals required to consummate the merger? Yes. The NEES
14 acquisition of EUA and the merger of the operating companies are being filed together in
15 several jurisdictions. Approvals have been or are being requested from the Federal Energy
16 Regulatory Commission and the Securities and Exchange Commission at the federal level,
17 and from state commissions in Massachusetts, Rhode Island, and Connecticut. An
18 approval may also be required from New Hampshire if a transfer of Montaup's share of
19 Seabrook to NEP is necessary.
20
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Testimony of J. K. Zschokke
Page 11 of 11
1 Q. Please summarize why you believe the merger of Montaup into NEP will promote the
2 general good of the State of Vermont and is in the public interest.
3 A. The merger will bring cost savings to NEP's transmission customers, produce efficiency
4 gains, and improve the ability of the Companies to provide reliable service to customers.
5 For all of these reasons, the merger meets the statutory requirements for approval by the
6 Board. Specifically, the merger (i) is consistent with the public interest, (ii) will not
7 diminish the facilities of the Companies used for furnishing service to the public, and (iii)
8 will not prevent or obstruct competition in Vermont. In fact, the merger will improve the
9 Companies' ability to provide service.
10
11 Q. Does this complete your testimony?
12 A. Yes.
</TABLE>
<PAGE>
AGREEMENT AND PLAN OF MERGER
and CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
TABLE OF CONTENTS
AGREEMENT AND PLAN OF MERGER...................................................1
CONSENT AGREEMENT..............................................................2
<PAGE>
Tab 1
AGREEMENT AND PLAN OF MERGER
dated as of February 1, 1999
by and among
NEW ENGLAND ELECTRIC SYSTEM,
RESEARCH DRIVE LLC
and
EASTERN UTILITIES ASSOCIATES
<PAGE>
TABLE OF CONTENTS
Page
No.
ARTICLE I
THE MERGER......................................................... 1
1.01 The Merger......................................................... 1
1.02 Effective Time..................................................... 1
1.03 Effects of the Merger.............................................. 2
ARTICLE II
CONVERSION OF SHARES............................................... 2
2.01 Conversion of Capital Stock........................................ 2
2.02 Surrender of Shares................................................ 3
2.03 Withholding Rights................................................. 4
ARTICLE III
THE CLOSING........................................................ 4
ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA.............................. 5
4.01 Organization and Qualification..................................... 5
4.02 Capital Stock...................................................... 6
4.03 Authority.......................................................... 7
4.04 Non-Contravention; Approvals and Consents.......................... 7
4.05 SEC Reports, Financial Statements and Utility Reports.............. 8
4.06 Absence of Certain Changes or Events............................... 9
4.07 Legal Proceedings.................................................. 9
4.08 Information Supplied............................................... 9
4.09 Compliance......................................................... 10
4.10 Taxes.............................................................. 10
4.11 Employee Benefit Plans; ERISA...................................... 12
4.12 Labor Matters...................................................... 14
4.13 Environmental Matters.............................................. 15
4.14 Regulation as a Utility............................................ 17
4.15 Insurance.......................................................... 17
4.16 Nuclear Facilities................................................. 18
4.17 Vote Required...................................................... 18
4.18 Opinion of Financial Advisor....................................... 18
-i-
<PAGE>
Page
No.
4.19 Ownership of NEES Common Shares.................................... 18
4.20 State Anti-Takeover Statutes....................................... 18
4.21 Year 2000.......................................................... 19
4.22 EUA Associates..................................................... 19
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES............................. 19
5.01 Organization and Qualification..................................... 19
5.02 Authority.......................................................... 20
5.03 Capital Stock...................................................... 20
5.04 Non-Contravention; Approvals and Consents.......................... 20
5.05 Information Supplied............................................... 21
5.06 Compliance......................................................... 21
5.07 Financing.......................................................... 22
5.08 No Vote Required................................................... 22
5.09 Ownership of EUA Shares............................................ 22
5.10 Merger with The National Grid Group plc............................ 22
ARTICLE VI
COVENANTS................................................ 22
6.01 Covenants of EUA................................................... 22
6.02 Covenants of NEES.................................................. 28
6.03 Additional Covenants by NEES and EUA............................... 29
ARTICLE VII
ADDITIONAL AGREEMENTS.................................... 30
7.01 Access to Information.............................................. 30
7.02 Proxy Statement.................................................... 31
7.03 Approval of Shareholders........................................... 31
7.04 Regulatory and Other Approvals..................................... 31
7.05 Employee Benefit Plans............................................. 32
7.06 Labor Agreements and Workforce Matters............................. 34
7.07 Post Merger Operations............................................. 34
7.08 No Solicitations................................................... 35
7.09 Directors' and Officers' Indemnification and Insurance............. 36
7.10 Expenses........................................................... 37
7.11 Brokers or Finders................................................. 37
7.12 Anti-Takeover Statutes............................................. 38
7.13 Public Announcements............................................... 38
-ii-
<PAGE>
Page
No.
7.14 Restructuring of the Merger........................................ 38
ARTICLE VIII
CONDITIONS......................................................... 39
8.01 Conditions to Each Party's Obligation to Effect the Merger......... 39
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger...... 39
8.03 Conditions to Obligation of EUA to Effect the Merger............... 40
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER.................................. 41
9.01 Termination........................................................ 41
9.02 Effect of Termination.............................................. 43
9.03 Termination Fees................................................... 43
9.04 Amendment.......................................................... 44
9.05 Waiver............................................................. 44
ARTICLE X
GENERAL PROVISIONS................................................. 44
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements......................................................... 44
10.02 Notices............................................................ 44
10.03 Entire Agreement; Incorporation of Exhibits........................ 46
10.04 No Third Party Beneficiary......................................... 46
10.05 No Assignment; Binding Effect...................................... 46
10.06 Headings........................................................... 47
10.07 Invalid Provisions................................................. 47
10.08 Governing Law...................................................... 47
10.09 Enforcement of Agreement........................................... 47
10.10 Certain Definitions................................................ 47
10.11 Counterparts....................................................... 48
10.12 WAIVER OF JURY TRIAL............................................... 48
-iii-
<PAGE>
GLOSSARY OF DEFINED TERMS
The following terms, when used in this Agreement, have the meanings
ascribed to them in the corresponding Sections of this Agreement listed below:
"1935 Act" -- Section 4.05(b)
"Adjustment Date" -- Section 2.01(c)
"Affected Employees" -- Section 7.05(a)
"affiliate" -- Section 10.11(a)
"Agreement" -- Preamble
"Alternative Proposal" -- Section 7.08
"beneficially" -- Section 10.10(b)
"business day" -- Section 10.10(c)
"Canceled Shares" -- Section 2.02(b)
"Certificates" -- Section 2.02(b)
"Closing" -- Article III
"Closing Agreement" -- Section 4.10(j)
"Closing Date" -- Article III
"Code" -- Section 2.03
"Confidentiality Agreement" -- Section 7.01
"Constituent Entities" -- Section 1.01
"Contracts" -- Section 4.04(a)
"control," "controlling,"
"controlled by" and
"under common control with" -- Section 10.10(a)
"DOE" -- Section 4.05(b)
"Effective Time" -- Section 1.02
"Environmental Claim" -- Section 4.13(f)(i)
"Environmental Laws" -- Section 4.13(f)(ii)
"Environmental Permits" -- Section 4.13(b)
"ERISA" -- Section 4.11(a)
"ERISA Affiliate" -- Section 4.11(c)
"EUA" -- Preamble
"EUA Associates" -- Section 4.01(b)
"EUA Employee Agreements" -- Section 7.05(d)(ii)
"EUA Executives" -- Section 7.05(d)(ii)
"EUA Shares" -- Preamble
"EUA Disclosure Letter" -- Section 4.01(a)
"EUA Employee Benefit Plans" -- Section 4.11(a)
"EUA Financial Statements" -- Section 4.05(a)
"EUA Nuclear Facilities" -- Section 4.16
"EUA Material Adverse Effect" -- Section 4.01(a)
"EUA Required Consents" -- Section 4.04(a)
"EUA Required Statutory Approvals" -- Section 4.04(b)
"EUA SEC Reports" -- Section 4.05(a)
-iv-
<PAGE>
"EUA Shareholders' Approval" -- Section 7.03
"EUA Shareholders' Meeting" -- Section 7.03
"EUA Significant Subsidiary" -- Section 7.08
"EUA Shares" -- Preamble
"EUA Trust Agreement" -- Section 1.03
"EUA Voting Debt -- Section 4.02(d)
"Evaluation Material" -- Section 7.01(a)
"Exchange Act" -- Section 4.05(a)
"Exchange Fund" -- Section 2.02(a)
"Extended Termination Date" -- Section 9.01(b)
"FCC" -- Section 4.05(b)
"FERC" -- Section 4.05(b)
"Final Order" -- Section 8.01(d)
"Governmental Authority" -- Section 4.04(a)
"Hazardous Materials" -- Section 4.13(f)(iii)
"HSR Act" -- Section 7.04(a)
"Indemnified Liabilities" -- Section 7.09(a)
"Indemnified Party" -- Section 7.09(a)
"Indemnified Parties" -- Section 7.09(a)
"Information Systems" -- Section 4.21
"Initial Termination Date" -- Section 9.01(b)
"IRS" -- Section 4.10(m)
"knowledge" -- Section 10.11(d)
"laws" -- Section 4.04(a)
"Lien" -- Section 4.02(b)
"LLC" -- Preamble
"Massachusetts Secretary" -- Section 1.02
"Merger" -- Preamble
"Merger Consideration" -- Section 2.01(b)(ii)
"MGL" -- Section 1.01
"National Grid Group" -- Section 5.10
"National Grid Merger Agreement" -- Section 5.10
"NEES" -- Preamble
"NEES Disclosure Letter" -- Section 5.03
"NEES Material Adverse Effect" -- Section 5.01
"NEES-EUA Regulatory Approvals" -- Section 7.04(b)
"NEES-EUA Regulatory Proceedings" -- Section 7.04(c)
"NEES Required Consents" -- Section 5.04(a)
"NEES Required Statutory Approvals" -- Section 5.04(b)
"NEES-NGG Regulatory Approvals" -- Section 7.04(c)
"NEES-NGG Regulatory Proceedings" -- Section 7.04(c)
"NEES-NGG Required Statutory Approvals"-- Section 7.04
"NEES-NGG Transactions" -- Section 7.04
"NEES Shares" -- Section 5.03
-v-
<PAGE>
"NEES Trust Agreement" -- Section 5.01
"NGG Circular" -- Section 7.02
"NRC" -- Section 4.05(b)
"Options" -- Section 4.02(a)
"orders" -- Section 4.04(a)
"Out-of-Pocket Expenses" -- Section 9.03(a)
"Paying Agent" -- Section 2.02(a)
"PBGC" -- Section 4.11(g)
"person" -- Section 10.11(e)
"Per Share Amount" -- Section 2.01(b)(ii)
"Post Closing Plans" -- Section 7.05(b)
"Proxy Statement" -- Section 4.08(a)
"Release" -- Section 4.13(f)(iv)
"Representatives" -- Section 10.11(f)
"SEC" -- Section 4.05(a)
"Securities Act" -- Section 4.05(a)
"Subsidiary" -- Section 10.11(g)
"Surviving Entity" -- Section 1.01
"Tax Ruling" -- Section 4.10(j)
"Taxes" -- Section 4.10
"Tax Return" -- Section 4.10
"US GAAP" -- Section 4.05(a)
"Yankee Companies" -- Section 4.16
"Y2K Consultant" -- Section 6.01(o)
-vi-
<PAGE>
This AGREEMENT AND PLAN OF MERGER, dated as of February 1, 1999 (this
"Agreement"), is made and entered into by and among NEW ENGLAND ELECTRIC SYSTEM,
a Massachusetts business trust ("NEES"), RESEARCH DRIVE LLC ("LLC"), a
Massachusetts limited liability company which is directly and indirectly wholly
owned by NEES, and EASTERN UTILITIES ASSOCIATES, a Massachusetts business trust
("EUA").
WHEREAS, the Board of Directors of NEES, the Board of Trustees of EUA
and the members of LLC have each determined that it is advisable and in the best
interests of their respective shareholders and members to consummate, and have
approved, the business combination transaction provided for herein in which LLC
would merge with and into EUA, with EUA being the surviving entity (the
"Merger"), pursuant to the terms and conditions of this Agreement, as a result
of which NEES will own, directly or indirectly, all of the issued and
outstanding common shares of EUA (the "EUA Shares");
WHEREAS, NEES, LLC and EUA desire to make certain representations,
warranties and agreements in connection with the Merger and also to prescribe
various conditions to the Merger;
NOW, THEREFORE, in consideration of the mutual covenants and
agreements set forth in this Agreement, and for other good and valuable
consideration, the receipt and sufficiency of which are hereby acknowledged, the
parties hereto hereby agree as follows:
ARTICLE I
THE MERGER
1.01 The Merger. Upon the terms and subject to the conditions of this
Agreement, at the Effective Time (as defined in Section 1.02), LLC shall be
merged with and into EUA in accordance with Section 2 of Chapter 182 and Section
59 of Chapter 156C of the Massachusetts General Laws ("MGL"). At the Effective
Time, the separate existence of LLC shall cease and EUA shall continue as the
surviving entity in the Merger. EUA, after the Effective Time, is sometimes
referred to herein as the "Surviving Entity" and EUA and LLC are sometimes
referred to herein as the "Constituent Entities". The effect and consequences of
the Merger shall be as set forth in Article II.
1.02 Effective Time. Subject to the provisions of this Agreement, on
the Closing Date (as defined in Article III), a certificate of merger shall be
executed and filed by EUA and LLC with the Secretary of the Commonwealth of
Massachusetts (the "Massachusetts Secretary"). The Merger shall become effective
at the time of the filing of the certificate of merger relating to the Merger
with the Massachusetts Secretary, or at such later time as is specified in the
certificate of merger (such date and time being referred to herein as the
"Effective Time").
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1.03 Effects of the Merger. At the Effective Time, the Agreement and
Declaration of Trust of EUA (the "EUA Trust Agreement") as in effect immediately
prior to the Effective Time shall be the agreement and declaration of trust of
the Surviving Entity, until thereafter amended as provided by law and such
agreement and declaration of trust. Subject to the foregoing, the additional
effects of the Merger shall be as provided in the applicable provisions of
Section 2 of Chapter 182 of the MGL and Section 62 of the Limited Liability
Company Act of Massachusetts.
ARTICLE II
CONVERSION OF SHARES
2.01 Conversion of Capital Stock. At the Effective Time, by virtue of
the Merger and without any action on the part of the holder thereof:
(a) Membership Interests of LLC. Each one percent of the issued
and outstanding membership interests in LLC shall be converted into one
transferable certificate of participation or share of the Surviving Entity.
(b) Conversion of EUA Shares.
(i) Cancellation of Treasury Shares and Shares Owned by
NEES and Subsidiaries. All EUA Shares that are owned by EUA as treasury shares
and any EUA Shares owned by NEES or any other wholly owned Subsidiary (as
defined in Section 10.11) of NEES shall be canceled and retired and shall cease
to exist and no cash or other consideration shall be delivered in exchange
therefor.
(ii) Conversion of EUA Shares. Each EUA Share issued and
outstanding immediately prior to the Effective Time (other than shares to be
canceled in accordance with Section 2.01(b)(i)) shall be canceled and converted
in accordance with the provisions of this Section 2.01 into the right to receive
cash in the amount (the "Per Share Amount") of $31.00 as such amount may
hereafter be adjusted in accordance with Section 2.01(c) hereof (the "Merger
Consideration"), payable, without interest, to the holder of such EUA Share,
upon surrender, in the manner provided in Section 2.02 hereof, of the
certificate formerly evidencing such share.
(c) Adjustment in Amount of Merger Consideration. In the event
that the Closing Date shall not have occurred on or prior to the date that is
the six (6) month anniversary of the date on which EUA Shareholders' Approval is
obtained (the "Adjustment Date"), the Per Share Amount shall be increased, for
each day after the Adjustment Date up to and including the day which is one day
prior to the earlier of the Closing Date and the Extended Termination Date, by
an amount equal to $0.003.
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2.02 Surrender of Shares. (a) Deposit with Paying Agent. Prior to the
Effective Time, NEES shall designate a bank or trust company reasonably
acceptable to EUA to act as agent (the "Paying Agent") for the benefit of the
holders of EUA Shares in connection with the Merger to receive the funds to
which holders of EUA Shares shall become entitled pursuant to Section
2.01(b)(ii) (the "Exchange Fund"). From time to time at, immediately prior to or
after the Effective Time, NEES or LLC shall make or cause to be made available
to the Paying Agent immediately available funds in amounts and at the times
necessary for the payment of the Merger Consideration upon surrender of
Certificates (as defined in Section 2.02(b)) in accordance with Section 2.02(b),
it being understood that any and all interest or other income earned on funds
made available to the Paying Agent pursuant to this Section 2.02(a) shall belong
to and shall be paid (at the time provided for in Section 2.02(e)) as directed
by NEES or LLC. Any such funds deposited with the Paying Agent by NEES shall be
invested by the Paying Agent as directed by NEES or LLC.
(b) Exchange Procedure. As soon as practicable after the
Effective Time, the Paying Agent shall mail to each holder of record of a
certificate or certificates (the "Certificates") which immediately prior to the
Effective Time represented outstanding EUA Shares (the "Canceled Shares") that
were canceled and became instead the right to receive the Merger Consideration
pursuant to Section 2.01(b)(ii): (i) a letter of transmittal in such form as
NEES and EUA may reasonably agree (which shall specify that delivery shall be
effected, and risk of loss and title to the Certificates shall pass, only upon
actual delivery of the Certificates to the Paying Agent) and (ii) instructions
for effecting the surrender of the Certificates in exchange for the Merger
Consideration. Upon surrender of a Certificate or Certificates to the Paying
Agent for cancellation (or to such other agent or agents as may be appointed by
NEES and are reasonably acceptable to EUA), together with a duly executed letter
of transmittal and such other documents as the Paying Agent shall require, the
holder of such Certificate shall be entitled to receive the Merger Consideration
in exchange for each EUA Share formerly evidenced by such Certificate which such
holder has the right to receive pursuant to Section 2.01(b)(ii). In the event of
a transfer of ownership of Canceled Shares which is not registered in the
transfer records of EUA, the Merger Consideration in respect of such Canceled
Shares may be given to the transferee thereof if the Certificate or Certificates
representing such Canceled Shares is presented to the Paying Agent, accompanied
by all documents required to evidence and effect such transfer and by evidence
satisfactory to the Paying Agent that any applicable stock transfer taxes have
been paid. At any time after the Effective Time, each Certificate shall be
deemed to represent only the right to receive the Merger Consideration subject
to and upon the surrender of such Certificate as contemplated by this Section
2.02. No interest shall be paid or will accrue on the Merger Consideration
payable to holders of Certificates pursuant to Section 2.01(b)(ii).
(c) No Further Ownership Rights in EUA Shares. The Merger
Consideration paid upon the surrender of Certificates in accordance with the
terms of Section 2.01(b)(ii) shall be deemed to have been paid at the Effective
Time in full satisfaction of all rights pertaining to EUA Shares represented
thereby. From and after the Effective Time, the share transfer books of EUA
shall be closed and there shall be no further registration of transfers thereon
of EUA Shares which were outstanding immediately prior to the Effective Time.
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<PAGE>
If, after the Effective Time, Certificates are presented to NEES for any reason,
they shall be canceled and exchanged as provided in this Section 2.02.
(d) Lost, Stolen or Destroyed Certificates. In the event any
owner of any Certificate shall claim that such Certificate shall have been lost,
stolen or destroyed, upon the making of an affidavit of that fact by the owner
of such Certificate and delivery of that affidavit to the Paying Agent and, if
required by NEES or LLC, the posting by such person of a bond in customary
amount as indemnity against any claim that may be made against NEES, EUA or the
Surviving Entity with respect to such Certificate, the Paying Agent will issue
in exchange for such lost, stolen or destroyed Certificate the Merger
Consideration payable upon due surrender of, and deliverable pursuant to this
Section 2.02 in respect of, EUA Shares to which such Certificate relates.
(e) Termination of Exchange Fund. Any portion of the Exchange
Fund which remains undistributed to the shareholders of EUA for one (1) year
after the Effective Time shall be delivered to the Surviving Entity, upon
demand, and any Shareholders of EUA who have not theretofore complied with this
Article II shall thereafter look only to the Surviving Entity (subject to
abandoned property, escheat and other similar laws) as general creditors for
payment of their claim for the Merger Consideration payable upon due surrender
of the Certificates held by them. None of NEES, LLC or the Surviving Entity
shall be liable to any former holder of EUA Shares for the Merger Consideration
delivered to a public official pursuant to any applicable abandoned property,
escheat or similar law.
2.03 Withholding Rights. Each of the Surviving Entity and NEES shall
be entitled to deduct and withhold from the consideration otherwise payable
pursuant to this Agreement to any holder of EUA Shares such amounts as it is
required to deduct and withhold with respect to the making of such payment under
the Internal Revenue Code of 1986, as amended (the "Code"), or any other
provision of state, local or foreign tax law. To the extent that amounts are so
withheld by the Surviving Entity or NEES, as the case may be, such withheld
amounts shall be treated for all purposes of this Agreement as having been paid
to the holder of EUA Shares in respect of which such deduction and withholding
was made by the Surviving Entity or NEES, as the case may be.
ARTICLE III
THE CLOSING
The closing of the Merger and other transactions contemplated hereby
(the "Closing") will take place at the offices of Skadden, Arps, Slate, Meagher
& Flom LLP, 919 Third Avenue, New York, New York 10022, at 10:00 a.m., local
time, on the second business day following satisfaction or waiver (where
applicable) of the conditions set forth in Article VIII (other than those
conditions that by their nature are to be fulfilled at the Closing, but subject
to the fulfillment or waiver of such conditions), unless another date, time or
place is agreed to in writing by the parties hereto (the "Closing Date").
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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EUA
EUA represents and warrants to NEES and LLC as follows:
4.01 Organization and Qualification. (a) EUA is a voluntary
association duly organized, validly existing and in good standing under the laws
of the Commonwealth of Massachusetts and has full power, authority and legal
right to own its property and assets and to transact the business in which it is
engaged. Each of EUA's Subsidiaries is a corporation duly organized or
incorporated, validly existing and in good standing under the laws of its
jurisdiction of organization or incorporation and has full corporate power and
authority to conduct its business as and to the extent now conducted and to own,
use and lease its assets and properties, except where failure to be so organized
or incorporated, existing and in good standing or to have such power and
authority, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect. As used in this Agreement, the term "EUA
Material Adverse Effect" means a material adverse effect on the business,
assets, results of operations, condition (financial or otherwise) or prospects
of EUA and its Subsidiaries taken as a whole. Each of EUA and its Subsidiaries
is duly qualified, licensed or admitted to do business and is in good standing
in each jurisdiction in which the ownership, use or leasing of its assets and
properties, or the conduct or nature of its business, makes such qualification,
licensing or admission necessary, except where failure to be so qualified,
licensed or admitted and in good standing, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect. Section
4.01 of the letter dated the date hereof and delivered to NEES and LLC by EUA
concurrently with the execution and delivery of this Agreement (the "EUA
Disclosure Letter") sets forth (i) the name and jurisdiction of incorporation or
organization of each Subsidiary of EUA, (ii) such Subsidiary's authorized
capital stock, (iii) the number of issued and outstanding shares of capital
stock of such Subsidiary and (iv) the number of shares of such Subsidiary held
of record by EUA. EUA has previously delivered to NEES correct and complete
copies of the EUA Trust Agreement and the certificate or articles of
organization or incorporation and bylaws (or other comparable charter documents)
of its Subsidiaries.
(b) Section 4.01 of the EUA Disclosure Letter sets forth a
description as of the date hereof, of all EUA Associates, including (i) the name
of each such entity and EUA's interest therein and (ii) a brief description of
the principal line or lines of business conducted by each such entity. For
purposes of this Agreement "EUA Associates" shall mean any corporation or other
entity (including partnerships and other business associations) that is not a
Subsidiary of EUA in which EUA and/or one or more of its Subsidiaries, directly
or indirectly, owns an equity interest (other than short-term investments in the
ordinary course of business) if such corporation or other entity (including
partnerships and other business associations) contributes five percent or more
of EUA's consolidated revenues, assets, income or costs.
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<PAGE>
4.02 Capital Stock. (a) The authorized equity securities of EUA
consists of 36,000,000 EUA Shares, of which 20,435,997 shares were issued and
outstanding as of the close of business on January 29, 1999. As of the close of
business on January 29, 1999, no EUA Shares were held in the treasury of EUA.
Since such date there has been no change in the sum of the issued and
outstanding EUA Shares. All of the issued and outstanding EUA Shares are duly
authorized, validly issued, fully paid and nonassessable. Except pursuant to
this Agreement and except as described in Section 4.02 of the EUA Disclosure
Letter, on the date hereof there are no outstanding subscriptions, options,
warrants, rights (including share appreciation rights), preemptive rights or
other contracts, commitments, understandings or arrangements, including any
right of conversion or exchange under any outstanding security, instrument or
agreement (together, "Options"), obligating EUA or any of its Subsidiaries to
issue or sell any shares of equity securities of EUA or to grant, extend or
enter into any Option with respect thereto. The EUA Disclosure Letter sets forth
all capital stock authorized, issued and outstanding at subsidiary levels as of
the close of business on January 29, 1999.
(b) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, all of the
outstanding shares of capital stock of each Subsidiary of EUA are duly
authorized, validly issued, fully paid and nonassessable and are owned,
beneficially and of record, by EUA or a Subsidiary, which is wholly owned,
directly or indirectly, by EUA, free and clear of any liens, claims, mortgages,
encumbrances, pledges, security interests, equities and charges of any kind
(each a "Lien"). Except as disclosed in EUA SEC Reports filed prior to the date
of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are no (i)
outstanding Options obligating EUA or any of its Subsidiaries to issue or sell
any shares of capital stock of any Subsidiary of EUA or to grant, extend or
enter into any such Option or (ii) voting trusts, proxies or other commitments,
understandings, restrictions or arrangements in favor of any person other than
EUA or a Subsidiary which is wholly owned, directly or indirectly, by EUA with
respect to the voting of, or the right to participate in, dividends or other
earnings on any capital stock of any Subsidiary of EUA.
(c) Except as disclosed in EUA SEC Reports filed prior to the
date of this Agreement or Section 4.02 of the EUA Disclosure Letter, there are
no outstanding contractual obligations of EUA or any Subsidiary of EUA to
repurchase, redeem or otherwise acquire any EUA Shares or any capital stock of
any Subsidiary of EUA or to provide funds to, or make any investment (in the
form of a loan, capital contribution or otherwise) in, any Subsidiary of EUA or
any other person.
(d) As of the date of this Agreement, no bonds, debentures,
notes or other indebtedness of EUA or any Subsidiary of EUA having the right to
vote (or which are convertible into or exercisable for securities having the
right to vote) (together "EUA Voting Debt") on any matters on which Shareholders
may vote are issued or outstanding nor are there any outstanding Options
obligating EUA or any of its Subsidiaries to issue or sell any EUA Voting Debt
or to grant, extend or enter into any Option with respect thereto.
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<PAGE>
4.03 Authority. EUA has full power and authority to enter into this
Agreement, to perform its obligations hereunder and, subject to obtaining EUA
Shareholders' Approval (as defined in Section 7.03(b)) and EUA Required
Statutory Approvals (as defined in Section 4.04(b)), to consummate the Merger
and other transactions contemplated hereby. The execution, delivery and
performance of this Agreement by EUA and the consummation by EUA of the Merger
and other transactions contemplated hereby have been duly authorized by all
necessary action on the part of EUA, subject to obtaining EUA Shareholders'
Approval with respect to the consummation of the Merger and the other
transactions contemplated hereby. This Agreement has been duly and validly
executed and delivered by EUA and constitutes a legal, valid and binding
obligation of EUA enforceable against EUA in accordance with its terms, except
as enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
4.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by EUA do not, and the performance by EUA of its
obligations hereunder and the consummation of the Merger and other transactions
contemplated hereby will not, conflict with, result in a violation or breach of,
constitute (with or without notice or lapse of time or both) a default under,
result in or give to any person any right of payment or reimbursement,
termination, cancellation, modification or acceleration of, or result in the
creation or imposition of any Lien upon any of the assets or properties of EUA
or any of its Subsidiaries or any of the terms, conditions or provisions of (i)
the EUA Trust Agreement or the certificates or articles of incorporation or
organization or bylaws (or other comparable charter documents) of EUA's
Subsidiaries, or (ii) subject to the obtaining of EUA Shareholders' Approval,
EUA Required Consents, EUA Required Statutory Approvals and the taking of any
other actions described in this Section 4.04, (x) any statute, law, rule,
regulation or ordinance (together, "laws"), or any judgment, decree, order,
writ, permit or license (together, "orders"), of any court, tribunal,
arbitrator, authority, agency, commission, official or other instrumentality of
the United States, any foreign country or any domestic or foreign state, county,
city or other political subdivision (a "Governmental Authority") applicable to
EUA or any of its Subsidiaries or any of their respective assets or properties,
or (y) subject to obtaining the third-party consents set forth in Section 4.04
of the EUA Disclosure Letter (the "EUA Required Consents"), any note, bond,
mortgage, security agreement, indenture, license, franchise, permit, concession,
contract, lease or other instrument, obligation or agreement of any kind
(together, "Contracts") to which EUA or any of its Subsidiaries is a party or by
which EUA or any of its Subsidiaries or any of their respective assets or
properties is bound, excluding from the foregoing clauses (x) and (y) such
conflicts, violations, breaches, defaults, payments or reimbursements,
terminations, cancellations, modifications, accelerations and creations and
impositions of Liens which, individually or in the aggregate, could not
reasonably be expected to have an EUA Material Adverse Effect.
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(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by EUA or the consummation by
EUA of the Merger and other transactions contemplated hereby except as described
in Section 4.04 of the EUA Disclosure Letter or the failure of which to obtain
could not reasonably be expected to result in an EUA Material Adverse Effect
(the "EUA Required Statutory Approvals," it being understood that references in
this Agreement to "obtaining" such EUA Required Statutory Approvals shall mean
making such declarations, filings or registrations; giving such notices;
obtaining such authorizations, consents or approvals; and having such waiting
periods expire as are necessary to avoid a violation of law).
4.05 SEC Reports, Financial Statements and Utility Reports. (a) EUA
delivered to NEES prior to the execution of this Agreement a true and complete
copy of each form, report, schedule, registration statement, registration
exemption, if applicable, definitive proxy statement and other document
(together with all amendments thereof and supplements thereto) filed by EUA or
any of its Subsidiaries with the Securities and Exchange Commission (the "SEC")
under the Securities Act of 1933, as amended, and the rules and regulations
thereunder (the "Securities Act") and the Securities Exchange Act of 1934, as
amended, and the rules and regulations thereunder (the "Exchange Act") since
December 31, 1995 (as such documents have since the time of their filing been
amended or supplemented, the "EUA SEC Reports"), which are all the documents
(other than preliminary materials) that EUA and its Subsidiaries were required
to file with the SEC under the Securities Act and the Exchange Act since such
date. As of their respective dates, EUA SEC Reports (i) complied as to form in
all material respects with the requirements of the Securities Act or the
Exchange Act, as the case may be, and (ii) did not contain any untrue statement
of a material fact or omit to state a material fact required to be stated
therein or necessary in order to make the statements therein, in light of the
circumstances under which they were made, not misleading. Each of the audited
consolidated financial statements and unaudited interim consolidated financial
statements (including, in each case, the notes, if any, thereto) included in EUA
SEC Reports (the "EUA Financial Statements") complied as to form in all material
respects with the published rules and regulations of the SEC with respect
thereto, were prepared in accordance with U.S. generally accepted accounting
principles ("US GAAP") applied on a consistent basis during the periods involved
(except as may be indicated therein or in the notes thereto and except with
respect to unaudited statements as permitted by Form 10-Q of the SEC) and fairly
present (subject, in the case of the unaudited interim financial statements, to
normal, recurring year-end audit adjustments (which are not expected to be,
individually or in the aggregate, materially adverse to EUA and its Subsidiaries
taken as a whole)) the consolidated financial position of EUA and its
consolidated subsidiaries as at the respective dates thereof and the
consolidated results of their operations and cash flows for the respective
periods then ended. Except as set forth in Section 4.05 of the EUA Disclosure
Letter, each Subsidiary of EUA is treated as a consolidated subsidiary of EUA in
EUA Financial Statements for all periods covered thereby.
(b) All filings (other than immaterial filings) required to be
made by EUA or any of its Subsidiaries since December 31, 1995, under the Public
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Utility Holding Company Act of 1935 (the "1935 Act"), the Federal Power Act, the
Atomic Energy Act of 1954, the Communications Act of 1934, and applicable state
laws and regulations, have been filed with the SEC, the Federal Energy
Regulatory Commission (the "FERC"), the Department of Energy (the "DOE"), the
Nuclear Regulatory Commission (the "NRC"), the Federal Communications Commission
(the "FCC") or any appropriate state public utility commissions (including,
without limitation, to the extent required, the state public utility regulatory
agencies of Massachusetts, Rhode Island, New Hampshire, Maine, Vermont and
Connecticut as the case may be, including all forms, statements, reports,
agreements (oral or written) and all documents, exhibits, amendments and
supplements appertaining thereto, including but not limited to all rates,
tariffs, franchises, service agreements and related documents and all such
filings complied, as of their respective dates, in all material respects with
all applicable requirements of the appropriate statutes and the rules and
regulations thereunder.
4.06 Absence of Certain Changes or Events. Except as set forth in
Section 4.06 of the EUA Disclosure Letter or as disclosed in EUA SEC Reports
filed prior to the date of this Agreement since December 31, 1997, EUA and each
of EUA's Subsidiaries have conducted its business only in the ordinary course of
business consistent with past practice and there has not been, and no fact or
condition exists which, individually or in the aggregate, has or could
reasonably be expected to have an EUA Material Adverse Effect.
4.07 Legal Proceedings. Except as disclosed in EUA SEC Reports filed
prior to the date of this Agreement or in Section 4.07 of the EUA Disclosure
Letter and except for environmental matters which are governed by Section 4.13,
(i) there are no actions, claims, hearings, suits, arbitrations or proceedings
pending or, to the knowledge of EUA or any of its Subsidiaries, threatened
against, specifically relating to or affecting, and, to the knowledge of EUA or
any of its Subsidiaries, there are no Governmental Authority investigations or
audits pending or threatened against, specifically relating to or affecting, EUA
or any of its Subsidiaries or any of their respective assets and properties
which, individually or in the aggregate, could reasonably be expected to have an
EUA Material Adverse Effect and (ii) neither EUA nor any of its Subsidiaries is
subject to any order of any Governmental Authority which, individually or in the
aggregate, could reasonably be expected to have an EUA Material Adverse Effect.
4.08 Information Supplied. (a) The proxy statement relating to EUA
Shareholders' Meeting, as amended or supplemented from time to time (as so
amended and supplemented, the "Proxy Statement"), and any other documents to be
filed by EUA with the SEC (including, without limitation, under the 1935 Act) or
any other Governmental Authority in connection with the Merger and other
transactions contemplated hereby will comply as to form in all material respects
with the requirements of the Exchange Act, the Securities Act and the 1935 Act,
as applicable, and will not, on the date of their respective filings or, in the
case of the Proxy Statement, at the date it is mailed to Shareholders of EUA and
at the time of EUA Shareholders' Meeting (as defined in Section 7.03), contain
any untrue statement of a material fact or omit to state any material fact
necessary in order to make the statements therein, in light of the circumstances
under which they are made, not misleading.
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(b) Notwithstanding the foregoing provisions of this Section
4.08, no representation or warranty is made by EUA with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by NEES or LLC for inclusion or incorporation by reference therein.
4.09 Compliance. Except as set forth in Section 4.09 of the EUA
Disclosure Letter, or as disclosed in EUA SEC Reports filed prior to the date
hereof, neither EUA nor any of EUA's Subsidiaries is in violation of, is, to the
knowledge of EUA, under investigation with respect to any violation of, or has
been given notice or been charged with any violation of, any law, statute,
order, rule, regulation, ordinance or judgment (including, without limitation,
any applicable environmental law, ordinance or regulation) of any Governmental
Authority, except for possible violations which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect. Except as set forth in Section 4.09 of the EUA Disclosure Letter or as
disclosed in EUA SEC Reports filed prior to the date hereof, EUA and EUA's
Subsidiaries have all permits, licenses, franchises and other governmental
authorizations, consents and approvals necessary to conduct their businesses as
presently conducted except for such failures which could not reasonably be
expected to have an EUA Material Adverse Effect. Neither EUA nor any of EUA's
Subsidiaries is in breach or violation of, or in default in the performance or
observance of any term or provision of, (i) the EUA Trust Agreement, in the case
of EUA, or articles of incorporation or organization or by-laws, in the case of
EUA's Subsidiaries, or (ii) any contract, commitment, agreement, indenture,
mortgage, loan agreement, note, lease, bond, license, approval or other
instrument to which it is a party or by which EUA or any Subsidiary of EUA is
bound or to which any of their respective property is subject, except for
possible violations, breaches or defaults which, individually or in the
aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
4.10 Taxes. Except as disclosed in Section 4.10 of the EUA Disclosure
Letter:
(a) Filing of Timely Tax Returns. EUA and each of its
Subsidiaries have timely filed all Tax Returns required to be filed by each of
them under applicable law. All Tax Returns were (and, as to Tax Returns not
filed as of the date hereof, will be) true, complete and correct;
(b) Payment of Taxes. EUA and each of its Subsidiaries have,
within the time and in the manner prescribed by law, paid (and until the Closing
Date will pay within the time and in the manner prescribed by law) all Taxes
that are currently due and payable except for those contested in good faith and
for which adequate reserves have been taken;
(c) Tax Reserves. EUA and its Subsidiaries have established (and
until the Closing Date will maintain) on their books and records adequate
reserves for all Taxes and for any liability for deferred income taxes in
accordance with GAAP;
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(d) Extensions of Time for Filing Tax Returns. Neither EUA nor
any of its Subsidiaries has requested any extension of time within which to file
any Tax Return, which Tax Return has not since been filed;
(e) Waivers of Statute of Limitations. Neither EUA nor any of
its Subsidiaries has in effect any extension, outstanding waivers or comparable
consents regarding the application of the statute of limitations with respect to
any Taxes or Tax Returns;
(f) Expiration of Statute of Limitations. The Tax Returns of
EUA, each of its Subsidiaries and any affiliated, consolidated, combined or
unitary group that includes EUA or any of its Subsidiaries either have been
examined and settled with the appropriate Tax authority or closed by virtue of
the expiration of the applicable statute of limitations for all years through
and including 1993;
(g) Audit, Administrative and Court Proceedings. No audits or
other administrative proceedings or court proceedings are presently pending or
threatened with regard to any Taxes or Tax Returns of EUA or any of its
Subsidiaries (other than those being contested in good faith and for which
adequate reserves have been established) and no issues have been raised in
writing by any Tax authority in connection with any Tax or Tax Return;
(h) Tax Liens. There are no Tax liens upon any asset of EUA or
any of its Subsidiaries except liens for Taxes not yet due.
(i) Powers of Attorney. No power of attorney currently in force
has been granted by EUA or any of its Subsidiaries concerning any Tax matter;
(j) Tax Rulings. Neither EUA nor any of its Subsidiaries has,
during the five year period prior to the date of this Agreement, received a Tax
Ruling (as defined below) or entered into a Closing Agreement (as defined below)
with any taxing authority. "Tax Ruling", as used in this Agreement, shall mean a
written ruling of a taxing authority relating to Taxes. "Closing Agreement", as
used in this Agreement, shall mean a written and legally binding agreement with
a taxing authority relating to Taxes;
(k) Availability of Tax Returns. EUA and its Subsidiaries have
made available to NEES complete and accurate copies, covering all years ending
on or after December 31, 1993, of (i) all Tax Returns, and any amendments
thereto, filed by EUA or any of its Subsidiaries, (ii) all audit reports
received from any taxing authority relating to any Tax Return filed by EUA or
any of its Subsidiaries and (iii) any Closing Agreements entered into by EUA or
any of its Subsidiaries with any taxing authority.
(l) Tax Sharing Agreements. No agreements relating to the
allocation or sharing of Taxes exist between or among EUA and any of its
Subsidiaries and neither EUA nor any of its Subsidiaries (i) has been a member
of an affiliated group filing a consolidated federal income tax return (other
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than a group the common parent of which was EUA) or (ii) has any liability for
Taxes of any Person (other than EUA or its Subsidiaries) under United States
Treasury Regulation Section 1.1502-6 (or any provision of state, local), or
foreign law, as a transferee or successor, by contract or otherwise;
(m) Code Section 481 Adjustments. Neither EUA nor any of its
Subsidiaries is required to include in income any adjustment pursuant to Code
Section 481(a) by reason of a voluntary change in accounting method initiated by
EUA or any of its Subsidiaries, and, the Internal Revenue Service ("IRS") has
not proposed any such adjustment or change in accounting method;
(n) Code Sections 6661 and 6662. All transactions that could
give rise to an understatement of federal income tax, and within the meaning of
Code Section 6662 have been adequately disclosed (or, with respect to Tax
Returns filed following the Closing, will be adequately disclosed) on the Tax
Returns of EUA and its Subsidiaries in accordance with Code Section
6662(d)(2)(B);
(o) Intercompany Transactions. Neither EUA nor any of its
Subsidiaries has engaged in any intercompany transactions within the meaning of
Treasury Regulations ss. 1.1502-13 for which any income or gain will remain
unrecognized as of the close of the last taxable year prior to the Closing Date;
and
(p) Foreign Tax Returns. Neither EUA nor any of its Subsidiaries
is required to file a foreign tax return.
"Taxes" as used in this Agreement, shall mean any federal, state,
county, local or foreign taxes, charges, fees, levies, or other assessments,
including all net income, gross income, premiums, sales and use, ad valorem,
transfer, gains, profits, windfall profits, excise, franchise, real and personal
property, gross receipts, capital stock, production, business and occupation,
employment, disability, payroll, license, estimated, stamp, custom duties,
severance or withholding taxes, other taxes or similar charges of any kind
whatsoever imposed by any governmental entity, whether imposed directly on a
Person or resulting under Treasury Regulation Section 1.1502-6 (or any similar
provision of state, local or foreign law), as a transferee or successor, by
contract or otherwise and includes any interest and penalties on or additions to
any such taxes or in respect of a failure to comply with any requirement
relating to any Tax Return. "Tax Return" as used in this Agreement, shall mean a
report, return or other information required to be supplied to a governmental
entity with respect to Taxes including, where permitted or required, combined,
unitary or consolidated returns for any group of entities.
4.11 Employee Benefit Plans; ERISA. (a) Each "employee benefit plan"
(as defined in Section 3(3) of the Employee Retirement Income Security Act of
1974, as amended ("ERISA")), bonus, deferred compensation, share option or other
written agreement relating to employment or fringe benefits for employees,
former employees, officers, trustees or directors of EUA or any of its
Subsidiaries effective as of the date hereof or providing benefits as of the
date hereof to current employees, former employees, officers, trustees or
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directors of EUA or pursuant to which EUA or any of its subsidiaries has or
could reasonably be expected to have any liability (collectively, the "EUA
Employee Benefit Plans") is listed in Section 4.11(a) of the EUA Disclosure
Letter, is in material compliance with applicable law, and has been administered
and operated in all material respects in accordance with its terms. Each EUA
Employee Benefit Plan which is intended to be qualified within the meaning of
Section 401(a) of the Code has received a favorable determination letter from
the IRS as to such qualification and, to the knowledge of EUA, no event has
occurred and no condition exists which could reasonably be expected to result in
the revocation of, or have any adverse effect on, any such determination.
(b) Complete and correct copies of the following documents have
been made available to NEES as of the date of this Agreement: (i) all EUA
Employee Benefit Plans and any related trust agreements or insurance contracts,
(ii) the most current summary descriptions of each EUA Employee Benefit Plan
subject to ERISA, (iii) the three most recent Form 5500s and Schedules thereto
for each EUA Employee Benefit Plan subject to such reporting, (iv) the most
recent determination of the IRS with respect to the qualified status of each EUA
Employee Benefit Plan that is intended to qualify under Section 401(a) of the
Code, (v) the most recent accountings with respect to each EUA Employee Benefit
Plan funded through a trust and (vi) the most recent actuarial report of the
qualified actuary of each EUA Employee Benefit Plan with respect to which
actuarial valuations are conducted.
(c) Except as set forth in Section 4.11(c) of the EUA Disclosure
Letter, neither EUA nor any Subsidiary maintains or is obligated to provide
benefits under any EUA Employee Benefit Plan (other than as an incidental
benefit under a Plan qualified under Section 401(a) of the Code) which provides
health or welfare benefits to retirees or other terminated employees other than
benefit continuations as required pursuant to Section 601 of ERISA. Each EUA
Employee Benefit Plan subject to the requirements of Section 601 of ERISA has
been operated in material compliance therewith. EUA has not contributed to a
nonconforming group health plan (as defined in Code Section 5000(c)) and no
person under common control with EUA within the meaning of Section 414 of the
Code ("ERISA Affiliate") has incurred a tax liability under Code Section 5000(a)
that is or could reasonably be expected to be a liability of EUA's.
(d) Except as set forth in Section 4.11(d) of the EUA Disclosure
Letter, each EUA Employee Benefit Plan covers only employees who are employed by
EUA or a Subsidiary (or former employees or beneficiaries with respect to
service with EUA or a Subsidiary).
(e) Except as set forth in Section 4.11(e) of the EUA Disclosure
Letter, neither EUA, any Subsidiary, any ERISA Affiliate nor any other
corporation or organization controlled by or under common control with any of
the foregoing within the meaning of Section 4001 of ERISA has, within the
five-year period preceding the date of this Agreement, at any time contributed
to any "multiemployer plan," as that term is defined in Section 4001 of ERISA.
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(f) No event has occurred, and there exists no condition or set
of circumstances in connection with any EUA Employee Benefit Plan, under which
EUA or any Subsidiary, directly or indirectly (through any indemnification
agreement or otherwise), could be subject to any liability under Section 409 of
ERISA, Section 502(i) of ERISA, Title IV of ERISA or Section 4975 of the Code
except for instances of non-compliance which, individually or in the aggregate,
could not reasonably be expected to have an EUA Material Adverse Effect.
(g) Neither EUA nor any ERISA Affiliate has incurred any
liability to the Pension Benefit Guaranty Corporation (the "PBGC") under Section
302(c)(ii), 4062, 4063, 4064 or 4069 of ERISA, or otherwise that has not been
satisfied in full and no event or condition exists or has existed which could
reasonably be expected to result in any such material liability. As of the date
of this Agreement, no "reportable event" within the meaning of Section 4043 of
ERISA has occurred with respect to any EUA Employee Benefit Plan that is a
defined benefit plan under Section 3(35) of ERISA.
(h) Except as set forth in Section 4.11(h) of the EUA Disclosure
Letter, no employer securities, employer real property or other employer
property is included in the assets of any EUA Employee Benefit Plan.
(i) Full payment has been made of all material amounts which EUA
or any affiliate thereof was required under the terms of EUA Employee Benefit
Plans to have paid as contributions to such plans on or prior to the Effective
Time (excluding any amounts not yet due) and no EUA Employee Benefit Plan which
is subject to Part III of Subtitle B of Title I of ERISA has incurred any
"accumulated funding deficiency" within the meaning of Section 302 of ERISA or
Section 412 of the Code, whether or not waived.
(j) Except as set forth in Section 4.11(j) of the EUA Disclosure
Letter, no amounts payable under any EUA Employee Benefit Plan or other
agreement, contract, or arrangement will fail to be deductible for federal
income tax purposes by virtue of Section 280G or Section 162(m) of the Code.
4.12 Labor Matters. As of the date hereof, except as set forth in
Section 4.12 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries is a party to any material collective bargaining agreement or other
labor agreement with any union or labor organization. To the knowledge of EUA,
as of the date hereof, there is no current union representation question
involving employees of EUA or any of its Subsidiaries, nor does EUA know of any
activity or proceeding of any labor organization (or representative thereof) or
employee group to organize any such employees. Except as set forth in Section
4.12 of the EUA Disclosure Letter, (i) there is no unfair labor practice,
employment discrimination or other employment-related complaint or proceeding
against EUA or any of its Subsidiaries pending or, to the knowledge of EUA,
threatened, which has or could reasonably be expected to have an EUA Material
Adverse Effect, (ii) there is no strike, dispute, slowdown, work stoppage or
lockout pending, or, to the knowledge of EUA, threatened, against or involving
EUA or any of its Subsidiaries which has or could reasonably be expected to
have, an EUA Material Adverse Effect and (iii) there is no proceeding, claim,
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suit, or action pending or, to the knowledge of EUA or any of its Subsidiaries,
threatened, nor, to the knowledge of EUA or any of its Subsidiaries is there any
Governmental Authority investigation pending or threatened, in respect of which
any trustee, director, officer, employee or agent of EUA or any of its
Subsidiaries is or may be entitled to claim indemnification from EUA or any of
its Subsidiaries pursuant to the EUA Trust Agreement, in the case of EUA, and
their respective articles of incorporation and by-laws, in the case of EUA's
Subsidiaries, or as provided in the indemnification agreements listed in Section
4.12 of the EUA Disclosure Letter. Except as set forth in Section 4.12 of the
EUA Disclosure Letter, EUA and its Subsidiaries are in compliance with all
federal, state and local laws with respect to employment practices and labor
relations, including, without limitation, any provisions relating to affirmative
action, employment discrimination, wages, hours, collective bargaining, and the
payment of social security and similar taxes, safety and health regulations and
mass layoffs and plant closings except for such instances of noncompliance
which, individually or in the aggregate, could not reasonably be expected to
have an EUA Material Adverse Effect.
4.13 Environmental Matters. Except as disclosed in EUA SEC Reports
filed prior to the date of this Agreement or in Section 4.13 of the EUA
Disclosure Letter:
(a) (i) Each of EUA and its Subsidiaries is in compliance with
all applicable Environmental Laws (as hereinafter defined), except where the
failure to be in compliance, in the aggregate could not reasonably be expected
to result in an EUA Material Adverse Effect; and
(ii) Neither EUA nor any of its Subsidiaries has received
any written communication from any person or Governmental Authority that alleges
that EUA or any of its Subsidiaries is not in such compliance (including the
materiality qualifier set forth in clause (i) above) with applicable
Environmental Laws.
(b) Each of EUA and its Subsidiaries has obtained all
environmental, health and safety permits and governmental authorizations
(collectively, the "Environmental Permits") necessary for the construction of
their facilities and the conduct of their operations, as applicable, and all
such Environmental Permits are in good standing or, where applicable, a renewal
application has been timely filed and agency approval is expected in the
ordinary course of business, and EUA and its Subsidiaries are in compliance with
all terms and conditions of the Environmental Permits, except where the failure
have such Environmental Permits, file a renewal application for such
Environmental Permits, or to be in compliance with such Environmental Permits,
in the aggregate could not reasonably be expected to result in an EUA Material
Adverse Effect.
(c) There is no Environmental Claim (as hereinafter defined)
that could, individually or in the aggregate, reasonably be expected to have an
EUA Material Adverse Effect pending (i) against EUA or any of its Subsidiaries;
(ii) against any person or entity whose liability for any Environmental Claim
EUA or any of its Subsidiaries has or may have retained or assumed either
contractually or by operation of law; or (iii) against any real or personal
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property or operations which EUA or any of its Subsidiaries owns, leases or
manages, in whole or in part.
(d) To the knowledge of EUA there have not been any material
Releases (as hereinafter defined) of any Hazardous Material (as hereinafter
defined) that would be reasonably likely to form the basis of any material
Environmental Claim against EUA or any of its Subsidiaries, or against any
person or entity whose liability for any material Environmental Claim EUA or any
of its Subsidiaries has or may have retained or assumed either contractually or
by operation of law, except for any Environmental Claim that, individually or in
the aggregate, could not reasonably be expected to have an EUA Material Adverse
Effect.
(e) To the knowledge of EUA with respect to any predecessor of
EUA or any of its Subsidiaries, there is no material Environmental Claim pending
or threatened, and there has been no Release of Hazardous Materials that could
reasonably be expected to form the basis of any material Environmental Claim
except for any Environmental Claim that, individually or in the aggregate, could
not be reasonably be expected to have an EUA Material Adverse Effect.
(f) As used in this Section 4.13:
(i) "Environmental Claim" means any and all written
administrative, regulatory or judicial actions, suits, demands, demand letters,
directives, claims, liens, investigations, proceedings or notices or
noncompliance, liability or violation by any person or entity (including any
Governmental Authority) alleging potential liability (including, without
limitation, potential responsibility or liability for enforcement, investigatory
costs, cleanup costs, governmental response costs, removal costs, remedial
costs, natural resources damages, property damages, personal injuries or
penalties) arising out of, based on or resulting from
(A) the presence, or Release or threatened Release into the
environment, of any Hazardous Materials at any
location, whether or not owned, operated, leased or
managed by EUA or any of its Subsidiaries; or
(B) circumstances forming the basis of any violation, or
alleged violation, of any Environmental Law; or
(C) any and all claims by any third party seeking damages,
contribution, indemnification, cost recovery,
compensation or injunctive relief resulting from the
presence or Release of any Hazardous Materials;
(ii) "Environmental Laws" means all federal, state and local
laws, rules and regulations and binding interpretation thereof, relating to
pollution, the environment (including, without limitation, ambient air, surface
water, groundwater, land surface or subsurface strata) or protection of human
health as it relates to the environment including, without limitation, laws and
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regulations relating to Releases or threatened Releases of Hazardous
Materials, or otherwise relating to the manufacture, generation, processing,
distribution, use, treatment, storage, disposal, transport or handling of
Hazardous Materials;
(iii) "Hazardous Materials" means (A) any petroleum or
petroleum products, radioactive materials, asbestos in any form that is or could
become friable, urea formaldehyde foam insulation, and transformers or other
equipment that contain dielectric fluid containing polychlorinated biphenyls;
and (B) any chemicals, materials or substances which are now defined as or
included in the definition of "hazardous substances", "hazardous wastes",
"hazardous materials", "extremely hazardous wastes", "restricted hazardous
wastes", "toxic substances", "toxic pollutants", or words of similar import,
under any Environmental Law; and (c) any other chemical, material, substance or
waste, exposure to which is now prohibited, limited or regulated under any
Environmental Law in a jurisdiction in which EUA or any of its Subsidiaries (x)
operates or (y) stores, treats or disposes of Hazardous Materials; and
(iv) "Release" means any release, spill, emission, leaking,
injection, deposit, disposal, discharge, dispersal, leaching or migration into
the atmosphere, soil, surface water, groundwater or property.
4.14 Regulation as a Utility. (a) EUA is a public utility holding
company registered under Section 5, and subject to the provisions, of the 1935
Act. Section 4.14 of the EUA Disclosure Letter lists the subsidiaries of EUA
that are "public utility companies" within the meaning of Section 2(a)(5) of the
1935 Act and lists the jurisdictions where each such Subsidiary is subject to
regulation as a public utility company or public service company. Except as set
forth above and as set forth in Section 4.14 of the EUA Disclosure Letter,
neither EUA nor any "subsidiary company" or "affiliate" of EUA is subject to
regulation as a public utility or public service company (or similar
designation) by the federal government of the United States, any state in the
United States or any political subdivision thereof, or any foreign country.
(b) As used in this Section 4.14, the terms "subsidiary company"
and "affiliate" shall have the respective meanings ascribed to them in Section
2(a)(8) and Section 2(a)(11), respectively, of the 1935 Act.
4.15 Insurance. Except as set forth in Section 4.15 of the EUA
Disclosure Letter, each of EUA and its Subsidiaries is, and has been
continuously since January 1, 1994, insured with financially responsible
insurers in such amounts and against such risks and losses as are customary in
all material respects for companies in the United States conducting the business
conducted by EUA and its Subsidiaries during such time period. Except as set
forth in Section 4.15 of the EUA Disclosure Letter, neither EUA nor any of its
Subsidiaries has received any notice of cancellation or termination with respect
to any material insurance policy of EUA or any of its Subsidiaries. The
insurance policies of EUA and each of its Subsidiaries are valid and enforceable
policies.
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4.16 Nuclear Facilities. Montaup Electric Company, a Subsidiary of
EUA, is a minority common stockholder of each of Connecticut Yankee Atomic Power
Company, Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power
Corporation and Yankee Atomic Electric Company (the "Yankee Companies") and a
minority joint owner in Millstone 3 and Seabrook 1 (collectively, as described
in Section 4.16 of the EUA Disclosure Letter, the "EUA Nuclear Facilities").
With respect to its ownership of Millstone 3 and Seabrook 1, Montaup Electric
Company holds the required operating licenses from the NRC. With respect to the
Yankee Companies, each Yankee Company holds its own operating license from the
NRC. Because it is a minority stockholder or a minority joint owner, Montaup
Electric Company does not have responsibility for the operation of EUA Nuclear
Facilities. Except as set forth in Section 4.16 of the EUA Disclosure Letter or
as disclosed in EUA SEC Reports filed prior to the date hereof, to the knowledge
of EUA, neither EUA nor any of its Subsidiaries is in violation of any
applicable health, safety, regulatory and other legal requirement, including NRC
laws and regulations and Environmental Laws, applicable to EUA Nuclear
Facilities except for such failure to comply as could not reasonably be expected
to have a material adverse effect with respect to EUA Nuclear Facilities and the
ownership interest of EUA therein. To the knowledge of EUA, each of EUA Nuclear
Facilities maintains emergency plans designed to respond to an unplanned release
therefrom of radioactive materials into the environment and insurance coverages
consistent with industry practice. EUA has funded, or has caused the funding of,
its portion of the decommissioning cost of each of the EUA Nuclear Facilities
and the storage of spent nuclear fuel consistent with the most recently approved
plan for each of the EUA Nuclear Facilities and FERC authorized rates. Except as
set forth in Section 4.16 of the EUA Disclosure Letter, to the knowledge of EUA,
no EUA Nuclear Facility is as of the date of this Agreement on the List of
Nuclear Power Plants Warranting Increased Regulatory Attention maintained by the
NRC.
4.17 Vote Required. The affirmative vote of two-thirds of the
outstanding EUA Shares voting as a single class (with each EUA Share having one
vote per share) with respect to the approval of the Merger and other
transactions contemplated hereby is the only vote of the holders of any class or
series of equity securities of EUA or its Subsidiaries required to approve this
Agreement and approve the Merger and other transactions contemplated hereby.
4.18 Opinion of Financial Advisor. EUA has received the opinion of
Salomon Smith Barney Inc., dated the date of this Agreement, to the effect that,
as of such date, the Merger Consideration is fair from a financial point of view
to the holders of EUA Shares. A true and complete copy of the written opinion
will be delivered to NEES promptly after receipt thereof by EUA.
4.19 Ownership of NEES Common Shares. Neither EUA nor any of its
Subsidiaries or other affiliates beneficially owns any NEES Common Shares.
4.20 State Anti-Takeover Statutes. EUA has taken all necessary actions
so that the provisions of Chapters 110C, 110D or 110F of the MGL will not apply
to this Agreement, the Merger or other transactions contemplated hereby or
thereby.
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4.21 Year 2000. The Information Systems operated by EUA and its
Subsidiaries which is used in the conduct of their business is capable of
providing or being adapted to provide uninterrupted millennium functionality to
record, store, process and present calendar dates falling on or after January 1,
2000 in substantially the same manner and with the same functionality as such
Information Systems record, store, process and present such calendar dates
falling on or before December 31, 1999 other than such interruptions in
millennium functionality that could not, individually or in the aggregate,
reasonably be expected to result in a EUA Material Adverse Effect. EUA
reasonably believes as of the date hereof that the remaining cost of adaptations
referred to in the foregoing sentence will not exceed the amounts reflected in
the Form 10-Q filed by EUA for the quarter ended September 30, 1998 (excluding
the fees and costs of any Y2K Consultant retained pursuant to Section 6.01(o)
hereof and of the implementation of any recommendations by such Y2K Consultant
actually made by EUA that are not already part of EUA's compliance plan as of
the date hereof). "Information Systems" means mainframe and midrange hardware,
operating system software and applications programs; network and desktop (PC)
hardware, operating system software and applications programs; EDI (Electronic
Date Interchange) and FTP (File Transfer Protocol) software; and embedded
systems hardware and applications software.
4.22 EUA Associates. The representations and warranties set forth in
Sections 4.04(a), 4.06, 4.07, 4.09, 4.12 and 4.13 are true and correct in all
material respects with regard to EUA Associates.
ARTICLE V
REPRESENTATIONS AND WARRANTIES OF NEES
NEES represents and warrants to EUA as follows:
5.01 Organization and Qualification. NEES is a voluntary association
duly organized, validly existing and in good standing under the laws of the
Commonwealth of Massachusetts and has full power, authority and legal right to
own its property and assets and to transact the business in which it is engaged.
Each of the NEES Subsidiaries is a corporation duly organized or incorporated,
validly existing and in good standing under the laws of its jurisdiction of
organization or incorporation and has full corporate power and authority to
conduct its business as and to the extent now conducted and to own, use and
lease its assets and properties, except where failure to be so organized or
incorporated, existing and in good standing or to have such power and authority,
individually or in the aggregate, could not reasonably be expected to have a
NEES Material Adverse Effect. As used in this Agreement, the term "NEES Material
Adverse Effect" means a material adverse effect on the business, assets, results
of operations, condition (financial or otherwise) or prospects of NEES and its
Subsidiaries taken as a whole. LLC is a limited liability company validly
existing under the laws of the Commonwealth of Massachusetts. LLC was formed
solely for the purpose of engaging in the Merger and other transactions
contemplated hereby, has engaged in no other business activities (other than in
connection with the formation and capitalization of LLC pursuant to or in
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accordance with the LLC Agreement (as defined below)) and has conducted its
operations only as contemplated hereby and by the LLC Agreement. Each of NEES
and its Subsidiaries is duly qualified, licensed or admitted to do business and
is in good standing in each jurisdiction in which the ownership, use or leasing
of its assets and properties, or the conduct or nature of its business, makes
such qualification, licensing or admission necessary, except where failure to be
so qualified, licensed or admitted and in good standing, individually or in the
aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect. NEES has previously delivered to EUA correct and complete copies of its
Agreement and Declaration of Trust (the "NEES Trust Agreement") and the articles
of association of LLC.
5.02 Authority. Each of NEES and LLC has full power and authority to
enter into this Agreement, and to perform its obligations hereunder, and to
consummate the Merger and other transactions contemplated hereby. The execution,
delivery and performance of this Agreement by each of NEES and LLC and the
consummation by each of NEES and LLC of the Merger and other transactions
contemplated hereby have been duly authorized by all necessary corporate action
on the part of NEES and all necessary action on the part of LLC. This Agreement
has been duly and validly executed and delivered by each of NEES and LLC and
constitutes a legal, valid and binding obligation of each of NEES and LLC
enforceable against each of NEES and LLC in accordance with its terms, except as
enforceability may be limited by bankruptcy, insolvency, reorganization,
moratorium or other similar laws affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether such
enforceability is considered in a proceeding in equity or at law).
5.03 Capital Stock. The authorized equity securities of NEES consists
of 150,000,000 common shares of NEES (the "NEES Shares"), of which 59,170,986
shares were issued and outstanding as of the close of business on January 29,
1999. As of the close of business on January 29, 1999, 5,798,666 NEES Shares
were held in the treasury of NEES. All of the issued and outstanding NEES Shares
are duly authorized, validly issued, fully paid and nonassessable. Except as may
be provided by the New England Electric System Companies' Incentive Share Plan,
the New England Electric System Companies Incentive Thrift Plan I, the New
England Electric System Companies Incentive Thrift Plan II, the New England
Electric Companies Long-Term Performance Share Award Plan, and the New England
Electric System Directors' annual retainer shares, and except as set forth in
Section 5.03 of the letter dated the date hereof and delivered to EUA by NEES
and LLC concurrently with the execution and delivery of this Agreement (the
"NEES Disclosure Letter"), on the date hereof there are no outstanding Options
obligating NEES or any of its Subsidiaries to issue or sell any shares of equity
securities of NEES or to grant, extend or enter into any Option with respect
thereto.
5.04 Non-Contravention; Approvals and Consents. (a) The execution and
delivery of this Agreement by each of NEES and LLC do not, and the performance
by each of NEES and LLC of its obligations hereunder and the consummation of the
Merger and other transactions contemplated hereby will not, conflict with,
result in a violation or breach of, constitute (with or without notice or lapse
of time or both) a default under, result in or give to any person any right of
payment or reimbursement, termination, cancellation, modification or
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acceleration of, or result in the creation or imposition of any Lien upon any of
the assets or properties of NEES, or LLC under, any of the terms, conditions or
provisions of (i) the NEES Agreement and Declaration of Trust or the articles of
organization of LLC, (ii) subject to the actions described in paragraph (b) of
this Section, (x) any laws or orders of any Governmental Authority applicable to
NEES or LLC or any of their respective assets or properties, or (y) subject to
obtaining the third-party consents (the "NEES Required Consents") set forth in
Section 5.04 of the NEES Disclosure Letter any Contracts to which NEES is a
party or by which NEES or any of its Subsidiaries or any of their respective
assets or properties is bound, excluding from the foregoing clauses (x) and (y)
conflicts, violations, breaches, defaults, terminations, modifications,
accelerations and creations and impositions of Liens which, individually or in
the aggregate, could not reasonably be expected to have a NEES Material Adverse
Effect.
(b) No declaration, filing or registration with, or notice to or
authorization, consent or approval of, any Governmental Authority is necessary
for the execution and delivery of this Agreement by NEES or LLC or the
consummation by NEES or LLC of the Merger and other transactions contemplated
hereby except as described in Section 5.04 of the NEES Disclosure Letter or the
failure of which to obtain could not reasonably be expected to result in a NEES
Material Adverse Effect (the "NEES Required Statutory Approvals," it being
understood that references in this Agreement to "obtaining" such NEES Required
Statutory Approvals shall mean making such declarations, filings or
registrations; giving such notices; obtaining such authorizations, consents or
approvals; and having such waiting periods expire as are necessary to avoid a
violation of law).
5.05 Information Supplied. (a) The information supplied by NEES or LLC
and included in the Proxy Statement with the written consent of NEES or LLC, as
the case may be, will not, at the date mailed to EUA's Shareholders or at the
time of EUA Shareholder's Meeting, contain any untrue statements of a material
fact or omit to state any material fact required to be stated therein or
necessary in order to make the statements therein, in light of the circumstances
under which they were made, not misleading.
(b) Notwithstanding the foregoing provisions of this Section
5.05, no representation or warranty is made by NEES with respect to statements
made or incorporated by reference in the Proxy Statement based on information
supplied by EUA for inclusion or incorporation by reference therein or based on
information which is not made in or incorporated by reference in such documents
but which should have been disclosed pursuant to this Section 5.05.
5.06 Compliance. Except as set forth in Section 5.06 of the NEES
Disclosure Letter, or as disclosed in the NEES Reports filed prior to the date
hereof, NEES is not in violation of, is, to the knowledge of NEES, under
investigation with respect to any violation of, or has been given notice or been
charged with any violation of, any law, statute, order, rule, regulation,
ordinance or judgment (including, without limitation, any applicable
environmental law, ordinance or regulation) of any Governmental Authority,
except for possible violations which, individually or in the aggregate, could
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not reasonably be expected to have a NEES Material Adverse Effect. Except as set
forth in Section 5.06 of the NEES Disclosure Letter or as disclosed in the NEES
Reports filed prior to the date hereof, NEES and its Subsidiaries have all
material permits, licenses and other governmental authorizations, consents and
approvals necessary to conduct their businesses as presently conducted which are
material to the operation of the businesses of NEES. NEES is not in breach or
violation of, or in default in the performance or observance of, any term or
provision of, and no event has occurred which, with lapse of time or action by a
third party, could result in a default by NEES under (i) the NEES Agreement and
Declaration of Trust or by-laws or (ii) any contract, commitment, agreement,
indenture, mortgage, loan agreement, note, lease, bond, license, approval or
other instrument to which it is a party or by which NEES is bound or to which
any of their respective property is subject, except for possible violations,
breaches or defaults which, individually or in the aggregate, could not
reasonably be expected to have a NEES Material Adverse Effect.
5.07 Financing. NEES has or will have available, prior to the
Effective Time, sufficient cash in immediately available funds to pay or to
cause LLC to pay the Merger Consideration pursuant to Article II hereof and to
consummate the Merger and other transactions contemplated hereby.
5.08 No Vote Required. No vote of the NEES Shares or of any class or
series of equity securities of NEES or its Subsidiaries is necessary for the
approval of the Merger and other transactions contemplated hereby.
5.09 Ownership of EUA Shares. Neither NEES nor any of its Subsidiaries
or other affiliates beneficially owns any EUA Shares.
5.10 Merger with The National Grid Group plc. NEES has entered into an
Agreement and Plan of Merger dated as of December 11, 1998 by and among The
National Grid Group plc ("National Grid Group"), NGG Holdings LLC (formerly
known as Iosta LLC) and NEES (the "National Grid Merger Agreement"). Pursuant to
Section 6.01 of the National Grid Merger Agreement, NEES has provided a copy of
this Agreement to National Grid Group, and National Grid Group has given NEES
its written consent to enter into this Agreement and consummate the Merger on
the terms set forth in this Agreement. Prior to the execution of this Agreement,
NEES has provided EUA with a copy of such written consent.
ARTICLE VI
COVENANTS
6.01 Covenants of EUA. At all times from and after the date hereof
until the Effective Time, EUA covenants and agrees as to itself and its
Subsidiaries that (except as expressly contemplated or permitted by this
Agreement or as set forth in Section 6.01 of the EUA Disclosure Letter, or to
the extent that NEES shall otherwise previously consent in writing):
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(a) Ordinary Course. EUA and each of its Subsidiaries shall
conduct their businesses only in, and EUA and each of its Subsidiaries shall not
take any action except in, the ordinary course consistent with good utility
practice. Without limiting the generality of the foregoing, EUA and its
Subsidiaries shall use all commercially reasonable efforts to preserve intact in
all material respects their present business organizations and reputation, to
maintain in effect all existing permits, to keep available the services of their
key officers and employees, to maintain their assets and properties in good
working order and condition, ordinary wear and tear excepted, to maintain
insurance on their tangible assets and businesses in such amounts and against
such risks and losses as are currently in effect, to preserve their
relationships with customers and suppliers and others having significant
business dealings with them and to comply in all material respects with all laws
and orders of all Governmental Authorities applicable to them.
(b) Charter Documents. EUA shall not, nor shall it permit any of
its Subsidiaries to, amend or propose to amend the EUA Trust Agreement, in the
case of EUA, and its certificate or articles of incorporation or organization or
bylaws (or other comparable charter documents), in the case of EUA's
Subsidiaries.
(c) Dividends. EUA shall not, nor shall it permit any of its
Subsidiaries to, (i) declare, set aside or pay any dividends on, or make other
distributions in respect of, any of its capital stock or share capital, except:
(A) that EUA may continue the declaration and payment of
regular quarterly dividends on EUA Shares with usual
record and payment dates not, in any fiscal year, in
excess of the dividend for the comparable period in the
prior fiscal year;
(B) that the Subsidiaries of EUA set forth in Section
6.01(c) of the EUA Disclosure Letter may continue the
declaration and payment of dividends on preferred stock
in accordance with the terms of such stock, with the
record and payment dates and in the amounts set forth
in Section 6.01(c) of the EUA Disclosure Letter;
(C) if the Effective Time does not occur between a record
date and payment date of a regular quarterly dividend,
for a special dividend on EUA Shares with respect to
the quarter in which the Effective Time occurs with a
record date on or prior to the date on which the
Effective Time occurs, which does not exceed an amount
equal to the product of (x) the number of days between
the last payment date of a regular quarterly dividend
and the record date of such special dividend,
multiplied by (y) $.0045; and
(D) for dividends and distributions (including liquidating
distributions) by a direct or indirect Subsidiary of
EUA to its parent.
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(ii) split, combine, subdivide, reclassify or take similar action with respect
to any of its capital stock or share capital or issue or authorize or propose
the issuance of any other securities in respect of, in lieu of or in
substitution for shares of its capital stock or comprised in its share capital,
(iii) adopt a plan of complete or partial liquidation or resolutions providing
for or authorizing such liquidation or a dissolution, merger, consolidation,
restructuring, recapitalization or other reorganization or (iv) directly or
indirectly redeem, repurchase or otherwise acquire any shares of its capital
stock or any Option with respect thereto except:
(A) in connection with intercompany purchases of capital
stock or share capital,
(B) for the purpose of funding EUA's dividend reinvestment
and share purchase plan in accordance with past
practice, or
(C) subject to EUA's obligations under the Securities Act
and the Exchange Act, pursuant to EUA's previously
announced share repurchase program provided that the
number of EUA Shares repurchased does not exceed
3,000,000 and the price paid per share does not exceed
95% of the Per Share Amount.
(d) Share Issuances. EUA shall not, nor shall it permit any of
its Subsidiaries to, issue, deliver or sell, or authorize or propose the
issuance, delivery or sale of, any shares of its capital stock or any Option
with respect thereto (other than the issuance by a wholly owned Subsidiary of
its capital stock to its direct or indirect parent corporation, or modify or
amend any right of any holder of outstanding shares of capital stock or Options
with respect thereto).
(e) Acquisitions. EUA shall not, nor shall it permit any of its
Subsidiaries to acquire or agree to acquire (by merging or consolidating with,
or by purchasing a substantial equity interest in or substantial portion of the
assets of, or by any other manner) any business or any corporation, partnership,
association or other business organization or division thereof.
(f) Dispositions. EUA shall not, nor shall it permit any of its
Subsidiaries to sell, lease, securitize, grant any security interest in or
otherwise dispose of or encumber any of its assets or properties, other than
dispositions in the ordinary course of its business consistent with past
practice and having an aggregate value of less than $1,000,000 for each
disposition and $5,000,000 in the aggregate.
(g) Indebtedness. EUA shall not, nor shall it permit any of its
Subsidiaries to incur or guarantee any indebtedness (including any debt borrowed
or guaranteed or otherwise assumed, including, without limitation, the issuance
of debt securities or warrants or rights to acquire debt) or enter into any
"keep well" or other agreement to maintain any financial condition of another
Person or enter into any arrangement having the economic effect of any of the
foregoing other than (i) short-term indebtedness in the ordinary course of
business consistent with past practice (such as the issuance of commercial paper
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or the use of existing credit facilities) in amounts not exceeding the amounts
set forth in Section 6.01(g) of the EUA Disclosure Letter, (ii) long-term
indebtedness in connection with the refinancing of existing indebtedness either
at its stated maturity or at a lower cost of funds (calculating such cost on an
aggregate after-tax basis) or (iii) guarantees or "keep well" agreements in
favor of wholly owned Subsidiaries of EUA in connection with the conduct of the
business of such wholly owned Subsidiaries of EUA not aggregating more than
$1,000,000.
(h) Capital Expenditures. Except (i) as required by law or (ii)
as reasonably deemed necessary by EUA after consulting with NEES following a
catastrophic event, such as a major storm, EUA shall not, nor shall it permit
any of its Subsidiaries to make any capital expenditures or commitments during
any fiscal year that is in excess of 110% of (i) the aggregate amount set forth
in Section 6.01(h) of the EUA Disclosure Letter with respect to EUA and its
Subsidiaries that are public utility companies within the meaning of Section
2(a)(5) of the 1935 Act or (ii) the amount set forth in Section 6.01(h) of the
EUA Disclosure Letter with respect to each of EUA's other Subsidiaries.
(i) Employee Benefits. EUA shall not, nor shall it permit any of
its Subsidiaries to enter into, adopt, amend (except as may be required by
applicable law) or terminate any EUA Employee Benefit Plan, or other agreement,
arrangement, plan or policy between EUA or one of its Subsidiaries and one or
more of its trustees, directors, officers, employees or former employees, or,
except for normal increases in the ordinary course of business, (a) increase in
any manner the compensation or fringe benefits of any trustee, director or
executive officer, (b) increase in any manner the compensation or fringe
benefits of any employee, (c) pay any benefit not required by any plan or
arrangement in effect as of the date hereof or, (d) cause any trustee, director,
officer, employee or former employee of EUA to accrue or receive additional
benefits, accelerate vesting or accelerate the payment of any benefits under any
EUA Employee Benefit Plan, or other agreement, arrangement, plan or policy. EUA,
prior to the Closing Date, shall take all necessary action and make all
necessary amendments to its stock-based plans so that all such plans will be in
a form that allows the plans to function after the Effective Time and after any
merger of EUA and its Subsidiaries into NEES or its Subsidiaries. EUA, prior to
the Closing Date, shall take all necessary actions, in a manner satisfactory to
NEES, so that on or after the Closing Date, neither EUA, the Surviving Entity
nor their affiliates' stock or securities will be required to be held in, or
distributed pursuant to, any EUA Employee Benefit Plan.
(j) Labor Matters. Notwithstanding any other provision of this
Agreement to the contrary, EUA or its Subsidiaries may negotiate successor
collective bargaining agreements to those referenced in Section 4.12 hereof, and
may negotiate other collective bargaining agreements or arrangements as required
by law or for the purpose of implementing the agreements referenced in Section
4.12 hereof. EUA will keep NEES informed as to the status of, and will consult
with NEES as to the strategy for, all negotiations with collective bargaining
representatives. EUA and its Subsidiaries shall act prudently and reasonably and
consistent with their obligation under applicable law in such negotiations.
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(k) Discharge of Liabilities. EUA shall not, nor shall it permit
its Subsidiaries to, pay, discharge or satisfy any material claims, liabilities
or obligations (absolute, accrued, asserted or unasserted, contingent or
otherwise), other than the payment, discharge or satisfaction, in the ordinary
course of business consistent with past practice (which includes the payment of
final and unappealable judgments) or in accordance with their terms, of
liabilities reflected or reserved against in, or contemplated by, the most
recent consolidated financial statements (or the notes thereto) of such party
included in EUA SEC Reports, or incurred in the ordinary course of business
consistent with past practice.
(l) Contracts. EUA shall not, nor shall it permit its
Subsidiaries, except in the ordinary course of business consistent with past
practice or as set forth in Section 6.01(l) of the EUA Disclosure Letter, (i) to
modify, amend, terminate or fail to use commercially reasonable efforts to renew
any material Contract to which EUA or any of its Subsidiaries is a party or
waive, release or assign any material rights or claims or (ii) to enter into any
new material Contracts except as expressly permitted by Sections 6.01 (f), (g)
or (i) and 7.06 hereof.
(m) Equity Investments. EUA shall not, nor shall it permit its
Subsidiaries or affiliates to, make equity contributions to non-affiliates or to
its non-utility Subsidiaries.
(n) Loans. EUA shall not, nor shall it permit its Subsidiaries
or affiliates to, loan money to non-affiliates or to its non-utility
Subsidiaries.
(o) Year 2000. EUA, within 15 days of the date of this
Agreement, shall engage a qualified third party ("Y2K Consultant") to conduct a
detailed assessment of the adequacy and state of completion of its Year 2000
Program, including but not limited to assessment and testing of its customer,
accounting, and operational systems. The Y2K Consultant and scope of work of the
Y2K Consultant shall be acceptable to NEES. Such assessment and testing shall be
completed as soon thereafter as practicable. EUA shall have such assessment
updated by the Y2K Consultant at the end of each fiscal quarter of 1999. EUA
shall allow designated NEES personnel and representatives access to the Y2K
Consultant's personnel, reports and recommendations and access to EUA's
personnel, documents, and information related to the Y2K issue. EUA and the
third party shall meet with such designated NEES personnel and representatives
on a periodic basis (but not less frequently than monthly) to update NEES on
EUA's Year 2000 Program. If this Agreement is terminated pursuant to Section
9.01 hereof, NEES shall reimburse EUA for the costs and expenses of the Y2K
Consultant.
(p) Insurance. EUA shall, and shall cause its Subsidiaries to,
maintain with financially responsible insurance companies (or through
self-insurance, consistent with past practice) insurance in such amounts and
against such risks and losses as are customary for companies engaged in their
respective businesses.
(q) 1935 Act. EUA shall not, nor shall it permit any of its
Subsidiaries to, engage in any activities which would cause a change in its
status, or that of its Subsidiaries, under the 1935 Act.
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(r) Regulatory Matters. Subject to applicable law and except for
non-material filings in the ordinary course of business consistent with past
practice, EUA shall consult with NEES prior to implementing any changes in its
or any of its Subsidiaries' rates or charges, standards of service or accounting
or executing any agreement with respect thereto that is otherwise permitted
under this Agreement and shall, and shall cause its Subsidiaries to, deliver to
NEES a copy of each such filing or agreement at least four (4) business days
prior to the filing or execution thereof so that NEES may comment thereon. EUA
shall, and shall cause its Subsidiaries to, make all such filings (i) only in
the ordinary course of business consistent with past practice or (ii) as
required by a Governmental Authority or regulatory agency with appropriate
jurisdiction.
(s) Accounting. EUA shall not, nor shall it permit any of its
Subsidiaries to make any changes in their accounting methods, policies or
procedures, except as required by law, rule, regulation or applicable generally
accepted accounting principles;
(t) Tax Status. Neither EUA nor any of its Subsidiaries shall
(i) make or rescind any material express or deemed election relating to Taxes,
(ii) make a request for a Tax Ruling or enter into a Closing Agreement, (iii)
settle or compromise any material claim, action, suit, litigation, proceeding,
arbitration, investigation, audit, or controversy relating to Taxes or (iv)
change in any material respect any of its methods of reporting income,
deductions or accounting for federal income tax purposes from those employed in
the preparation of its federal income Tax Return for the taxable year ending
December 31, 1997, except as may be required by applicable law.
(u) No Breach. EUA shall not, nor shall it permit any of its
Subsidiaries to willfully take or fail to take any action that would or is
reasonably likely to result in (i) a material breach of any provision of this
Agreement or (ii) its representations and warranties set forth in this Agreement
being untrue in any material respect on and as of the Closing Date.
(v) Advice of Changes. EUA shall confer with NEES on a regular
and frequent basis with respect to EUA's business and operations and other
matters relevant to the Merger to the extent permitted by law, and shall
promptly advise NEES, orally and in writing, of any material change or event,
including, without limitation, any complaint, investigation or hearing by any
Governmental Authority (or communication indicating the same may be
contemplated) or the institution or threat of material litigation; provided that
EUA shall not be required to make any disclosure to the extent such disclosure
would constitute a violation of any applicable law or regulation.
(w) Notice and Cure. EUA will notify NEES in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to EUA, that causes or will or may be likely to cause any covenant or agreement
of EUA under this Agreement to be breached or that renders or will render untrue
in any material respect any representation or warranty of EUA contained in this
Agreement. EUA also will notify NEES in writing of, and will use all
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commercially reasonable efforts to cure, before the Closing, any material
violation or breach, as soon as practical after it becomes known to EUA, of any
representation, warranty, covenant or agreement made by EUA. No notice given
pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(x) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, EUA will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to the other's obligations contained in
this Agreement and to consummate and make effective the Merger and other
transactions contemplated by this Agreement, and EUA will not, nor will it
permit any of its Subsidiaries to, take or fail to take any action that could be
reasonably expected to result in the nonfulfillment of any such condition.
(y) Third Party Standstill Agreements. Except as provided in
Section 7.08 hereto, during the period from the date of this Agreement through
the Effective Time, neither EUA nor any of its Subsidiaries shall terminate,
amend, modify or waive any provision of any confidentiality or standstill
agreement to which it is a party. During such period, EUA shall take all steps
necessary to enforce, to the fullest extent permitted under applicable law, the
provisions of any such agreement.
6.02 Covenants of NEES. At all times from and after the date hereof
until the Effective Time, NEES covenants and agrees that (except as expressly
contemplated or permitted by this Agreement or to the extent that EUA shall
otherwise previously consent in writing):
(a) No Breach. NEES shall not, nor shall it permit any of its
Subsidiaries to, except as otherwise expressly provided for in this Agreement,
willfully take or fail to take any action that would or is reasonably likely to
result in (i) a material breach of any of its covenants or agreements contained
in this Agreement or (ii) any of its representations and warranties set forth in
Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.06, 5.07, 5.08 and 5.09 of this
Agreement being untrue in any material respect on and as of the Closing Date.
(b) Advice of Changes. NEES shall confer with EUA on a regular
and frequent basis with respect to any matter having, or which, insofar as can
be reasonably foreseen, could reasonably be expected to have, a NEES Material
Adverse Effect or materially impair the ability of NEES to consummate the Merger
and other transactions contemplated hereby; provided that NEES shall not be
required to make any disclosure to the extent such disclosure would constitute a
violation of any applicable law or regulation.
(c) Notice and Cure. NEES will notify EUA in writing of, and
will use all commercially reasonable efforts to cure before the Closing, any
event, transaction or circumstance, as soon as practical after it becomes known
to NEES, that causes or will or may be likely to cause any covenant or agreement
of NEES under this Agreement to be breached or that renders or will render
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untrue in any material respect any representation or warranty of NEES contained
in this Agreement. NEES also will notify EUA in writing of, and will use all
commercially reasonable efforts to cure before the Closing, any material
violation or breach, as soon as practical after it becomes known to such party,
of any representation, warranty, covenant or agreement made by NEES. No notice
given pursuant to this paragraph shall have any effect on the representations,
warranties, covenants or agreements contained in this Agreement for purposes of
determining satisfaction of any condition contained herein.
(d) Fulfillment of Conditions. Subject to the terms and
conditions of this Agreement, NEES will take or cause to be taken all
commercially reasonable steps necessary or desirable and proceed diligently and
in good faith to satisfy each condition to its obligations contained in this
Agreement and to consummate and make effective the Merger and other transactions
contemplated by this Agreement, and NEES will not, nor will it permit any of its
Subsidiaries to, take or fail to take any action that could be reasonably
expected to result in the nonfulfillment of any such condition.
(e) Conduct of Business of LLC. Prior to the Effective Time,
except as may be required by applicable law and subject to the other provisions
of this Agreement, NEES shall cause LLC to (i) perform its obligations under
this Agreement in accordance with its terms, and (ii) not engage directly or
indirectly in any business or activities of any type or kind and not enter into
any agreements or arrangements with any person, or be subject to or bound by any
obligation or undertaking, which is inconsistent with this Agreement.
(f) Certain Mergers. NEES shall not, and shall not permit any of
its Subsidiaries to, acquire or agree to acquire by merging or consolidating
with, or by purchasing a substantial portion of the assets of or equity in, or
by any other manner, any business or any corporation, partnership, association
or other business organization or division thereof, or otherwise acquire or
agree to acquire any assets if the entering into of a definitive agreement
relating to or the consummation of such acquisition, merger or consolidation
could reasonably be expected to (i) impose any material delay in the obtaining
of, or significantly increase the risk of not obtaining, any authorizations,
consents, orders, declarations or approvals of any Governmental Authority
necessary to consummate the Merger or the expiration or termination of any
applicable waiting period, (ii) significantly increase the risk of any
Governmental Authority entering an order prohibiting the consummation of the
Merger, (iii) significantly increase the risk of not being able to remove any
such order on appeal or otherwise or (iv) materially delay the consummation of
the Merger.
6.03 Additional Covenants by NEES and EUA.
(a) Control of Other Party's Business. Nothing contained in this
Agreement shall give NEES, directly or indirectly, the right to control or
direct EUA's operations prior to the Effective Time. Nothing contained in this
Agreement shall give EUA, directly or indirectly, the right to control or direct
NEES' operations prior to the Effective Time. Prior to the Effective Time, each
of EUA and NEES shall exercise, consistent with the terms and conditions of this
Agreement, complete control and supervision over its respective operations.
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(b) Transition Steering Team. As soon as reasonably practicable
after the date hereof, NEES and EUA shall create a special transition steering
team, with representation from EUA and NEES, that will develop recommendations
concerning the future structure and operations of EUA after the Effective Time,
subject to applicable law. The members of the transition steering team shall be
appointed by the Chief Executive Officers of NEES and EUA. The functions of the
transition steering team shall include (i) to direct the exchange of information
and documents between the parties and their Subsidiaries as contemplated by
Section 7.01 and (ii) the development of regulatory plans and proposals,
corporate organizational and management plans, workforce combination proposals,
and such other matters as they deem appropriate.
ARTICLE VII
ADDITIONAL AGREEMENTS
7.01 Access to Information. EUA shall, and shall cause each of its
Subsidiaries to, and shall use commercially reasonable efforts to cause EUA
Associates to, throughout the period from the date hereof to the Effective Time
to the extent permitted by law, (i) provide NEES and its Representatives with
full access, upon reasonable prior notice and during normal business hours, to
all facilities, operations, officers (including EUA's environmental, health and
safety personnel), employees, agents and accountants of EUA and its Subsidiaries
and Associates and their respective assets, properties, books and records, to
the extent EUA or any Subsidiary of EUA or EUA Associate is not under a legal
obligation not to provide access or to the extent that such access would not
constitute a waiver of the attorney client privilege and does not unreasonably
interfere with the business and operations of EUA and its Subsidiaries and
Associates and (ii) furnish promptly to such persons (x) a copy of each report,
statement, schedule and other document filed or received by EUA or any of its
Subsidiaries pursuant to the requirements of federal or state securities laws
and each material report, statement, schedule and other document filed with any
other Governmental Authority, and (y) all other information and data (including,
without limitation, copies of Contracts, EUA Employee Benefit Plans, and other
books and records) concerning the business and operations of EUA and its
Subsidiaries as NEES or any of its Representatives reasonably may request. No
review pursuant to this Section 7.01 or otherwise shall affect any
representation or warranty contained in this Agreement or any condition to the
obligations of the parties hereto. Any such information or material obtained
pursuant to this Section 7.01 that constitutes "Evaluation Material" (as such
term is defined in the letter agreement dated as of December 18, 1998 between
EUA and NEES (the "Confidentiality Agreement")) shall be governed by the terms
of the Confidentiality Agreement. NEES may provide information or materials that
it obtains relating to EUA or any EUA Subsidiary pursuant to this Section 7.01
to National Grid Group; the treatment by National Grid Group of such information
or material shall be governed by the terms of the letter agreement dated as of
December 21, 1998 between EUA and National Grid Group.
7.02 Proxy Statement. As soon as reasonably practicable after the
date of this Agreement, EUA shall prepare and file the Proxy Statement with the
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SEC. NEES and EUA shall cooperate with each other in the preparation of the
Proxy Statement and any amendment or supplement thereto, and EUA shall promptly
notify NEES of the receipt of any comments of the SEC with respect to the Proxy
Statement and of any requests by the SEC for any amendment or supplement thereto
or for additional information, and shall promptly provide to NEES copies of all
correspondence between EUA or any of its Representatives and the SEC with
respect to the Proxy Statement (except reports from financial advisors other
than with the consent of such financial advisors). Each of the parties hereto
shall furnish all information concerning itself which is required or customary
for inclusion in the Proxy Statement. EUA shall consult with NEES regarding the
Proxy Statement and have due regard to any comments NEES may make in relation to
the Proxy Statement. EUA shall give NEES and its counsel the opportunity to
review the Proxy Statement and all responses to requests for additional
information by and replies to comments of the SEC before their being filed with,
or sent to, the SEC. Each of EUA and NEES agrees to use its reasonable best
efforts, after consultation with the other parties hereto, to respond promptly
to all such comments of and requests by the SEC. After obtaining the consent of
EUA, which consent shall not be unreasonably withheld, NEES may provide
information supplied to NEES by EUA to National Grid Group for inclusion of such
information in the Super Class 1 circular ("NGG Circular") to be issued to
shareholders of National Grid Group in connection with approval by such
shareholders of the National Grid Merger Agreement. NEES shall use its best
efforts to provide EUA with a draft of any portion of the NGG Circular with
information relating to EUA prior to the issuance of the NGG Circular.
7.03 Approval of Shareholders. EUA shall, through its Board of
Trustees, duly call, give notice of, convene and hold a meeting of its
shareholders (the "EUA Shareholders' Meeting") for the purpose of voting on the
approval of the Merger and other transactions contemplated hereby (the "EUA
Shareholders' Approval") as soon as reasonably practicable after the date
hereof; provided, however, subject to the fiduciary duties of its Board of
Trustees and the requirements of applicable law, EUA shall include in the Proxy
Statement the recommendation of the Board of Trustees of EUA that the
Shareholders of EUA approve the Merger and the other transactions contemplated
hereby, and shall use its reasonable best efforts to obtain such approval.
7.04 Regulatory and Other Approvals. (a) HSR Filings. Each party
hereto shall file or cause to be filed with the Federal Trade Commission and the
Department of Justice any notifications required to be filed by its respective
"ultimate parent" company under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended (the "HSR Act"), and the rules and regulations promulgated
thereunder with respect to the Merger and other transactions contemplated
hereby. Such parties will use all commercially reasonable efforts to make such
filings in a timely manner and to respond on a timely basis to any requests for
additional information made by either of such agencies.
(b) Other Regulatory Approvals. Each party shall cooperate and
use its best efforts to promptly prepare and file all necessary applications,
notices, petitions, filings and other documents with, and to use all
commercially reasonable efforts to obtain all necessary permits, consents,
approvals and authorizations of, all Governmental Authorities necessary or
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advisable to obtain the EUA Required Statutory Approvals, the NEES Required
Statutory Approvals and the approvals of the state utility commissions referred
to in Section 8.01(d) (collectively, the "NEES-EUA Regulatory Approvals"). The
parties agree that they will consult with each other with respect to obtaining
the NEES-EUA Regulatory Approvals; provided, however, that NEES shall have
primary responsibility for the preparation and filing of any related
applications, filings or other material with the SEC, the FERC, the NRC and
state utility commissions. EUA shall have the right to review and approve in
advance drafts of and final applications, filings and other material (including
material with respect to proposed settlements) submitted to or filed with the
SEC, the FERC, the NRC and state utility commissions or parties to such
proceedings before such Governmental Authority, which approval shall not be
unreasonably withheld or delayed.
(c) NEES-NGG Regulatory Proceedings. EUA and NEES acknowledge
that, at the same time EUA and NEES will be seeking to obtain the NEES-EUA
Regulatory Approvals, National Grid Group and NEES will be seeking to obtain the
regulatory approvals (the "NEES-NGG Regulatory Approvals") required to
consummate the transactions contemplated by the National Grid Merger Agreement.
NEES and EUA agree to seek to prosecute the proceedings relating to the NEES-EUA
Regulatory Approvals (the "NEES-EUA Regulatory Proceedings") separately from the
prosecution by National Grid Group and NEES of the proceedings relating to the
NEES-NGG Regulatory Approvals (the "NEES-NGG Regulatory Proceedings"), but
recognize that one or more of the NEES-EUA Regulatory Proceedings may be
consolidated with one or more of the NEES-NGG Regulatory Proceedings by the
relevant Governmental Authority. Upon the request of EUA, NEES will keep EUA
reasonably apprised of the status of the NEES-NGG Regulatory Proceedings.
7.05 Employee Benefit Plans.
(a) For a period of twelve (12) months immediately following the
Closing Date, the compensation, benefits and coverage provided to those
non-union individuals who continue to be employees of the Surviving Entity (the
"Affected Employees") pursuant to employee benefit plans or arrangements
maintained by NEES or the Surviving Entity shall be, in the aggregate, not less
favorable (as determined by NEES and the Surviving Entity using reasonable
assumptions and benefit valuation methods) than those provided, in the
aggregate, to such Affected Employees immediately prior to the Closing Date. In
addition to the foregoing, NEES shall, or shall cause the Surviving Entity to,
pay any Affected Employee whose employment is terminated by NEES or the
Surviving Entity within twelve (12) months of the Closing Date a severance
benefit package equivalent to the severance benefit package that would be
provided under the NEES Standard Severance Plan as in effect on the date hereof.
(b) NEES shall, or shall cause the Surviving Entity to, give the
Affected Employees full credit for purposes of eligibility, vesting, benefit
accrual (including, without limitation, benefit accrual under any defined
benefit pension plans) and determination of the level of benefits under any
employee benefit plans or arrangements maintained by NEES or the Surviving
Entity in effect as of the Closing Date for such Affected Employees' service
with EUA or any Subsidiary of EUA (or any prior employer) to the same extent
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recognized by EUA or such Subsidiary immediately prior to the Closing Date. With
respect to any employee benefit plan or arrangement established by NEES, EUA or
the Surviving Entity after the Closing Date (the "Post Closing Plans"), service
shall be credited in accordance with the terms of such Post Closing Plans.
(c) NEES shall, or shall cause the Surviving Entity to, (i)
waive all limitations as to preexisting conditions, exclusions and waiting
periods with respect to participation and coverage requirements applicable to
the Affected Employees under any welfare benefit plan established to replace any
EUA welfare benefit plans in which such Affected Employees may be eligible to
participate after the Closing Date, other than limitations or waiting periods
that are already in effect with respect to such Affected Employees and that have
not been satisfied as of the Closing Date under any welfare plan maintained for
the Affected Employees immediately prior to the Closing Date, and (ii) provide
each Affected Employee with credit for any co-payments and deductibles paid
prior to the Closing Date in satisfying any applicable deductible or
out-of-pocket requirements under any welfare plans that such Affected Employees
are eligible to participate in after the Closing Date.
(d)(i) NEES shall, or shall cause the Surviving Entity and its
Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, all EUA Employee Benefit Plans as in effect
on the date hereof; provided, however, that this Section 7.05(d)(i) is not
intended to prevent NEES or the Surviving Entity from exercising their rights
with respect to all EUA Employee Benefit Plans solely in accordance with their
terms, including but not limited to the right to alter, terminate or otherwise
amend such EUA Employee Benefit Plans.
(ii) NEES shall, or shall cause the Surviving Entity and
its Subsidiaries to, honor, and shall guarantee the obligations of the Surviving
Entity and its Subsidiaries under, (A) all employment severance, consulting and
retention agreements or arrangements as in effect on the date hereof, as set
forth in Section 7.05(d)(ii) of the EUA Disclosure Letter, or as modified in
accordance with Section 6.01(i) of the EUA Disclosure Letter (such agreements or
arrangements, the "EUA Employee Agreements" and the individuals who are parties
to such EUA Employee Agreements, the "EUA Executives") and (B) all EUA Employee
Benefit Plans in which such EUA Executives participate; provided, however, that
this Section 7.05(d)(i) is not intended to prevent NEES or the Surviving Entity
from exercising their rights with respect to the EUA Employee Agreements and the
EUA Employee Benefit Plans in which such EUA Executives participate, in each
case solely in accordance with their terms, including but not limited to the
right to alter, terminate or otherwise amend such EUA Employee Agreements and
EUA Employee Benefit Plans.
(e) Notwithstanding the foregoing, NEES and the Surviving Entity
and its subsidiaries shall neither be required to or prevented from merging
EUA's benefit plans, agreements, or arrangements into NEES or the Surviving
Entity and its subsidiaries benefit plans, agreements, or arrangements or from
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replacing EUA's benefit plans, agreements or arrangements with NEES or the
Surviving Entity and its subsidiaries benefit plans, agreements or arrangements.
7.06 Labor Agreements and Workforce Matters.
(a) Labor Agreements. NEES shall honor, or shall cause the
appropriate subsidiaries of the Surviving Entity to honor, all collective
bargaining agreements of EUA or its subsidiaries in effect as of the Effective
Time until their expiration; provided, however, that this undertaking is not
intended to prevent NEES or the Surviving Entity and its subsidiaries from
exercising their rights with respect to such collective bargaining agreements
and in accordance with their terms, including any right to amend, modify,
suspend, revoke or terminate any such contract, agreement, collective bargaining
agreement or commitment or portion thereof.
(b) Workforce Matters. Subject to applicable law and obligations
under applicable collective bargaining agreements, for a period of 2 years
following the Effective Time, any reductions in workforce in respect of
employees of the Surviving Entity and its Subsidiaries shall be made on a fair
and equitable basis as determined by the Surviving Entity, with due
consideration to prior experience and skills, and any employee whose employment
is terminated or job is eliminated during such period shall be entitled to
participate on a fair and equitable basis as determined by NEES or the Surviving
Entity in the job opportunity and employment placement programs offered by NEES
or the Surviving Entity or any of their Subsidiaries for which they are
eligible. Any workforce reductions carried out following the Effective Time by
the Surviving Entity and its Subsidiaries shall be done in accordance with all
applicable collective bargaining agreements and all laws and regulations
governing the employment relationship and termination thereof including, without
limitation, the Worker Adjustment and Retraining Notification Act, and the
regulations promulgated thereunder, and any comparable state or local law.
7.07 Post Merger Operations.
(a) NEES Advisory Board. If the Merger is consummated, then,
promptly following the closing of the merger contemplated by the National Grid
Merger Agreement, NEES shall take such action as is necessary to cause all of
the members of the Board of Directors of EUA to be appointed to serve on the
advisory board to be formed pursuant to Section 7.07(e) of the National Grid
Merger Agreement.
(b) Charities. The parties agree that provision of charitable
contribution and community support within the New England region serves a number
of important goals. After the Effective Time, NEES intends to cause the
Surviving Entity to provide charitable contributions and community support
within the New England region at annual levels substantially comparable to the
annual level of charitable contributions and community support provided,
directly or indirectly, by EUA and its public utility subsidiaries within the
New England region during 1998.
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7.08 No Solicitations. Prior to the Effective Time, EUA agrees: (a)
that neither it nor any of its Subsidiaries shall, and it shall use its best
efforts to cause its Representatives (as defined in Section 10.10) not to,
knowingly initiate, solicit or encourage, directly or indirectly, any inquiries
or any proposal or offer (including, without limitation, any proposal or offer
to its Shareholders) with respect to a merger, consolidation or other business
combination including EUA or any of its significant Subsidiaries (as defined in
Rule 1-02(W) of Regulation S-X promulgated under the Exchange Act) other than
EUA Cogenex Corporation (an "EUA Significant Subsidiary"), or any acquisition or
similar transaction (including, without limitation, a tender or exchange offer)
involving the purchase of (i) all or any significant portion of the assets of
EUA and its Subsidiaries taken as a whole, (ii) ten percent or more of the
outstanding EUA Shares or (iii) 50% or more of the outstanding shares of the
capital stock of any EUA Significant Subsidiary (any such proposal or offer
being hereinafter referred to as an "Alternative Proposal"), or engage in any
negotiations concerning, or provide any confidential information or data to, or
have any other discussions with, any person or group relating to an Alternative
Proposal, or otherwise knowingly facilitate any effort or attempt to make or
implement an Alternative Proposal other than from NEES and its affiliates; (b)
that it will immediately cease and cause to be terminated any existing
activities, discussions or negotiations with any parties with respect to any
Alternative Proposal; and (c) that it will notify NEES immediately if any such
inquiries, proposals or offers are received by, any such information is
requested from, or any such negotiations or discussions are sought to be
initiated or continued with, it or any of such persons; provided, however, that,
prior to receipt of the EUA Shareholders' Approval, nothing contained in this
Section 7.08 shall prohibit the Board of Trustees of EUA from (i) furnishing
information to (but only pursuant to a confidentiality agreement in customary
form and having terms and conditions no less favorable to EUA than the
Confidentiality Agreement (as defined in Section 7.01)) or entering into
discussions or negotiations with any person or group that makes an unsolicited
Alternative Proposal, if, and only to the extent that, (A) the Board of Trustees
of EUA, based upon advice of outside counsel with respect to fiduciary duties,
determines in good faith that such action is necessary for the Board of Trustees
to act in a manner consistent with its fiduciary duties to Shareholders under
applicable law, (B) the Board of Trustees of EUA has reasonably concluded in
good faith (after consultation with its financial advisors) that the person or
group making such Alternative Proposal will have adequate sources of financing
to consummate such Alternative Proposal and that such Alternative Proposal is
likely to be more favorable to EUA's shareholders than the Merger, (C) prior to
furnishing such information to, or entering into discussions or negotiations
with, such person or group, EUA provides written notice to NEES to the effect
that it is furnishing information to, or entering into discussions or
negotiations with, such person or group, which notice shall identify such person
or group and the material terms of the Alternative Proposal in reasonable
detail, and (D) EUA keeps NEES promptly informed of the status and all material
information with respect to any such discussions or negotiations; and (ii) to
the extent required, complying with Rule 14e-2 promulgated under the Exchange
Act with regard to an Alternative Proposal. Nothing in this Section 7.08 shall
(x) permit EUA to terminate this Agreement (except as specifically provided in
Article IX), (y) permit EUA to enter into any agreement with respect to an
Alternative Proposal for so long as this Agreement remains in effect (it being
agreed that for so long as this Agreement remains in effect, EUA shall not enter
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into any agreement with any person or group that provides for, or in any way
knowingly facilitates, an Alternative Proposal (other than a confidentiality
agreement under the circumstances described above)), or (z) affect any other
obligation of EUA under this Agreement.
7.09 Directors' and Officers' Indemnification and Insurance.
(a) Indemnification. To the extent, if any, not provided by an
existing right of indemnification or other agreement or policy, from and after
the Effective Time, NEES shall, or shall cause the Surviving Entity to, to the
fullest extent permitted by applicable law, indemnify, defend and hold harmless
each person who is now, or has been at any time prior to the date hereof, or who
becomes prior to the Effective Time, (x) an officer, trustee or director or (y)
an employee covered as of the date hereof (to the extent of the coverage
extended as of the date hereof) of EUA or any Subsidiary of EUA (each an
"Indemnified Party," and collectively, the "Indemnified Parties") against (i)
all losses, expenses (including reasonable attorney's fees and expenses),
claims, damages or liabilities or, subject to the first proviso of the next
succeeding sentence, amounts paid in settlement, arising out of actions or
omissions occurring at or prior to the Effective Time (and whether asserted or
claimed prior to, at or after the Effective Time) that are, in whole or in part,
based on or arising out of the fact that such person is or was a director,
trustee, officer or employee of EUA or any Subsidiary of EUA (the "Indemnified
Liabilities"), and (ii) all Indemnified Liabilities to the extent they are based
on or arise out of or pertain to the transactions contemplated by this
Agreement, in each case, to the extent permitted by the EUA Trust Agreement or
the indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter. In the event of any such loss, expense, claim, damage or liability
(whether or not arising before the Effective Time), (i) NEES shall, or shall
cause the Surviving Entity to, pay the reasonable fees and expenses of counsel
selected by the Indemnified Parties, which counsel shall be reasonably
satisfactory to NEES or the Surviving Entity, as appropriate, promptly after
statements therefor are received and otherwise advance to such Indemnified Party
upon request, reimbursement of documented expenses reasonably incurred, in
either case to the extent not prohibited by the EUA Trust Agreement or the
indemnification agreements set forth in Section 7.09 of the EUA Disclosure
Letter upon receipt of an undertaking by or on behalf of such director, trustee
or officer to repay such amounts as and to the extent required by the EUA Trust
Agreement or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter, (ii) the Surviving Entity shall cooperate in the defense of
any such matter and (iii) any determination required to be made with respect to
whether an Indemnified Party's conduct complies with the standards set forth
under the EUA Trust Agreement or the indemnification agreements set forth in
Section 7.09 of the EUA Disclosure Letter and the certificate of incorporation
or by-laws or similar governing documents of the Surviving Entity shall be made
by independent counsel mutually acceptable to the Surviving Entity and the
Indemnified Party; provided, however, that the Surviving Entity shall not be
liable for any settlement effected without its written consent (which consent
shall not be unreasonably withheld) and provided further that no indemnification
shall be made if such indemnification is prohibited by the EUA Trust Agreement
or the indemnification agreements set forth in Section 7.09 of the EUA
Disclosure Letter.
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(b) Insurance. For a period of six years after the Effective
Time, NEES and the Surviving Entity at NEES's election, (i) shall cause to be
maintained in effect an extended reporting period for current policies of
directors' and officers' liability insurance for the benefit of such persons who
are currently covered by such policies of EUA on terms no less favorable than
the terms of such current insurance coverage or (ii) shall provide tail coverage
for such persons which provides such persons with coverage for a period of six
years for acts prior to the Effective Time on terms no less favorable than the
terms of such current insurance coverage.
(c) Successors. In the event the Surviving Entity or any of its
successors or assigns (i) consolidates with or merges into any other person or
entity and shall not be the continuing or surviving corporation or entity of
such consolidation or merger or (ii) transfers all or substantially all of its
properties and assets to any person or entity, then and in either such case,
proper provisions shall be made so that the successors and assigns of the
Surviving Entity, as applicable, shall assume the obligations set forth in this
Section 7.09.
(d) Survival of Indemnification. To the fullest extent permitted
by law, from and after the Effective Time, all rights to indemnification as of
the date hereof in favor of the employees, agents, directors, trustees and
officers of EUA and EUA's Subsidiaries with respect to their activities as such
prior to the Effective Time, as provided in the EUA Trust Agreement or the
respective certificates of incorporation and by-laws or similar governing
documents in effect on the date hereof, or otherwise in effect on the date
hereof, shall survive the Merger and shall continue in full force and effect for
a period of not less than six years from the Effective Time.
(e) Benefit. The provisions of this Section 7.09 are intended to
be for the benefit of, and shall be enforceable by, each Indemnified Party, his
or her heirs and his or her representatives.
(f) Amendment of the EUA Trust Agreement. NEES shall not, and
shall ensure that the Surviving Entity shall not, amend the EUA Trust Agreement
to in any way limit the indemnification provided to the Indemnified Parties
under this Section 7.09.
7.10 Expenses. Except as set forth in Section 9.03, whether or not
the Merger is consummated, all costs and expenses incurred in connection with
the Merger and other transactions contemplated hereby shall be paid by the party
incurring such cost or expense, except that the filing fees in connection with
the filings required under the HSR Act and the 1935 Act shall be paid by NEES.
7.11 Brokers or Finders. EUA represents, as to itself and its
affiliates, that no agent, broker, investment banker, financial advisor or other
firm or person is or will be entitled to any broker's, finder's or investment
banker's fee or any other commission or similar fee in connection with the
Merger and other transactions contemplated by this Agreement except Salomon
Smith Barney Inc., whose fees and expenses will be paid by EUA in accordance
with EUA's agreement with such firm, and EUA shall indemnify and hold NEES
harmless from and against any and all claims, liabilities or obligations with
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respect to any other such fee or commission or expenses related thereto asserted
by any person on the basis of any act or statement alleged to have been made by
EUA or its affiliates.
7.12 Anti-Takeover Statutes. If any "fair price", "moratorium",
"business combination", "control share acquisition" or other form of
anti-takeover statute or regulation shall become applicable to the Merger or
other transactions contemplated hereby, EUA and the members of the Board of
Trustees of EUA shall grant such approvals and take such actions consistent with
their fiduciary duties and in accordance with applicable law as are reasonably
necessary so that the Merger and other transactions contemplated hereby may be
consummated as promptly as practicable on the terms contemplated hereby and
otherwise act to eliminate or minimize the effects of such statute or regulation
on the Merger and other transactions contemplated hereby.
7.13 Public Announcements. Except as otherwise required by law or the
rules of any applicable securities exchange or national market system or any
other Regulatory Authority, so long as this Agreement is in effect, NEES and EUA
will not, and will not permit any of their respective Subsidiaries or
Representatives to, issue or cause the publication of any press release or make
any other public announcement with respect to the Merger and other transactions
contemplated by this Agreement without the consent of the other party, which
consent shall not be unreasonably withheld. NEES and EUA will cooperate with
each other in the development and distribution of all press releases and other
public announcements with respect to the Merger and other transactions
contemplated hereby, and will furnish the other with drafts of any such releases
and announcements as far in advance as practicable.
7.14 Restructuring of the Merger. It may be preferable to effectuate
a business combination between NEES and EUA by means of an alternative structure
to the Merger. Accordingly, if, prior to satisfaction of the conditions
contained in Article VIII hereto, NEES proposes the adoption of an alternative
structure that otherwise substantially preserves for NEES and EUA the economic
benefits of the Merger and will not materially delay the consummation thereof,
then the parties shall use their respective best efforts to effect a business
combination among themselves by means of a mutually agreed upon structure other
than the Merger that so preserves such benefits; provided, however, that prior
to closing any such restructured transaction, all material third party and
Governmental Authority declarations, filings, registrations, notices,
authorizations, consents or approvals necessary for the effectuation of such
alternative business combination shall have been obtained and all other
conditions to the parties' obligations to consummate the Merger and other
transactions contemplated hereby, as applied to such alternative business
combination, shall have been satisfied or waived.
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ARTICLE VIII
CONDITIONS
8.01 Conditions to Each Party's Obligation to Effect the Merger. The
respective obligation of each party to effect the Merger and other transactions
contemplated hereby is subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following conditions:
(a) Shareholder Approval. EUA Shareholders' Approval shall have
been obtained.
(b) HSR Act. Any waiting period (and any extension thereof)
applicable to the consummation of the Merger under HSR shall have expired or
been terminated.
(c) Injunctions or Restraints. No court of competent
jurisdiction or other competent Governmental Authority shall have enacted,
issued, promulgated, enforced or entered any law or order (whether temporary,
preliminary or permanent) which is then in effect and has the effect of making
illegal or otherwise restricting, preventing or prohibiting consummation of the
Merger or other transactions contemplated hereby.
(d) Governmental and Regulatory and Other Consents and
Approvals. The NEES Required Statutory Approvals and EUA Required Statutory
Approvals shall have been obtained prior to the Effective Time, and shall have
become Final Orders (as hereinafter defined). The Final Orders shall not,
individually or in the aggregate, impose terms and conditions that (i) could
reasonably be expected to have an EUA Material Adverse Effect; (ii) could
reasonably be expected to have a NEES Material Adverse Effect; or (iii)
materially impair the ability of the parties to complete the Merger. The parties
shall have received Final Orders from the Massachusetts Department of
Telecommunications and Energy and the Rhode Island Public Utilities Commission
pertaining to the recovery of costs (including, without limitation, transaction
premium and integration costs) associated with the Merger that are materially
consistent with existing policy and previous orders of such agencies. "Final
Order" for all purposes of this Agreement means action by the relevant
regulatory authority which has not been reversed, stayed, enjoined, set aside,
annulled or suspended with respect to which any waiting period prescribed by law
before the Merger and other transactions contemplated hereby may be consummated
has expired, and as to which all conditions to be satisfied before the
consummation of such transactions prescribed by law, regulation or order have
been satisfied.
8.02 Conditions to Obligation of NEES and LLC to Effect the Merger.
The obligation of NEES and LLC to effect the Merger and other transactions
contemplated hereby is further subject to the satisfaction or waiver at or prior
to the Closing, of each of the following additional conditions (all or any of
which may be waived in whole or in part by NEES and LLC in the sole discretion):
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(a) Representations and Warranties. The representations and
warranties made by EUA in this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "EUA Material Adverse Effect", shall be true and correct as so
made as of the Closing Date as though so made on and as of the Closing Date,
except to the extent expressly given as of a specified date, except where the
failure of such representations and warranties to be true and correct as so made
does not have and could not reasonably be expected to have, individually or in
the aggregate, an EUA Material Adverse Effect, and EUA shall have delivered to
NEES a certificate, dated the Closing Date and executed in the name and on
behalf of EUA by its Chairman of the Board, President or any Executive or Senior
Vice President, to such effect.
(b) Performance of Obligations. EUA shall have performed and
complied with, in all material respects, each agreement, covenant and obligation
required by this Agreement to be so performed or complied with by EUA at or
prior to the Closing, and EUA shall have delivered to NEES a certificate, dated
the Closing Date and executed in the name and on behalf of EUA by its Chairman
of the Board, President or any Executive or Senior Vice President, to such
effect.
(c) Material Adverse Effect. No EUA Material Adverse Effect
shall have occurred and there shall exist no facts or circumstances which in the
aggregate could reasonably be expected to have an EUA Material Adverse Effect.
(d) EUA Required Consents. All EUA Required Consents shall have
been obtained by EUA, except where the failure to receive such EUA Required
Consents could not reasonably be expected to (i) have an EUA Material Adverse
Effect, or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
8.03 Conditions to Obligation of EUA to Effect the Merger. The
obligation of EUA to effect the Merger and other transactions contemplated
hereby is further subject to the satisfaction or waiver, at or prior to the
Closing, of each of the following additional conditions (all or any of which may
be waived in whole or in part by EUA in its sole discretion):
(a) Representations and Warranties. The representations and
warranties made by NEES and LLC in Sections 5.01, 5.02, 5.03, 5.04, 5.05, 5.07,
5.08 and 5.09 of this Agreement, in each case made as if none of such
representations or warranties contained any qualification or limitation as to
"materiality" or "NEES Material Adverse Effect," shall be true and correct as so
made as of the Closing Date, except to the extent expressly given as of a
specified date and except where the failure of such representations and
warranties to be so true and correct as so made does not have and could not
reasonably be expected to have, individually or in the aggregate, a NEES
Material Adverse Effect or a material adverse effect on LLC, and NEES and LLC
shall each have delivered to EUA a certificate, dated the Closing Date and
executed in the name and on behalf of NEES by any director of NEES and in the
name and on behalf of LLC by a member of its management committee its Chairman
of the Board, President or any Executive or Senior Vice President to such
effect.
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(b) NEES Required Consents. All NEES Required Consents shall
have been obtained by NEES, except where the failure to receive such NEES
Required Consents could not reasonably be expected to (i) have a NEES Material
Adverse Effect or (ii) delay or prevent the consummation of the Merger and other
transactions contemplated hereby.
(c) Performance of Obligations. NEES and LLC shall have
performed and complied with, in all material respects, each agreement, covenant
and obligation required by this Agreement to be so performed or complied with by
NEES or LLC at or prior to the Closing, and NEES and LLC shall each have
delivered to EUA a certificate, dated the Closing Date and executed in the name
and on behalf of NEES by its Chairman of the Board, President or any Executive
or Senior Vice President, or on behalf of LLC by a member of its management
committee to such effect.
ARTICLE IX
TERMINATION, AMENDMENT AND WAIVER
9.01 Termination. This Agreement may be terminated, and the Merger
and other transactions contemplated hereby may be abandoned, at any time prior
to the Effective Time, whether prior to or after EUA Shareholders' Approval
(except as otherwise provided in Section 9.01(c) below):
(a) By mutual written agreement of the Board of Directors of
NEES and Board of Trustees of EUA, respectively;
(b) By EUA or NEES, by written notice to the other, if the
Closing Date shall not have occurred on or before December 31, 1999 (the
"Initial Termination Date"); provided, however, that the right to terminate the
Agreement under this Section 9.01(b) shall not be available to any party whose
failure to fulfill any obligation under this Agreement has been the cause of, or
resulted in, the failure of the Effective Time to occur on or before such date;
and provided, further, that if on the Initial Termination Date the conditions to
the Closing set forth in Section 8.01(d) shall not have been fulfilled but all
other conditions to the Closing shall be fulfilled or shall be capable of being
fulfilled, then the Initial Termination Date shall be extended for four (4)
months beyond the Initial Termination Date (the "Extended Termination Date");
(c) By NEES, by written notice to EUA, if EUA Shareholders'
Approval shall not have been obtained at a duly held meeting of such
Shareholders, including any adjournments thereof;
(d) By EUA or NEES, if any applicable state or federal law or
applicable law of a foreign jurisdiction or any order, rule or regulation is
adopted or issued that has the effect, as supported by the written opinion of
outside counsel for such party, of prohibiting the Merger or other transactions
contemplated hereby, or if any court of competent jurisdiction or any
Governmental Authority shall have issued a nonappealable final order, judgment
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or ruling or taken any other action having the effect of permanently
restraining, enjoining or otherwise prohibiting the Merger or other transactions
contemplated hereby (provided that the right to terminate this Agreement under
this Section 9.01(d) shall not be available to any party that has not defended
such lawsuit or other legal proceeding (including seeking to have any stay or
temporary restraining order entered by any court or other Governmental Authority
vacated or reversed)).
(e) By EUA upon ten (10) days' prior notice to NEES if the Board
of Trustees of EUA determines in good faith, that termination of this Agreement
is necessary for the Board of Trustees of EUA to act in a manner consistent with
its fiduciary duties to Shareholders under applicable law by reason of an
unsolicited Alternative Proposal meeting the requirements of clauses (A) and (B)
of Section 7.08 having been made; provided that
(A) The Board of Trustees of EUA shall determine based
on advice of outside counsel with respect to the Board of
Trustees' fiduciary duties that notwithstanding a binding
commitment to consummate an agreement of the nature of this
Agreement entered into in the proper exercise of its applicable
fiduciary duties, and notwithstanding all concessions which may
be offered by NEES in negotiation entered into pursuant to clause
(B) below, it is necessary pursuant to such fiduciary duties that
the trustees reconsider such commitment as a result of such
Alternative Proposal, and
(B) prior to any such termination, EUA shall, and
shall cause its respective financial and legal advisors to,
negotiate with NEES to make such adjustments in the terms and
conditions of this Agreement as would enable EUA to proceed with
the Merger or other transactions contemplated hereby on such
adjusted terms;
and provided further that EUA's ability to terminate this Agreement pursuant to
this Section 9.01(e) is conditioned upon the concurrent payment by EUA to NEES
of any amounts owed by it pursuant to Section 9.03(a);
(f) By EUA, by written notice to NEES, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of NEES hereunder (other than a breach
described in clause (ii)), and such breach shall not have been remedied within
twenty (20) days after receipt by NEES of notice in writing from EUA, specifying
the nature of such breach and requesting that it be remedied; or (ii) NEES shall
fail to deliver or cause to be delivered the amount of cash to the Paying Agent
required pursuant to Section 2.02(a) at a time when all conditions to NEES's
obligation to close have been satisfied or otherwise waived in writing by NEES.
(g) By NEES, by written notice to EUA, if (i) there shall have
been any material breach of any representation or warranty, or any material
breach of any covenant or agreement, of EUA hereunder, and such breach shall not
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<PAGE>
have been remedied within twenty (20) days after receipt by EUA of notice in
writing from NEES, specifying the nature of such breach and requesting that it
be remedied; or (ii) the Board of Trustees of EUA (A) shall withdraw or modify
in any manner adverse to NEES its approval of the Merger and other transactions
contemplated hereby or its recommendation to its shareholders regarding the
approval of this Agreement, the Merger and other transactions contemplated
hereby, (B) shall approve or recommend or take no position with respect to an
Alternative Proposal or (C) shall resolve to take any of the actions specified
in clause (A) or (B).
9.02 Effect of Termination. If this Agreement is validly terminated
by either EUA or NEES pursuant to Section 9.01, this Agreement shall forthwith
become null and void and there shall be no liability or obligation on the part
of either EUA or NEES (or any of their respective Representatives or
affiliates), except that the provisions of this Section 9.02, Sections 7.10,
7.11 and 7.13, Section 9.03 and Sections 10.09 and 10.10 shall continue to apply
following any such termination.
9.03 Termination Fees. (a) In the event that (i) this Agreement is
terminated by EUA pursuant to Section 9.01(e) or (ii) any person or group shall
have made an Alternative Proposal that has not been withdrawn and this Agreement
is terminated by (A) NEES pursuant to Section 9.01(c) or Section 9.01(g) or (B)
by EUA pursuant to Section 9.01(b) and, in the case of this clause (ii) only, a
definitive agreement with respect to such Alternative Proposal is executed
within two years after such termination, then EUA shall pay to NEES, by wire
transfer of same day funds, either on the date contemplated in Section 9.01(e)
if applicable, or otherwise, within five (5) business days after such
termination, a termination fee of $20 million, plus an amount equal to all
documented out-of-pocket expenses and fees incurred by NEES arising out of, or
in connection with or related to, the Merger and other transactions contemplated
hereby, not in excess of $5 million in the aggregate.
(b) In the event that this Agreement is terminated by either
NEES or EUA pursuant to Section 9.01(b) and at the time of such termination (i)
the conditions to the Closing set forth in Section 8.01(d) shall not have been
fulfilled, (ii) if the date of termination is any date other than a date which
is on or after the Extended Termination Date, all conditions contained in
Article VIII other than Sections 8.01(d) or 8.03(c) shall have been fulfilled or
are capable of being fulfilled as of such date, and (iii) the merger
contemplated by the National Grid Merger Agreement has not yet been consummated,
then NEES shall pay to EUA, by wire transfer of same day funds, within five (5)
business days after such termination, a termination fee of $10 million, plus an
amount equal to all documented out-of-pocket expenses and fees incurred by EUA
arising out of, or in connection with or related to, the Merger and other
transactions contemplated hereby, not in excess of $5 million in the aggregate.
(c) Nature of Fees. The parties agree that the agreements
contained in this Section 9.03 are an integral part of the Merger and the other
transactions contemplated hereby and constitute liquidated damages and not a
penalty. The parties further agree that if any party is or becomes obligated to
pay a termination fee pursuant to Sections 9.03(a) or (b), the right to receive
such termination fee shall be the sole remedy of the other party with respect to
-43-
<PAGE>
the facts and circumstances giving rise to such payment obligation. If this
Agreement is terminated by a party as a result of a willful breach of a
representation, warranty, covenant or agreement by the other party, including a
termination pursuant to Section 9.01(f)(ii), the non-breaching party may pursue
any remedies available to it at law or in equity and shall be entitled to
recover any additional amounts thereunder. Notwithstanding anything to the
contrary contained in this Section 9.03, if one party fails to promptly pay to
the other any fee or expense due under this Section 9.03, in addition to any
amounts paid or payable pursuant to such Section, the defaulting party shall pay
the costs and expenses (including legal fees and expenses) in connection with
any action, including the filing of any lawsuit or other legal action, taken to
collect payment, together with interest on the amount of any unpaid fee at the
publicly announced prime rate of Citibank, N.A. from the date such fee was
required to be paid.
9.04 Amendment. This Agreement may be amended, supplemented or
modified by action taken by or on behalf of the Board of Directors of NEES or
the Board of Trustees of EUA at any time prior to the Effective Time, whether
prior to or after EUA Shareholders' Approval shall have been obtained, but after
such adoption and approval only to the extent permitted by applicable law. No
such amendment, supplement or modification shall be effective unless set forth
in a written instrument duly executed and delivered by or on behalf of each
party hereto.
9.05 Waiver. At any time prior to the Effective Time, NEES or EUA, by
action taken by or on behalf of its Board of Directors or Board of Trustees,
respectively, may to the extent permitted by applicable law (i) extend the time
for the performance of any of the obligations or other acts of the other parties
hereto, (ii) waive any inaccuracies in the representations and warranties of the
other parties hereto contained herein or in any document delivered pursuant
hereto or (iii) waive compliance with any of the covenants, agreements or
conditions of the other parties hereto contained herein. No such extension or
waiver shall be effective unless set forth in a written instrument duly executed
by or on behalf of the party extending the time of performance or waiving any
such inaccuracy or non-compliance. No waiver by any party of any term or
condition of this Agreement, in any one or more instances, shall be deemed to be
or construed as a waiver of the same or any other term or condition of this
Agreement on any future occasion.
ARTICLE X
GENERAL PROVISIONS
10.01 Non-Survival of Representations, Warranties, Covenants and
Agreements. The representations, warranties, covenants and agreements contained
in this Agreement or in any instrument delivered pursuant to this Agreement
shall not survive the Merger but shall terminate at the Effective Time, except
for the agreements contained in Article I and Article II, in Sections 7.05,
7.06, 7.08, 7.09 and 7.10, this Article X which shall survive the Effective
Time.
10.02 Notices. All notices, requests and other communications
hereunder must be in writing and will be deemed to have been duly given only if
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<PAGE>
delivered personally or by facsimile transmission or sent by overnight courier
(providing proof of delivery) to the parties at the following addresses or
facsimile numbers:
If to NEES or LLC, to:
New England Electric System
25 Research Drive
Westborough, MA 01582
Attn: Richard P. Sergel
President and Chief Executive Officer
Telephone: (508) 389-2764
Facsimile: (508) 366-5498
with a copy to:
Skadden, Arps, Slate, Meagher & Flom LLP
919 Third Avenue
New York, NY 10022
Attn: Sheldon S. Adler, Esq.
Telephone: (212) 735-3000
Facsimile: (212) 735-2000
If to EUA, to:
Eastern Utilities Associates
One Liberty Square
Boston, MA 02109
Attn: Donald G. Pardus
Chairman and Chief Executive Officer
Telephone: (617) 357-9590
Facsimile: (617) 357-7320
with a copy to:
Winthrop, Stimson, Putnam & Roberts
1 Battery Park Plaza
New York, NY 10004
Attn: David P. Falck
Telephone: (212) 858-1000
Facsimile: (212) 858-1500
All such notices, requests and other communications will (i) if
delivered personally to the address as provided in this Section, be deemed given
-45-
<PAGE>
upon delivery, (ii) if delivered by facsimile transmission to the facsimile
number as provided in this Section, be deemed given when sent, provided that the
facsimile is promptly confirmed by telephone confirmation thereof, and (iii) if
delivered by mail in the manner described above to the address as provided in
this Section, be deemed given one business day after delivery (in each case
regardless of whether such notice, request or other communication is received by
any other person to whom a copy of such notice, request or other communication
is to be delivered pursuant to this Section). Any party from time to time may
change its address, facsimile number or other information for the purpose of
notices to that party by giving notice specifying such change to the other
parties hereto.
10.03 Entire Agreement; Incorporation of Exhibits. (a) This Agreement
supersedes all prior discussions and agreements, both written and oral, among
the parties hereto with respect to the subject matter hereof, other than the
Confidentiality Agreement, which shall survive the execution and delivery of
this Agreement in accordance with its terms, and contains, together with the
Confidentiality Agreement, the sole and entire agreement among the parties
hereto with respect to the subject matter hereof.
(b) The EUA Disclosure Letter, the NEES Disclosure Letter and
any Exhibit attached to this Agreement and referred to herein are hereby
incorporated herein and made a part hereof for all purposes as if fully set
forth herein.
10.04 No Third Party Beneficiary. The terms and provisions of this
Agreement are intended solely for the benefit of each party hereto and their
respective successors or permitted assigns, and except as provided in Article II
and Sections 7.04, 7.05(d)(ii) and 7.09 (which is intended to be for the benefit
of the persons entitled to therein, and may be enforced by any of such persons),
it is not the intention of the parties to confer third-party beneficiary rights
upon any other person.
10.05 No Assignment; Binding Effect. Neither this Agreement nor any
right, interest or obligation hereunder may be assigned, in whole or in part, by
operation of law or otherwise, by any party hereto without the prior written
consent of the other parties hereto and any attempt to do so will be void,
except that LLC may assign any or all of its rights, interests and obligations
hereunder to another direct or indirect wholly owned Subsidiary of NEES,
provided that any such Subsidiary agrees in writing to be bound by all of the
terms, conditions and provisions contained herein and provided further that such
assignment (i) does not require a greater vote for EUA's Shareholder Approval,
(ii) does not require a subsequent vote following EUA's Shareholders Meeting, or
(iii) is not reasonably likely to materially delay or prevent EUA, LLC and NEES,
as appropriate, from obtaining EUA Required Statutory Approvals, EUA Required
Consents, EUA Shareholders' Approval, the NEES Required Shareholders' Approvals,
or the NEES Required Consents. Subject to the preceding sentence, this Agreement
is binding upon, inures to the benefit of and is enforceable by the parties
hereto and their respective successors and assigns.
-46-
<PAGE>
10.06 Headings. The headings used in this Agreement have been
inserted for convenience of reference only and do not define, modify or limit
the provisions hereof.
10.07 Invalid Provisions. If any provision of this Agreement is held
to be illegal, invalid or unenforceable under any present or future law or
order, and if the rights or obligations of any party hereto under this Agreement
will not be materially and adversely affected thereby, (i) such provision will
be fully severable, (ii) this Agreement will be construed and enforced as if
such illegal, invalid or unenforceable provision had never comprised a part
hereof, and (iii) the remaining provisions of this Agreement will remain in full
force and effect and will not be affected by the illegal, invalid or
unenforceable provision or by its severance herefrom.
10.08 Governing Law. This Agreement shall be governed by and
construed in accordance with the laws of the Commonwealth of Massachusetts.
10.09 Enforcement of Agreement. The parties hereto agree that
irreparable damage would occur in the event that any of the provisions of this
Agreement was not performed in accordance with its specified terms or was
otherwise breached. It is accordingly agreed that the parties shall be entitled
to an injunction or injunctions to prevent breaches of this Agreement and to
enforce specifically the terms and provisions hereof in any court of competent
jurisdiction, this being in addition to any other remedy to which they are
entitled at law or in equity.
10.10 Certain Definitions. As used in this Agreement:
(a) except as provided in Section 4.14, the term "affiliate," as
applied to any person, shall mean any other person directly or indirectly
controlling, controlled by, or under common control with, that person; for
purposes of this definition, "control" (including, with correlative meanings,
the terms "controlling," "controlled by" and "under common control with"), as
applied to any person, means the possession, directly or indirectly, of the
power to direct or cause the direction of the management and policies of that
person, whether through the ownership of voting securities, by contract or
otherwise;
(b) a person will be deemed to "beneficially" own securities if
such person would be the beneficial owner of such securities under Rule 13d-3
under the Exchange Act, including securities which such person has the right to
acquire (whether such right is exercisable immediately or only after the passage
of time);
(c) the term "business day" means a day other than Saturday,
Sunday or any day on which banks located in the Massachusetts are authorized or
obligated to close;
(d) the term "knowledge" or any similar formulation of
"knowledge" shall mean, with respect to any party hereto, the actual knowledge
after due inquiry of the executive officers of NEES and its Subsidiaries or EUA
and its Subsidiaries, respectively, set forth in Section 10.11(d) of the NEES
Disclosure Letter or Section 10.11(d) of the EUA Disclosure Letter; provided
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<PAGE>
that as used in Section 4.13 the term "knowledge" shall also include the
knowledge of the environmental, health and safety personnel of EUA;
(e) the term "person" shall include individuals, corporations,
partnerships, trusts, limited liability companies, other entities and groups
(which term shall include a "group" as such term is defined in Section 13(d)(3)
of the Exchange Act);
(f) the "Representatives" of any entity shall have the same
meaning as set forth in the Confidentiality Agreement;
(g) the term "Subsidiary" means any corporation or other entity,
whether incorporated or unincorporated, in which such party directly or
indirectly owns at least a majority of the voting power represented by the
outstanding capital stock or other voting securities or interests having voting
power under ordinary circumstances to elect a majority of the directors or
similar members of the governing body, or otherwise to direct the management and
policies, or such corporation or entity.
10.11 Counterparts. This Agreement may be executed in any number of
counterparts, each of which will be deemed an original, but all of which
together will constitute one and the same instrument and will become effective
when one or more counterparts have been signed by each party and delivered to
the other parties.
10.12 WAIVER OF JURY TRIAL. EACH PARTY HERETO HEREBY WAIVES, TO THE
FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY
JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING
TO THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY (WHETHER BASED ON
CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO
REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY
OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK
TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER
PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER
THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.
-48-
<PAGE>
IN WITNESS WHEREOF, each party hereto has caused this Agreement to be
signed by its officer thereunto duly authorized as of the date first above
written.
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer, or agent
thereof assumes or shall be held to any liability therefor.
EASTERN UTILITIES ASSOCIATES
By: /s/ Donald G. Pardus
-----------------------------------
Name: Donald G. Pardus
Title: Chairman
The name "Eastern Utilities Associates" is the designation of the Trustees of
EUA for the time being in their collective capacity but not personally, under a
Declaration of Trust dated April 2, 1928, as amended, a copy of which amended
Declaration of Trust has been filed in the office of the Secretary of The
Commonwealth of Massachusetts and elsewhere as required by law; and all persons
dealing with EUA must look solely to the trust property for the enforcement of
any claim against EUA, as neither the Trustees nor the officers or shareholders
of EUA assume any personal liability for obligations entered into on behalf of
EUA.
RESEARCH DRIVE LLC
By: /s/ John G. Cochrane
-----------------------------------
Name: John G. Cochrane
Title: Manager
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<PAGE>
Tab 2
CONSENT AGREEMENT
dated as of February 1, 1999
<PAGE>
CONSENT AGREEMENT
This Consent Agreement (the "Agreement") is entered into as of
February 1, 1999 between The National Grid Group, p1c, a public limited company
incorporated under the laws of England and Wales ("NGG") and New England
Electric System, a Massachusetts business trust ("NEES").
WHEREAS, NGG, NEES and NGG Holdings LLC (formerly Iosta LLC), a wholly
owned subsidiary of NGG, entered into an Agreement and Plan of Merger dated as
of December 11, 1998 (the"Merger Agreement") pursuant to which NGG Holdings LLC
will merge (the "Merger") with and into NEES with NEES being the surviving
entity and becoming a wholly owned subsidiary of NGG;
WHEREAS, NEES, Eastern Utilities Associates, a Massachusetts Business
Trust ("EUA") and Research Drive LLC are proposing to enter into an Agreement
and Plan of Merger in the form attached hereto as Exhibit A (the "EUA Merger
Agreement") providing for the merger (the "EUA Merger") of Research Drive LLC
with and into EUA with EUA being the surviving entity and becoming a wholly
owned subsidiary of NEES; and
WHEREAS, pursuant to the provisions of the Merger Agreement, NEES is
required to obtain the consent of NGG before entering into the EUA Merger
Agreement and with respect to certain actions relating to the consummation of
the transactions set forth therein.
NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties hereby agree as
follows:
1. Consent to EUA Merger Agreement. Subject to the terms and
conditions of this Consent, NGG hereby consents to NEES entering into the EUA
Merger Agreement with EUA in the form set forth in Exhibit A and agrees that,
subject to the immediately following sentence, the consummation by NEES of the
transactions contemplated by the EUA Merger Agreement in accordance with the
term thereof shall not constitute a breach by NEES of the terms of the Merger
Agreement. NEES and NGG acknowledge that the financing necessary to consummate
the EUA Merger was not contemplated when NEES and NGG agreed to the limitations
set forth in Article VI of the Merger Agreement and NGG consents to such
financing provided that such financing is consistent with the financing
parameters set forth on Exhibit B hereto. NGG also consents to the formation and
<PAGE>
capitalization of Research Drive LLC by NEES for the purpose of effecting the
EUA Merger as contemplated in the EUA Merger Agreement.
2. Access to Information. Subject to the following sentence, NEES
hereby agrees to provide NGG with reasonable access to any information it
receives regarding EUA pursuant to the terms of the EUA Merger Agreement and to
consult with NGG on a regular basis concerning the status of EUA and the EUA
Merger. NGG hereby acknowledges that any such material that is "Evaluation
Material" (as such term is defined in the letter agreement dated as of December
21, 1998 between NGG and NEES (the "Confidentiality Agreement") shall be
governed by the terms of the Confidentiality Agreement.
3. Regulatory Filings. NEES hereby agrees that NGG shall have the
right to review in advance, and that NEES will consult with NGG and give due
regard to NGG's views concerning, any applications, notices, petitions, filings
and other documents filed with any Governmental Authority (as defined in the EUA
Merger Agreement) in connection with the EUA Merger which could reasonably be
expected to have a material adverse effect on NGG's or NEES' ability to
consummate the Merger or which could reasonably be expected to adversely affect
in any material manner any material benefit of the Merger to NGG or NEES.
4. Amendments to EUA Merger Agreement. NEES hereby agrees that it will
not, without the prior written consent of NGG, amend or modify the EUA Merger
Agreement in any material respect, including, without limitation, amend or
otherwise modify any provision of the EUA Merger Agreement providing for or
relating to the amount, type or structure of the Merger Consideration (as
defined in the EUA Merger Agreement) or agree to any additional or different
amount, type or structure for the Merger Consideration (as so defined).
5. Acknowledgment. NGG and NEES acknowledge and agree that the
covenants set forth in Article VI of the Merger Agreement do not reflect the
operations of EUA if the EUA Merger is consummated prior to the Effective Time
(as defined in the Merger Agreement). In the event that the EUA Merger is
consummated prior to the Effective Time, NGG and NEES hereby agree to negotiate
in good faith to make appropriate modifications to such covenants set forth in
Section 6.01 of the Merger Agreement to reflect the operations of EUA.
6. Termination and Amendment. This Consent Agreement and the
obligations of NEES hereunder shall terminate upon the earlier to occur of (i)
the termination of the Merger Agreement, (ii) the EUA Merger and (iii) the
Merger, in each case without any further action by the parties hereto. Except as
<PAGE>
provided in the preceding sentence, this Consent can not be terminated or
amended in any material respect prior to the termination of the EUA Merger
Agreement without the prior written consent of EUA. The foregoing sentence is
intended for the benefit of EUA and may be enforced by EUA.
7. Notices. NEES hereby agrees to provide NGG with copies of all
notices and other communications it sends to EUA and all notices and other
communications it receives from EUA under the EUA Merger Agreement. All notices
and other communications provided under this Agreement must be in writing and
shall be given in the same manner and to the same parties as set forth in
Section 10.02 of the Merger Agreement.
8. Counterparts. This Agreement may be executed in any number of
counterparts, each of which shall be an original, with the same effect as if the
signatures thereto and hereto were upon the same instrument.
9. Governing Law and Waiver of Jury Trial. This Agreement shall be
governed by and construed in accordance with the laws of the State of New York
applicable to a contract executed and performed in such State, without giving
effect to the conflicts of laws principles. EACH PARTY HERETO HEREBY WAIVES, TO
THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL
BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR
RELATING TO THIS AGREEMENT (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER
THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR
ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH
OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING
WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN
INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS
AND CERTIFICATIONS IN THIS SECTION.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: /s/ Fiona B. Smith
-----------------------------------
Name: Fiona B. Smith
Title: Company Secretary
NEW ENGLAND ELECTRIC SYSTEM
By: ___________________________
Name:
Title:
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
IN WITNESS WHEREOF, each of NGG and NEES has duly executed this
Agreement as of the date first above written.
THE NATIONAL GRID GROUP, PLC
By: ______________________________
Name:
Title:
NEW ENGLAND ELECTRIC SYSTEM
By: /s/ Richard P. Sergel
-----------------------------------
Name: Richard P. Sergel
Title: President and CEO
The name "New England Electric System" means the trustee or trustees for the
time being (as trustee or trustees but not personally) under an Agreement and
Declaration of Trust dated January 2, 1926, as amended, which is hereby referred
to, and a copy of which, as amended, has been filed with the Secretary of the
Commonwealth of Massachusetts. Any agreement, obligation, or liability made,
entered into, or incurred by or on behalf of New England Electric System binds
only its trust estate, and no shareholder, director, trustee, officer or agent
thereof assumes or shall be held to any liability therefor.
<PAGE>
ACKNOWLEDGMENT OF EASTERN UTILITIES ASSOCIATES
(not legible)
<PAGE>
EXHIBIT B - Financing Parameters
Financing will be in an amount of up to $630 M provided through a
group of banks. The financing (i) will be prepayable, (ii) will have a term not
to exceed seven years, (iii) will have a LIBOR-based borrowing option and (iv)
will have other terms and conditions usual and customary for transactions of
this nature.
<PAGE>
Exhibit JKZ-2
Simplified Corporate Structure
for Regulated Operating Companies
(Plan for Full Consolidation)
------------------------------------------------------
----------------
| National Grid |
| Group |
----------------
| |
| |
| |
| |
| |
---------- -----
| NEES |--------------------------------- | EUA |
---------- -----
| | | |--------------|
| | | |
| | ---------------- ----------------- |
| |----| Mass. Electric |------ | Eastern Edison | |
| | ---------------- ----------------- |
| | | |
| | | |
- ----------- | | -------------- ----------- |
| Granite | | |----| New England |-------- | Montaup | |
| State |-----| | | Power | ----------- |
| Electric | | -------------- - - - - - - - - |
----------- | | ------------------- | |
| | | Blackstone Valley |-|-------|
| ---------------- | ------------------- | |
|----| Narragansett |-----| | |
---------------- | ---------- | |
| | Newport |----------|-------|
| ---------- |
- - - - - - - - -
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Exhibit JKZ-3
Page 1 of 1
<TABLE>
<CAPTION>
New England Power Company
1998 Balance Sheet
Dollars in Thousands
December 31,
1998
Line Assets ----
---- ------
<S> <C> <C>
1 Utility Plant, at original cost $1,262,461
2 Less: Accumulated Depreciation 837,637
-------
3 424,824
4 Construction Work in Progress 33,289
------
5 Net Utility Plant 458,113
6
7 Investments (Including in Subsidiaries) 88,121
8
9 Cash 179,413
10 Accounts Receivable, Associated Companies 107,878
11 Other Current Assets 63,362
12
13 Regulatory Assets 1,512,562
14 Deferred Charges and Other Assets 5,339
15 -----
16 Total Assets 2,414,788
17
18
19 Capitalization and Liabilities
------------------------------
20 Common Equity 520,896
21 Preferred Stock 1,567
22 Long-term Debt 371,765
-------
23 Total Capitalization 894,228
24
25 Long Term Debt due within one year 0
26 Short-term Debt 0
27 Other Current Liabilities 199,919
28
29 Deferred State and Federal Income Taxes 165,115
30 Unamortized Investment Tax Credits 30,870
31 Accrued Yankee Nuclear Plant Costs 242,138
32 Purchased Power Obligations 832,668
33 Other Liabilities 49,850
-------
34
35 Total Capitalization and Liabilities $2,414,788
36
37 Capitalization Ratios
---------------------
38 Common Equity 58%
39 Preferred Stock 0%
40 Long-term Debt 42%
---
41 Total Capitalization 100%
<PAGE>
Petition of New England Power Company
Vermont Public Service Board
Exhibit JKZ-4
Page 1 of 1
Montaup Electric Company
1998 Balance Sheet
Dollars in Thousands
December 31,
1998
Line Assets
---- ------
1 Utility Plant, at original cost $496,203
2 Less: Accumulated Depreciation 156,158
-------
3 340,045
4 Construction Work in Progress 1,307
-----
5 Net Utility Plant 341,352
6
7 Investments in Subsidiaries 12,881
8
9 Cash 154
10 Accounts Receivable, Associated Companies 66,638
11 Other Current Assets 15,998
12
13 Unrecovered Regulatory Plant Costs 58,503
14 Deferred Charges and Other Assets 145,445
15 -------
16 Total Assets 640,971
17
18
19 Capitalization and Liabilities
------------------------------
20 Common Equity 147,017
21 Preferred Stock 1,500
22 Long-term Debt 117,982
-------
23 Total Capitalization 266,499
24
25 Long Term Debt due within one year 0
26 Short-term Debt 0
27 Other Current Liabilities 69,759
28
29 Deferred State and Federal Income Taxes 99,567
30 Unamortized Investment Tax Credits 9,840
31 Other Liabilities 195,306
32
33 Total Capitalization and Liabilities $640,971
34
35 Capitalization Ratios
---------------------
36 Common Equity 55%
37 Preferred Stock 1%
38 Long-term Debt 44%
---
39 Total Capitalization 100%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Petition of New England Power Company
Vermont Public Service Board
Exhibit JKZ-5
Page 1 of 1
NEW ENGLAND POWER COMPANY
MONTAUP ELECTRIC COMPANY
PROFORMA BALANCE SHEET - MERGED
Dollars in Thousands
Actual Pro-Forma
------------------- -------------------------------
Redemption
of Montaup Repayment
NEP Montaup Debt and of Common Merged
1998 1998 Preferred Equity Company
Line Assets ---- ---- --------- --------- -------
---- ------
<S> <C> <C> <C> <C> <C> <C> <C>
1 Utility Plant, at original cost $1,262,461 $496,203 $1,758,664
2 Less: Accumulated Depreciation 837,637 156,158 993,795
------- ------- -------
3 424,824 340,045 764,869
4 Construction Work in Progress 33,289 1,307 34,596
------ ----- ------
5 Net Utility Plant 458,113 341,352 799,465
6
7 Investments (Including in Subsidiaries) 88,121 12,881 101,002
8
9 Cash 179,413 154 (119,482) (60,085) 0
10 Accounts Receivable, Associated Companies 107,878 66,638 174,516
11 Other Current Assets 63,362 15,998 79,360
12
13 Unrecovered Regulatory Plant Costs 1,512,562 58,503 1,571,065
14 Deferred Charges and Other Assets 5,339 145,445 150,784
15 ----- ------- -------
16 Total Assets 2,414,788 640,971 (119,482) (60,085) 2,876,192
17
18
19 Capitalization and Liabilities
------------------------------
20 Common Equity 520,896 147,017 (147,017) 520,896 (a)
21 Preferred Stock 1,567 1,500 (1,500) 0 1,567
22 Long-term Debt 371,765 117,982 (117,982) 0 371,765
------- ------- ------- - -------
23 Total Capitalization 894,228 266,499 (119,482) (147,017) 894,228
24
25 Long Term Debt due within one year 0 0 0
26 Short-term Debt 0 0 86,932 86,932
27 Other Current Liabilities 199,919 69,759 269,678
28
29 Deferred State and Federal Income Taxes 165,115 99,567 264,682
30 Unamortized Investment Tax Credits 30,870 9,840 40,710
31 Accrued Yankee Costs 242,138 0 242,138
32 Purchased Power Obligations 832,668 0 832,668
33 Other Liabilities 49,850 195,306 245,156
34 ------ ------- -------
35 $2,414,788 $640,971 ($119,482) ($60,085) $2,876,192
36
37
38 Total Capitalization and Liabilities
39
40 Capitalization Ratios
41 Common Equity 58% 55% 58%
42 Preferred Stock 0% 1% 0%
43 Long-term Debt 42% 44% 42%
-- -- --
44 Total Capitalization 100% 100% 100%
(a) The merged balance sheet does not reflect the impact of "push-down" accounting and the aquisition premium.
</TABLE>
