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No. ____________
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
FORM U-1
APPLICATION/DECLARATION
UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
Energy East Corporation, One Canterbury Green, Stamford, Connecticut 06904
CMP Group, Inc., 83 Edison Drive, Augusta, Maine 04336
CTG Resources, Inc., 100 Columbus Boulevard, Hartford, Connecticut 06103
(Name of company or companies filing this statement and
address of principal executive offices)
Kenneth M. Jasinski Arthur W. Adelberg
Executive Vice President and General Executive Vice President
Counsel CMP Group, Inc.
Energy East Corporation 83 Edison Drive
One Canterbury Green Augusta, Maine 04336
Stamford, Connecticut 06904 Telephone: (207) 623-3521
Telephone: (203) 325-0690
Arthur C. Marquardt
Chairman, President and Chief Executive
Officer
CTG Resources, Inc.
100 Columbus Boulevard
Hartford, Connecticut 06103
Telephone: (860) 727-3000
(Names and addresses of agents for service)
Copies to:
Elizabeth A. Moler, Esq. William T. Baker, Jr., Esq.
Adam Wenner, Esq. Thelen Reid & Priest
Vinson & Elkins L.L.P. 40 West 57th Street
The Willard Office Building New York, New York 10019
1455 Pennsylvania Avenue, N.W. Telephone: (212) 603-2106
Washington, D.C. 20004-1008
Telephone: (202) 639-6500
William T. Baker, Jr., Esq.
Huber Lawrence & Abell
605 Third Avenue
New York, New York 10158
(212) 682-6200
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TABLE OF CONTENTS
ITEM 1. DESCRIPTION OF PROPOSED MERGER 1
A. INTRODUCTION 1
1. General Request 3
2. Overview of the Mergers 4
a. CMP Group Merger 4
b. CTG Resources Merger 4
B. DESCRIPTION OF THE PARTIES TO THE MERGER 5
1. Energy East 5
a. Public Utility Operations of Energy East 5
b. Non-Public Utility Affiliates of Energy East 8
c. Non-Public Utility Affiliates of Connecticut Energy 10
2. CMP Group 12
a. Public Utility Operations of CMP Group 12
b. Non-Public Utility Affiliates of CMP Group 14
3. CTG Resources 16
a. Public Utility Affiliate of CTG Resources 16
b. Non-Public Utility Affiliates of CTG Resources 16
C. DESCRIPTION OF THE MERGER 17
1. CMP Group Merger Agreement 17
2. CTG Resources Merger Agreement 18
D. MANAGEMENT AND OPERATION OF THE COMPANIES
FOLLOWING THE MERGER 19
ITEM 2. FEES, COMMISSIONS AND EXPENSES 20
ITEM 3. APPLICABLE STATUTORY PROVISIONS 20
A. SECTION 9(A)(2) 23
B. SECTION 10(B) 25
1. Section 10(b)(1) 26
2. Section 10(b)(2) 30
a. Reasonableness of Consideration 30
b. Reasonableness of Fees 34
3. Section 10(b)(3) 36
C. SECTION 10(C) 39
1. Acquisition Must be Lawful 39
2. Combination and Integration of Electric Utility Operations 41
a. Changes in the Electric Utility Industry 43
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b. Restructuring of NEPOOL and NYPP into Open,
Competitive and Coordinated Markets 46
(i) The NYPP and NYISO 48
(ii) NEPOOL and ISO-NE 53
(iii) Coordination between ISO-NE and NYISO 56
(a) Interface transfer capacity 57
(b) Coordination and joint planning by
NYSEG and Central Maine Power
through the NYISO and ISO-NE 59
(iv) Integrating Effects of NYISO and
ISO-NE Transmission Tariffs 61
(v) NYSEG's and Central Maine Power's Transmission
Pricing Proposal Will Provide Additional Integration 62
c. Statutory Standards for Electric Integration
Will Be Satisfied 63
(i) Physical interconnection or capability
of physical interconnection 63
(ii) Coordination of electric operations 67
(iii) Single area or region 71
(iv) Not so large as to impair advantages of localized
management, efficient operation, and the
effectiveness of regulation 72
3. Combination of Gas utility operations 74
a. Section 10(c)(1) 74
(i) Section 8 74
(ii) Section 11 75
b. "ABC" Clauses 76
c. Gas utility integration standards
(Section 10(b)(2)) 81
(i) Section 2(a)(29)(B): "substantial economies
may be effectuated by being operated as a
single coordinated system" 83
(ii) Section 2(a)(29)(B): "a single area or region
in one or more states" 83
(iii) Section 2(a)(29)(B): System size from
perspective of "the advantages of local
management, efficient operation and the
effectiveness of regulation 88
4. Economies and Efficiencies from the Merger (Section 10(c)(2)) 88
a. Corporate Operations 91
b. Administration 91
c. Non-Gas Supply Purchasing Economies
d. Gas Supply 91
e. Additional Expected Benefits 92
5. Retention of Non-Utility Business 93
D. SECTION 10(F) 95
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ITEM 4: REGULATORY APPROVALS 95
A. ANTITRUST 96
B. FEDERAL POWER ACT 96
C. ATOMIC ENERGY ACT 96
D. TELECOMMUNICATIONS 97
E. STATE PUBLIC REGULATION 97
ITEM 5: PROCEDURE 98
ITEM 6: EXHIBITS AND FINANCIAL STATEMENTS 98
A. EXHIBITS 98
B. FINANCIAL STATEMENTS 101
ITEM 7: INFORMATION AS TO ENVIRONMENTAL EFFECTS 101
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ITEM 1. DESCRIPTION OF PROPOSED MERGERS
A. INTRODUCTION
This Application/Declaration seeks approvals relating to the proposed
combinations of Energy East Corporation ("Energy East") with CMP Group, Inc.
("CMP Group") and Energy East with CTG Resources, Inc. (collectively "the
Companies") pursuant to which CMP Group and CTG Resources will each become a
direct subsidiary of Energy East (both proposed combinations are referred to
collectively as the "Merger"). Following the consummation of the Merger, Energy
East will register with the Securities and Exchange Commission (the "SEC" or
"Commission") as a holding company under the Public Utility Holding Company Act
of 1935 (the "Act"). (1)
The Act was intended, among other things, to prevent the evils that arise
"when the growth and extension of holding companies bears no relation to the
economy of management and operation or integration and coordination of related
operating properties " In contrast, post-Merger Energy East will exemplify the
growth that promotes economies and coordination of related operating properties
within a single region in a manner consistent not only with the policies of the
Act, but also with the policies of both the Federal Energy Regulatory Commission
("FERC") and with state regulatory initiatives. Moreover, as discussed in
detail below, integration of New York State Electric & Gas Corporation ("NYSEG")
and Central Maine Power Company ("Central Maine Power") as members of adjacent,
highly interconnected and coordinated power pools and independent system
operators ("ISOs") represents a reasoned evolution of the integration
requirements under the Act. Here, through the combination of membership in
highly integrated power pools and ISOs, the instant availability of open access,
non-discriminatory intra- and inter- pool transmission through internet-based
Open Access Same-time Information Systems ("OASIS") sites, the reduction of
"pancaked" transmission charges, and coordinated electric utility operations,
the Merger will increase the efficiency of the competitive markets in the
northeastern United States, thereby "serv[ing] the public interest by tending
toward the economical and efficient development of an integrated public utility
system."
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(1) Prior to completion of the Merger, the Companies expect to file one or more
additional applications-declarations under the Act with respect to ongoing
financing activities and other matters pertaining to Energy East after the
Merger.
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The Merger is expected to produce substantial benefits to the public,
investors and consumers, and meet all applicable standards of the Act. The
Companies believe that the Merger will allow shareholders and consumers to
participate in a larger, financially stronger company that, through a
combination of the capital, management, and technical expertise of each Company,
will be a strong competitor in the rapidly evolving market for energy and energy
services, will be able to achieve increased financial stability and strength,
greater opportunities for earnings growth, reduction of operating costs,
efficiencies of operation, better use of facilities for the benefit of
customers, improved ability to use new technologies, greater retail and
industrial sales diversity, and optimization of their respective portfolios of
gas supply and transportation through joint management. The Companies believe
the Merger will significantly improve the competitive positions of their utility
subsidiaries and create greater opportunities for growth.
The shareholders of CMP Group and CTG Resources approved their respective
mergers with Energy East at meetings held on October 7, 1999 and October 18,
1999, respectively. Each of the Companies has submitted applications requesting
approval of the Merger and/or related matters to the appropriate state and
federal regulators. Applications are pending before the Maine Public Utilities
Commission ("MPUC"), the Connecticut Department of Public Utility Control
("DPUC"), the FERC, the Nuclear Regulatory Commission ("NRC"), and the Federal
Communications Commission ("FCC"). Finally, all three Companies will make the
required filings with the Antitrust Division of the U.S. Department of Justice
("DOJ") and the Federal Trade Commission ("FTC") under the Hart-Scott-Rodino
Antitrust Improvements Act of 1976, as amended ("HSR Act"). See Exhibits D-1
through D-13 and Item 4 below for additional detail regarding these regulatory
approvals. It is anticipated that favorable responses will be received from
these regulators by June 2000.
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In order to permit timely consummation of the Merger and the realization of
the substantial benefits it is expected to produce, Energy East requests that
the Commission's review of this Application/Declaration commence and proceed as
expeditiously as practicable, and that the Commission order be issued no later
than June 2000. To the extent that all of the state and other approvals have
not been received by that time, Energy East asks the Commission to condition the
effectiveness of its order upon receipt of all necessary state and other
regulatory approvals.
1. General Request
----------------
Pursuant to Sections 9(a)(2) and 10 of the Act, Energy East hereby requests
authorization and approval of the Commission to acquire, by means of the Merger,
100 percent of the issued and outstanding common stock of each of CTG Resources
and CMP Group, exclusive of dissenters' shares. A chart of the proposed
corporate structure of Energy East following consummation of the Merger is
attached hereto as Exhibit E-5. Energy East also hereby requests that the
Commission approve:
(i) the operation of Energy East as a combination electric and gas
utility holding company; and
(ii) the retention by Energy East of its non-utility activities,
businesses and investments and the acquisition by Energy East of the
non-utility activities, businesses and investments of CMP Group and
CTG Resources.
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2. Overview of the Mergers
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(a) CMP Group Merger
------------------
Pursuant to an Agreement and Plan of Merger, dated as of June 14, 1999 (the
"CMP Group Merger Agreement"), EE Merger Corp., a Maine corporation and a
wholly-owned subsidiary of Energy East, will be merged with and into CMP Group,
with CMP Group being the surviving corporation (the "CMP Group Merger"). Subject
to regulatory and shareholder approval, Energy East will purchase all common
shares of CMP Group, exclusive of dissenters' shares, for $29.50 per share, for
a total cash value of $957 million. Energy East will also assume approximately
$271 million of preferred stock and long-term debt. A copy of the CMP Group
Merger Agreement is incorporated by reference as Exhibit B-2 hereto. As a
result of these transactions, CMP Group will become a direct subsidiary of
Energy East. Energy East will establish a new corporate office in Portland,
Maine.
(b) CTG Resources Merger
----------------------
Pursuant to an Agreement and Plan of Merger, dated as of June 29, 1999 (the
"CTG Resources Merger Agreement"), CTG Resources will be merged with and into
Oak Merger Co., a Connecticut corporation and a wholly-owned subsidiary of
Energy East, with Oak Merger Co. being the surviving corporation (the "CTG
Resources Merger"). The common shareholders of CTG Resources will receive for
each issued and outstanding share of common stock the right to receive $41.00 in
cash, Energy East common stock or a combination of cash and Energy East common
stock. A copy of the CTG Resources Merger Agreement is incorporated by
reference as Exhibit B-1 hereto. As a result of these transactions, CTG
Resources will become a direct subsidiary of Energy East.
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B. DESCRIPTION OF THE PARTIES TO THE MERGER
1. Energy East
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On May 1, 1998, Energy East became the parent of NYSEG. Energy East
neither owns nor operates any physical properties. Energy East is currently a
public utility holding company exempt from all provisions of the Act, except
Section 9(a)(2), under Section 3(a)(1) of the Act by order of the Commission
dated February 12, 1999. Energy East Corporation, et al., Holding Co. Act
----------------------------------
Release ("HCAR") No. 26976 (Feb. 12, 1999). (2) Energy East, through its
subsidiaries, is an energy delivery, products and services company with
operations in New York, Massachusetts, Maine, New Hampshire, Vermont and New
Jersey. Energy East has offices in New York and Connecticut. Energy East's
common stock is publicly traded on the New York Stock Exchange under the symbol
"NEG." Energy East's principal executive offices are located at One Canterbury
Green, P.O. Box 1196, Stamford, Connecticut 06904-1196.
(a) Public Utility Operations of Energy East
New York State Electric & Gas Corporation
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NYSEG, a regulated public utility incorporated under the laws of the State
of New York, is a combination electric and gas utility serving 826,000 electric
customers and 244,000 natural gas customers in upstate New York. NYSEG has
divested substantially all of its generating assets. It retains hydroelectric
facilities with an aggregate capacity of 62 MW, non-utility generation ("NUG")
contracts and contracts pursuant to which the New York Power Authority ("NYPA")
sells power to NYSEG, as well as an 18 percent ownership interest in the Nine
Mile Point Unit 2 nuclear plant ("NM2"). NYSEG has reached an agreement to sell
its share of NM2.(3) The transaction is expected to close in the second quarter
of 2000. NYSEG is engaged in the business of purchasing, transmitting and
distributing electricity and purchasing, transporting and distributing natural
gas. NYSEG also generates electricity from its 18 percent share of NM2 and from
its hydroelectric stations.
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(2) See Energy East Corporation, et al., Holding Co. Act Release ("HCAR") No.
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26976 (Feb. 12, 1999).
(3) NYSEG has contracted to sell its 18 percent interest in NM2 to AmerGen Inc.
Approval of that sale is pending before the New York Public Service
Commission ("NYPSC"). An application for authorization to transfer
associated jurisdictional facilities filed pursuant to Section 203 of the
Federal Power Act is also pending before the FERC.
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NYSEG has contracted to sell its 18 percent interest in NM2 to AmerGen Inc.
Approval of that sale is pending before the New York Public Service Commission
("NYPSC"). An application for authorization to transfer associated
jurisdictional facilities filed pursuant to Section 203 of the Federal Power Act
is also pending before the FERC.
NYSEG's service territory, 99 percent of which is located outside the
corporate limits of cities, is in the central, eastern and western parts of the
State of New York. NYSEG's service territory has an area of approximately
19,900 square miles and a population of 2,400,000. The larger cities in which
NYSEG serves both electricity and natural gas customers are Binghamton, Elmira,
Auburn, Geneva, Ithaca and Lockport, New York. The service territory reflects a
diversified economy, including high-tech firms, light industry, colleges and
universities, agriculture and recreational facilities. No customer accounts for
five percent or more of either electric or natural gas revenues. During 1996
through 1998, approximately 84 percent of NYSEG's operating revenue was derived
from electric service with the balance derived from natural gas service.
After the sale of its interest in NM2, NYSEG will be engaged almost
entirely in the transmission and distribution of electricity and the
distribution of natural gas. As of December 31, 1998, NYSEG's electric
transmission system consisted of approximately 4,482 circuit miles of line.
NYSEG's electric distribution system consisted of 33,858 pole-miles of overhead
lines and 2,109 miles of underground lines. NYSEG, which is a member of the New
York Power Pool ("NYPP"), has committed to transfer control of its transmission
system to the New York Independent System Operator ("NYISO"). (4) , 87 F.E.R.C.
61,135 (1999). The NYISO is expected to begin operations no later than January
2000.
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(4) Central Hudson Gas & Electric Corp., et al., 87 F.E.R.C. 61,135 (1999).
--------------------------------------------
The NYISO is expected to begin operations no later than January 2000.
References to NYISO operations in the present tense in this
Application/Declaration are intended to recognize that the operational
start date for the NYISO is imminent.
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The NYISO, an independent operator of utilities' transmission systems, will
operate the transmission systems of all of the public utility systems in New
York. (5)
CMP Natural Gas, L.L.C.
------------------------
CMP Natural Gas, L.L.C. ("Maine Gas Co.") was established to furnish
natural gas distribution service, on a non-exclusive basis, in certain areas of
Maine, including, among others, the Bethel Windham, Augusta, Waterville and
Bangor metropolitan areas, and the coastal area, including Brunswick and Bath.
Maine Gas Co. began to provide service to retail customers in May 1999. Maine
Gas Co. is a joint venture between New England Gas Development Corp., a
wholly-owned subsidiary of CMP Group, and Energy East Enterprises, a
wholly-owned subsidiary of Energy East.
Connecticut Energy Corporation
--------------------------------
On April 23, 1999, Connecticut Energy Corporation ("Connecticut Energy")
and Energy East entered into an agreement and plan of merger. By separate
application dated August 30, 1999, Energy East has requested authorization from
the Commission for Connecticut Energy to merge with and into a wholly-owned
subsidiary of Energy East. The Commission's ruling on Energy East's August 30,
1999 application is still pending. (6)
Connecticut Energy, an exempt holding company that neither owns nor
operates any physical property, is primarily engaged in the retail distribution
of natural gas through its principal wholly-owned subsidiary, The Southern
Connecticut Gas Company ("Southern Connecticut Gas"). Connecticut Energy,
through its subsidiaries, is an energy delivery, products and services company
that provides an array of energy commodities and services to commercial and
industrial customers throughout New England. Connecticut Energy's principal
executive offices are located at 855 Main Street, Bridgeport, Connecticut 06604.
Connecticut Energy and its subsidiaries had 480 full-time employees as of
December 31, 1998. Southern Connecticut Gas had 467 employees as of December
31, 1998.
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(5) A detailed description of the history, purpose, and regulatory authority of
the NYISO appears in Item 3.C.2.(b).(i).
(6) In order not to unduly delay or complicate the instant application, it will
be assumed for purposes of the instant application that the Connecticut
Energy application has been granted, pursuant to the terms described in the
August 30, 1999 application. Thus, Connecticut Energy's utility and
non-utility affiliates will be assumed to be, and will be described herein
as, current affiliates of Energy East.
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Southern Connecticut Gas
--------------------------
Southern Connecticut Gas, a public service company incorporated under the
laws of the State of Connecticut, is engaged in the retail distribution of
natural gas for residential, commercial and industrial uses and the
transportation of natural gas for commercial and industrial users. Southern
Connecticut Gas serves approximately 158,000 customers in the State of
Connecticut, primarily in 22 towns along the southern Connecticut coast from
Westport to Old Saybrook, which include the urban communities of Bridgeport and
New Haven. Southern Connecticut Gas is the sole distributor of natural gas,
other than bottled gas, in its service area.
(b) Non-Public Utility Affiliates of Energy East
Energy East also has a number of direct and indirect subsidiaries that are
not "public utility companies" under the Act. These include Energy East
Enterprises ("EE Enterprises"), a Maine corporation, and XENERGY Enterprises,
Inc. ("XENERGY Enterprises"), a Delaware corporation.
EE Enterprises was organized in 1998 and owns natural gas and propane air
distribution companies. EE Enterprises is a wholly-owned subsidiary of Energy
East and is currently an exempt public utility holding company under the Act by
order of the Commission dated February 12, 1999. (7) It indirectly holds public
utility assets through its ownership of a 77 percent interest in Maine Gas Co.
EE Enterprises' non-utility subsidiaries are New Hampshire Gas Corporation, an
energy services company in New Hampshire specializing in propane air
distribution systems; Southern Vermont Natural Gas
(7) See Energy East Corporation, et al., HCAR No. 26976 (Feb. 12, 1999).
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Corporation, which is developing a combined natural gas supply and distribution
project that includes an extension of a pipeline from New York to Vermont by
Iroquois Gas Transmission System, and the development of natural gas
distribution systems in Vermont; and Seneca Lake Storage, Inc., which proposes
to own and operate a gas storage facility in New York.
XENERGY Enterprises, a wholly-owned subsidiary of Energy East, was
organized in 1992. It invests in providers of energy and telecommunication
services. XENERGY Enterprises currently holds no public utility assets and is
neither a public utility company nor a holding company under the Act. XENERGY
Enterprises' principal subsidiaries are XENERGY Inc., an energy services,
information systems and consulting company that specializes in energy
management, conservation engineering and demand-side management; Energy East
Solutions, Inc., which markets electricity and natural gas to end users and
provides wholesale commodities to retail electric suppliers in the northeastern
United States; NYSEG Solutions, Inc., which markets electricity and natural gas
to end users and provides wholesale commodities to retail electric suppliers in
the State of New York; Energy East Telecommunications, Inc. which provides
telecommunication services, including the construction and operation of fiber
optic networks; and Cayuga Energy, Inc., which holds investments in cogeneration
facilities. Energy East's other current direct non-utility subsidiaries are as
follows:
- - Energy East Management Corporation, a Delaware corporation, invests the
proceeds of the sale of an affiliate's generation assets.
- - Oak Merger Co., a Connecticut corporation, was formed solely for the
purpose of consummating the proposed merger with CTG Resources, pursuant to
the CTG Resources Merger Agreement. As described in more detail in Item
1.C.2 herein, Oak Merger Co. will be the surviving party in such merger and
will remain a wholly-owned subsidiary of Energy East. Upon consummation of
such
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merger, Oak Merger Co. will change its name to, and operate under, the name
of "CTG Resources, Inc."
- - EE Merger Corp., a Maine corporation, was formed solely for the purpose of
consummating the proposed merger with CMP Group, pursuant to the CMP Group
Merger Agreement. As described in more detail in Item 1.C.1 herein, CMP
Group will be the surviving party in such merger and will become a
wholly-owned subsidiary of Energy East.
(c) Non-Public Utility Affiliates of Connecticut Energy.
--------------------------------------------------------
Connecticut Energy also has a number of direct and indirect subsidiaries
that are not "public-utility companies" under the Act. These include CNE Energy
Services Group, Inc. ("CNE Energy"), CNE Development Corporation ("CNE
Development") and CNE Venture-Tech, Inc. ("CNE Venture-Tech"). All three of
these non-utility subsidiaries are Connecticut corporations.
- - CNE Energy, a wholly-owned subsidiary of Connecticut Energy, provides an
array of energy products and services to commercial and industrial
customers throughout New England, both on its own and through its
participation as a member of various energy-related limited liability
companies. CNE Energy's principal subsidiaries are: (i) Conectiv/CNE Energy
Services, LLC, a 50/50 joint venture of CNE Energy and Energy East
Solutions, Inc., a subsidiary of Energy East, that sells natural gas, fuel
oil and other services to commercial, industrial and municipal customers in
New England; (ii) Total Peaking Services, LLC, a 50/50 joint venture of CNE
Energy and Conectiv Energy Supply, Inc., which operates a 1.2 billion cubic
foot liquefied natural gas open access storage facility in Milford,
Connecticut; and (iii) Conectiv/CNE Peaking, LLC, a 50/50 joint venture of
CNE Energy and Conectiv Energy Supply, Inc., which provides a firm
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in-market supply source to assist energy marketers and local gas
distribution companies in meeting the maximum demands of their customers by
offering firm supplies for peak-shaving and emergency deliveries.
- - CNE Development, a wholly-owned subsidiary of Connecticut Energy, is a
16.67 percent equity participant in East Coast Natural Gas Cooperative,
LLC, which purchases and stores gas spot supplies, provides storage service
utilization services and is involved in bundled sales.
- - CNE Venture-Tech, a wholly-owned subsidiary of Connecticut Energy, invests
in ventures that produce or market technologically advanced energy-related
products. CNE Venture-Tech's investments include a 7.8884 percent limited
partnership interest in Nth Power Technologies Fund I, L.P., which invests
in companies that develop, produce and market innovative energy-related
products; and CIS Service Bureau, LLC, a service bureau which provides
access to customer-billing software and other related services for local
distribution and other utility-type companies (including Southern
Connecticut Gas) and which is wholly-owned by CNE Venture-Tech.
For the year ended December 31, 1998, electric revenues of approximately
$1,706,876,000 and gas revenues of approximately $305,881,000 accounted for
approximately 85 percent and 15 percent, respectively, of Energy East's
consolidated gross utility revenues. Energy East's utility operating income and
utility net income available for common stock were $482,720,000 and
$205,215,000, respectively. Consolidated assets of Energy East and its
subsidiaries as of December 31, 1998, were approximately $4.9 billion,
consisting of $3.9 billion in net utility plant and $1.0 billion in other
utility and non-utility assets. For the twelve months ended December 31, 1998,
consolidated operating revenues, operating income and net income for Energy East
and its subsidiaries were approximately $2,499,418,000, $474,839,000, and
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$194,205,000, respectively. Connecticut Energy's operating revenues totaled
approximately $242,431,000 for the fiscal year ended September 30, 1998.
Connecticut Energy's consolidated net income for the same period was $19
million.
2. CMP Group
CMP Group is a holding company by virtue of owning, among others, directly
or indirectly, more than five percent of the voting securities of Central Maine
Power Company ("Central Maine Power"), Maine Electric Power Company, Inc.
("MEPCo"), NORVARCO and Maine Gas Co., all public utility companies as defined
in the Act. CMP Group is exempt from all provisions of the Act, except Section
9(a)(2), under Section 3(a)(1) of the Act, by order of the Commission dated
February 12, 1999.(8) CMP Group, Inc., et al., HCAR No. 26977 (Feb. 12, 1999).
----------------------
CMP Group's principal utility subsidiary, Central Maine Power is primarily
engaged in purchasing, transmitting, distributing and selling electricity to
retail customers in Maine and to wholesale customers, principally other
utilities.
(a) Public Utility Operations of CMP Group
Central Maine Power
---------------------
Central Maine Power is the largest electric utility in Maine and serves
over 533,000 customers in its 11,000 square-mile service area in southern and
central Maine. Central Maine Power had approximately $939 million in
consolidated electric operating revenues in 1998. Central Maine Power is
subject to the regulatory authority of the MPUC and FERC.
Central Maine Power has divested and/or relinquished control over
substantially all of its generating assets and purchase power contracts and now
functions primarily as an electric transmission and distribution utility.
Central Maine Power has sold its hydroelectric, fossil and biomass generating
assets, (9) and has recently reached an agreement to sell one of its two
remaining
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(8) See CMP Group, Inc., et al., HCAR No. 26977 (Feb. 12, 1999).
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(9) Central Maine Power sold these assets to a non-affiliated third party, FPL
Energy, a subsidiary of FPL Group.
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investments in operating nuclear plants. (10) While Central Maine Power may
retain ownership of some of its nuclear and NUG capacity, it is selling its
entitlements to purchase capacity and energy under the NUG contracts, as well as
its entitlements to energy from its 2.5% interest in the Millstone 3 nuclear
plant, and its entitlements in a firm energy contract with Hydro Quebec. The
sales of generating capacity and entitlements to purchase capacity and energy
under NUG contracts were conducted pursuant to the requirements of Maine's
recently enacted electric utility restructuring legislation and MPUC Rules and
Regulations. (11) As of March 1, 2000, Central Maine Power will not control any
generation resources. Also beginning March 1, 2000, all retail electric
consumers in Maine will have the authority to choose their electric supplier.
Since under Maine law, Central Maine Power would be able to serve only a limited
number of retail customers and would not be the supplier of last resort, Central
Maine Power has elected not to continue as a retail electric supplier. In the
future, Central Maine Power will be a "wires" only transmission and distribution
utility.
As of December 31, 1998, Central Maine Power's delivery system consisted of
2,293 miles of overhead transmission lines, 19,438 pole-miles of distribution
lines and 1,434 miles of underground submarine cable. Central Maine Power is a
member of the New England Power Pool ("NEPOOL") and has transferred control over
its pool transmission facilities ("PTF") system to ISO New England Inc.
("ISO-NE"). (12) It maintains high-voltage connections with other electric
systems at the New Hampshire and New Brunswick, Canada borders.
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(10) On October 15, 1999, Central Maine Power, together with the other owners of
Vermont Yankee, announced acceptance of a bid by AmerGen Energy Company to
purchase the plant.
(11) 35-A M.R.S.A. 3204; and Chapt. 307 MPUC Rules and Regulations.
(12) New England Power Pool, 79 F.E.R.C. 61,374 (1997). The ISO-NE operates
----------------------
the transmission systems of all of the public utility systems in New
England. A detailed description of the ISO-NE appears in Item
3.C.2.(b).(ii).
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MEPCo and NORVARCO
--------------------
Central Maine Power currently has two electric utility subsidiaries,
organized and operating almost exclusively in Maine: MEPCo and NORVARCO.
(Central Maine Power, MEPCo and NORVARCO are referred to collectively as the
"CMP Electric Utilities.") MEPCo owns and operates a 345kV transmission
interconnection between the Maine-New Brunswick, Canada international border at
Orient, Maine. Central Maine Power owns a 78.3 percent voting interest in
MEPCo, with the remaining interests owned by two other Maine utilities. Also,
NORVARCO holds a 50 percent general partnership interest in Chester SVC
Partnership, a general partnership which owns a static var compensator located
in Chester, Maine, adjacent to MEPCo's transmission interconnection.
Maine Gas Co.
---------------
Maine Gas Co., a natural gas distribution company, is a joint venture of
New England Gas Development Corporation and EE Enterprises. New England Gas
Development Corporation, a wholly-owned subsidiary of CMP Group, holds an
approximately 23 percent interest in Maine Gas Co.
Other Nuclear Interests
-------------------------
Central Maine Power also owns a 38 percent voting interest in Maine Yankee
Atomic Power Company, which owns the Maine Yankee nuclear electric generating
plant in Wiscasset, Maine. Maine Yankee's plant was permanently shut down on
August 6, 1997. Central Maine Power also holds (i) a 9.5 percent voting
interest in Yankee Atomic Electric Company, which has permanently shut down its
plant located in Rowe, Massachusetts, and (ii) a six percent voting interest in
Connecticut Yankee Atomic Power Company, which has permanently shut down its
plant in Haddam, Connecticut.
(b) Non-Public Utility Affiliates of CMP Group
CMP Group's non-utility subsidiaries are as follows:
-13-
<PAGE>
- - CNEX (trade name for CMP International Consultants) provides consulting,
planning, training, project management, and information and research
services to foreign and domestic utilities and government agencies in
various aspects of utility operations and utility support services.
- - MaineCom Services ("MaineCom") provides telecommunications services,
including point-to-point connections, private networking, consulting,
private voice and data transport, carrier services, and long-haul
transport. It is subject to regulation by the MPUC with respect to making
available a fiber optics cable for public use in Maine.
- - NorthEast Optic Network, Inc. develops, constructs, owns and operates a
fiber optic telecommunications system in New York and New England.
MaineCom owns 37.9 percent of its common stock.
- - TeleSmart provides collections and related accounts receivable management
services and has a division which collects charged-off accounts.
- - Central Securities Corporation owns and leases office and service
facilities in Central Maine Power's service territory for the conduct of
Central Maine Power's business. Central Maine Power owns all of the
outstanding common stock of Central Securities.
- - Cumberland Securities Corporation also owns and leases office and service
facilities in Central Maine Power's service territory for the conduct of
Central Maine Power's business. Central Maine Power owns all of the
outstanding common stock of Cumberland Securities.
- - The Union Water-Power Company ("Union Water") provides utility construction
and support services (On Target division); energy efficiency performance
contracting and energy use and management services (Combined Energies
division); and commercial and residential real estate development services
(Union-Land Services and MaineHome Crafters division). Union Water is a
wholly-owned subsidiary of CMP Group.
-14-
<PAGE>
For the year ended December 1998, CMP Group's operating revenue on a
consolidated basis was approximately $950,327,000 of which approximately
$938,739,000 was derived from electric operations, and $11,588,000 from other
operations. Consolidated assets of CMP Group and its subsidiaries at December
31, 1998 were approximately $1,077,112,000 in net electric utility property,
plant and equipment; and approximately $1,185,772,000 in other corporate assets.
3. CTG Resources
CTG Resources is the parent company of Connecticut Natural Gas Corporation
("CNGC"), a regulated local natural gas distribution company, and of CNG Realty
Corp. ("CNGR") and The Energy Network, Inc. ("TEN"), non-utility subsidiaries.
CTG Resources is a holding company by virtue of owning all of the common stock
of CNGC, a public utility company as defined in the Act, which owns and operates
a local natural gas distribution system in the State of Connecticut. CTG
Resources is currently exempt from all provisions of the Act, except Section
9(a)(2), under Section 3(a)(1) of the Act and Rule 2 thereunder.
(a) Public Utility Affiliate of CTG Resources
Connecticut Natural Gas Corporation
--------------------------------------
CNGC, the regulated subsidiary of CTG Resources, distributes gas to
approximately 143,300 customers in 22 Connecticut communities, principally in
the Hartford-New Britain area and Greenwich. CNGC's gas distribution business
is subject to regulation by the DPUC as to franchises, rates, standards of
service, issuance of securities, safety practices and certain other matters.
Retail sales of gas by CNGC and deliveries of gas owned by others are made
pursuant to rate schedules and contracts filed with and subject to DPUC
approval.
-15-
<PAGE>
(b) Non-Public Utility Affiliates of CTG Resources
- - CNGR, formed in 1977, is a single purpose corporation which owns the
Operating and Administrative Center located on a seven-acre site in
downtown Hartford, Connecticut. CNGR engages in no other business activity.
- - TEN is an unregulated subsidiary of CTG Resources, which was incorporated
in 1982. TEN and its wholly-owned subsidiary, The Hartford Steam Company
("HSC"), provide district heating and cooling services to a number of large
buildings in Hartford, Connecticut.
- - TEN's wholly-owned subsidiary TEN Transmission, owns CTG Resources' 4.87
percent interest in Iroquois Gas Transmission System.
- - TEN's other unregulated operating divisions offer energy equipment rentals,
property rentals and financing services and own a 3,000 square foot
building in Hartford, Connecticut.
For the fiscal year ended 1998, CTG Resources' operating revenues on a
consolidated basis were approximately $282,748,000, of which approximately
$262,446,000 were derived from gas operations and $20,302,000 were from other
operations. Consolidated assets of CTG Resources and its subsidiaries at
September 30, 1998 were approximately $294,704,000 in identifiable gas utility
property, plant and equipment; and approximately $164,477,000 in other corporate
assets.
C. DESCRIPTION OF THE MERGER
1. CMP Group Merger Agreement
On June 14, 1999, CMP Group , Energy East and EE Merger Corp. entered into
the CMP Group Merger Agreement, providing for a merger transaction among CMP
Group, Energy East and EE Merger Corp.
-16-
<PAGE>
Pursuant to the CMP Group Merger Agreement, EE Merger Corp. will merge with
and into CMP Group, with CMP Group being the surviving corporation and becoming
a wholly-owned subsidiary of Energy East. The CMP Group Merger, which was
unanimously approved by the respective boards of directors of CMP Group, Energy
East and EE Merger Corp., is expected to occur shortly after all of the
conditions to the consummation of the CMP Group Merger, including the receipt of
required regulatory and shareholder approvals, are satisfied.
Under the terms of the CMP Group Merger Agreement, each outstanding share
of CMP Group's common stock, $5.00 par value per share, other than dissenting
shares and any treasury shares or shares owned by any subsidiary of the CMP
Group, Energy East or any of their subsidiaries will be converted into the right
to receive $29.50 in cash. Pursuant to the CMP Group Merger Agreement,
approximately $957 million in cash will be paid to holders of shares of CMP
Group common stock.
2. CTG Resources Merger Agreement
On June 29, 1999, CTG Resources entered into the CTG Resources Merger
Agreement with Energy East and Oak Merger Co. ("Oak"), pursuant to which CTG
Resources will merge with and into Oak.
Under the terms of the CTG Resources Merger Agreement, each outstanding
share of CTG Resources common stock, other than dissenting shares, will be
converted into the right to receive (i) $41.00 in cash ("CTG Resources Cash
Consideration"); or (ii) a number of shares of Energy East common stock equal to
the Exchange Ratio; or (iii) the right to receive a combination of cash and
shares of Energy East common stock. The "Exchange Ratio" shall be equal to the
CTG Resources Cash Consideration divided by either: (i) the Energy East share
price if the Energy East share price is equal to or less than $30.13 and equal
to or more than $23.67, (ii) $30.13 if the Energy East share price is greater
than $30.13, in which case the Exchange Ratio will equal 1.3609, or (iii) $23.67
if the Energy East share price is less than $23.67, in which case the Exchange
Ratio will equal 1.7320. The Energy East share price will equal the average of
-17-
<PAGE>
the closing prices of Energy East common stock as reported in the Wall Street
Journal, for the 20 trading days immediately preceding the second trading day
prior to the effective time of the CTG Resources Merger. The aggregate number
of shares of CTG Resources' common stock that is convertible into cash is
limited to 55 percent of the total number of shares of CTG Resources common
stock issued and outstanding as of the effective time of the CTG Resources
Merger.
D. MANAGEMENT AND OPERATION OF THE COMPANIES FOLLOWING THE MERGER
At the effective date of the CMP Group Merger, David T. Flanagan, the
current President and Chief Executive Officer of CMP Group, and two current
directors of CMP Group will be elected as members of the Board of Directors of
Energy East. At that time, Mr. Flanagan will become President of Energy East
and Chairman, President and Chief Executive Officer of the surviving company
(which will be a subsidiary of Energy East), and Arthur W. Adelberg, who
currently serves as Executive Vice President of CMP Group, will become a Senior
Vice President and the Chief Financial Officer of Energy East. Sara J. Burns,
who currently serves as President of Central Maine Power, will continue serving
as President of Central Maine Power after consummation of the CMP Group Merger.
F. Michael McClain, Vice President, Corporate Development of CMP Group, will
serve as the President of one or more non-utility subsidiaries of Energy East,
Xenergy Enterprises, and/or CMP Group after the CMP Group Merger becomes
effective.
Commencing at the effective date of the CTG Resources Merger, and
continuing until his successor is duly elected, Arthur C. Marquardt will be
President and Chief Executive Officer of the surviving corporation and will hold
other positions in other subsidiary corporations of Energy East as specified in
his employment agreement. One director of CTG Resources will become a director
of Energy East. The officers of Oak immediately prior to the consummation of
-18-
<PAGE>
the CTG Resources Merger will be the initial officers of the surviving
corporation (except that Mr. Marquardt will be the President and Chief Executive
Officer of the surviving corporation) and will hold office from the effective
date until their respective successors are duly elected or appointed and
qualified in the manner provided in the certificate of incorporation and by-laws
of the surviving corporation.
ITEM 2. FEES, COMMISSIONS AND EXPENSES
The fees, commissions and expenses to be paid or incurred, directly or
indirectly, by the Companies in connection with the Merger, including the
solicitation of proxies, the payment of legal and investment banker fees and
other related matters are estimated as follows:
<TABLE>
<CAPTION>
<S> <C>
Commission filing fee for the Registration Statement on Form S-4
in connection with the CTG Resources Merger. . . . . . . . . . . . . . . $ 67,915
Commission filing fee for the CMP Group Proxy Statement. . . . . . . . . 194,289
Accountants' fees. . . . . . . . . . . . . . . . . . . . . . . . . . . . 500,000
Legal fees and expenses. . . . . . . . . . . . . . . . . . . . . . . . . 6,000,000
Shareholder communication and proxy solicitation . . . . . . . . . . . . 405,000
Investment bankers' fees and expenses. . . . . . . . . . . . . . . . . . 20,200,000
Consulting fees related to the Merger. . . . . . . . . . . . . . . . . . 1,500,000
Expenses related to integrating the operations of the merged company and
miscellaneous
TOTAL. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35,500,000
</TABLE>
ITEM 3. APPLICABLE STATUTORY PROVISIONS
The following sections of the Act and the Commission's rules thereunder are
or may be directly or indirectly applicable to the proposed transaction:
Section of the Act Transactions to which section or rule is or may be
- ------------------ ------------------------------------------------------
applicable
----------
9(a)(2), 10 Acquisition indirectly by Energy East of common stock of
public utility subsidiaries of CMP Group and public utility
subsidiary of CTG Resources.
-19-
<PAGE>
8, 11(b), Retention by Energy East of its existing retail gas utility
operations; retention by Energy East of non-utility
businesses of Energy East, CMP Group and CTG Resources; and
operation of Energy East as a combination electric and gas
utility holding company.
To the extent that other sections of the Act are deemed applicable to the
Merger, such sections should be considered to be set forth in this Item 3.
Background
----------
As discussed in detail below, until recently both NYSEG and Central Maine
Power were vertically integrated utilities, and each provided "bundled" sales
service (i.e., energy, capacity, ancillary services, transmission and local
----
distribution, combined to be a single product -- delivered electricity) to
wholesale and retail customers. Prior to its recent divestiture of generating
assets, NYSEG owned approximately 2,557 MW of generating capacity and Central
Maine Power owned approximately 1,070 MW of generating capacity. Also, within
their franchised service areas, both NYSEG and Central Maine Power were granted
the exclusive right to provide electricity to their retail customers.
The historical industry structure of vertically integrated utilities
providing electric service within franchised service areas began to change with
the development of the "generation-only" power business that was mobilized by
the enactment of the Public Utility Regulatory Policies Act of 1978 ("PURPA")
and the Energy Policy Act of 1992. Also contributing to this change were the
actions of state and federal regulators in attempting to overcome the inherent
incentive for vertically integrated companies to use their transmission and
distribution systems to favor sales from their own (or affiliated) generating
resources or their purchased power contracts, over energy provided by
unaffiliated suppliers. Regulators were concerned that utilities would limit
competition at the generation level, which would otherwise have imposed downward
pressure on prices, to the advantage of customers. As described more fully
below, the policy underlying recent state and federal policy has been to reduce
or eliminate the incentives and opportunities for vertically integrated
-20-
<PAGE>
utilities to constrain competition, by requiring utilities to divest generation,
to separate "functionally" their merchant functions from their transmission
functions, and to transfer operational control of their transmission systems to
Regional Transmission Organizations ("RTOs"). Many state and federal policy
makers have concluded that competition at the generation level is fostered by
according retail customers the right to obtain "unbundled" electric energy from
a supplier of their choice, and, with respect to retail and wholesale customers,
by requiring utilities to provide open-access, nondiscriminatory transmission
and distribution service over their transmission and distribution systems.
In states in which these types of structural changes have been implemented,
transmission-owning utilities no longer have the ability to dictate which
generation units or purchased power contracts will be dispatched to serve
customer load. Instead, that selection is made through a competitive process,
either in the form of bilateral contracts between the seller and buyer (or
representatives of either) or through an established centralized market or power
exchange. In either case, the operation and dispatch of generation is no longer
performed or controlled by the transmission-owning distribution utility, but
rather by unaffiliated buyers and sellers responding to the laws of supply and
demand in accordance with the policies of an RTO.
The fundamental changes in the historical structure of the utility industry
have profound effects on the "integration" and operation as a "single
interconnected and coordinated system," as these terms are used in the Act. The
Companies are well aware of the considerable challenge the Commission faces in
applying the Act to an evolving industry structure. Thus, the Companies are
including in this section of the Application/Declaration a detailed description
of the industry restructuring to date in both New York and New England in order
to assist in the Commission's review and to establish the framework for
integration as applied to the Merger.
-21-
<PAGE>
A. Section 9(a)(2)
Section 9(a)(2) of the Act makes it unlawful, without approval of the
Commission under Section 10, "for any person to acquire, directly or
indirectly, any security of any public utility company, if such person is an
affiliate of such company and of any other public utility or holding company,
or will by virtue of such acquisition become such an affiliate." Under the
definition set forth in Section 2(a)(11)(A) of the Act, an "affiliate" of a
specified company means "any person that directly or indirectly owns, controls,
or holds with power to vote, 5 per centum or more of the outstanding voting
securities of such specified company," and "any company 5 per centum or more of
whose outstanding voting securities are owned, controlled, or held with power to
vote, directly or indirectly, by such specified company."
Energy East, CMP Group and CTG Resources are holding companies as defined
in Section 2(a)(5) of the Act. As a result of the Merger, Energy East, directly
or indirectly, will acquire more than five percent of the voting securities of
the public utility subsidiaries of both CMP Group and CTG Resources. Energy
East will thus become an "affiliate," as defined in Section 2(a)(11)(A) of the
Act, of the public utility subsidiaries of both CMP Group and CTG Resources.
Accordingly, Energy East must obtain the approval of the Commission for the
Merger under Sections 9(a)(2) and 10 of the Act. The statutory standards to be
considered by the Commission in evaluating the proposed transaction are set
forth in Sections 10(b), 10(c) and 10(f) of the Act.
-22-
<PAGE>
The Companies believe that the Merger complies with all of the applicable
provisions of Section 10 of the Act and should be approved by the Commission.
Thus:
- the Merger will not create detrimental interlocking relations or
concentration of control;
- the consideration to be paid in the Merger is fair and
reasonable;
- the Merger will not result in an unduly complicated capital
structure for the post-Merger Energy East system;
- the Merger is in the public interest and the interests of
investors and consumers;
- the Merger is consistent with Sections 8 and 11 of the Act;
- the Merger tends toward the economical and efficient development
of an integrated public utility system; and
- the Merger will comply with all applicable state laws.
The Commission's approval of this Application/Declaration will facilitate
the creation of a holding company which will be better able to compete in the
rapidly evolving utility industry, and is consistent with the Commission's
precedents for transactions previously approved by the Commission under the Act.
Additionally, the Merger and the requests contained in this
Application/Declaration are consistent with the interpretive recommendations
made by the Division of Investment Management (the "Division") in the report
issued by the Division in June 1995 entitled "The Regulation of Public Utility
Holding Companies" (the "1995 Report"). The Division's overall recommendation
that the Commission "act administratively to modernize and simplify holding
company regulationand minimize regulatory overlap, while protecting the
interests of consumers and investors,"(13) is germane to the Commission's review
of this Application/Declaration since, as demonstrated below, the Merger will
benefit both consumers and shareholders of post-Merger Energy East and since the
other federal and state regulatory authorities with jurisdiction over the Merger
are expected to approve the Merger as in the public interest. In addition, as
discussed in more detail in each applicable item below, the specific
recommendations of the Division with regard to utility ownership(14) and
diversification,(15) in particular, are applicable to the Merger.
- -----------------------
(13) Letter of the Division of Investment Management to the Securities and
Exchange Commission, 1995 Report.
(14) Among other things, the 1995 Report recommends that the Commission should
apply a more flexible interpretation of the integration requirements under the
Act; interconnection through power pools, reliability councils and wheeling
arrangements can satisfy the physical interconnection requirement of Section
2(a)(29); the geographic requirements of Section 2(a)(29)(A) should be
interpreted flexibly, recognizing technical advances consistent with the
purposes and provisions of the Act; the Commission's analysis should focus on
whether the resulting system will be subject to effective regulation; the
Commission should liberalize its interpretation of the "A-B-C" clauses and
permit combination systems where the affected states agree, and the Commission
should "watchfully defer" to the work of other regulators. 1995 Report at 71-77.
(15) The 1995 Report recommends that, for example, the Commission should
promulgate rules to reduce the regulatory burdens associated with energy-related
diversification and the Commission should adopt a more flexible approach in
considering all other requests to enter into diversified activities. 1995 Report
at 88-90. The recommendations regarding energy-related diversification were
incorporated in Rule 58.
-23-
<PAGE>
B. SECTION 10(B)
Section 10(b) provides that, if the requirements of Section 10(f) are
satisfied, the Commission shall approve an acquisition under Section 9(a)
unless:
(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 interests 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 interests of investors or consumers or the proper functioning of
such holding company system.
1. Section 10(b)(1)
-----------------
Section 10(b)(1) is intended to avoid "an excess of concentration and
bigness" while preserving 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" afforded by the
coordination of local utilities into an integrated system.(16) In applying
Section 10(b)(1) to utility acquisitions, the Commission must determine whether
the acquisition will create "the type of structures and combinations at which
the Act was specifically directed." (17) As discussed below, the Merger will not
create a "huge, complex, and irrational system," but rather will afford the
opportunity to achieve economies of scale and efficiencies which are expected to
--------
benefit investors and consumers. (18)
The Merger is not being undertaken for the purpose of extending Energy
East's control over regulated public utilities and will not lead to the type of
concentration of control over utilities, unrelated to operating efficiencies,
that Section 10(b)(1) was intended to prevent. The primary objective of Energy
East in the Merger is to become positioned to participate in the growing and
increasingly competitive northeastern United States energy market. The
Applicants believe that their combination provides a unique opportunity for
Energy East, CMP Group and CTG Resources and their respective shareholders,
customers and employees to participate in the formation of a competitive energy
services provider in the rapidly evolving energy services business and to share
in the benefits of industry restructuring which is already occurring in New
York, Maine, Connecticut and other states.
Size: If approved, the post-Merger Energy East system will serve
----
approximately 1,359,000 electric customers in two states and 545,300 gas
customers in three states. For 1998: (1) the combined assets of post-Merger
Energy East, CMP Group and CTG Resources would have totaled approximately $7.4
billion; and (2) combined operating revenues of these Companies would have
totaled approximately $4 billion.
By comparison, there are several registered electric utility holding
companies that are significantly larger than the post-Merger Energy East system.
The following table shows the post-Merger Energy East system's relative size as
compared to other registered systems in terms of assets, operating revenues and
customers.(19)
- -----------------------
(16) American Electric Power Co., 46 S.E.C. 1299, 1309 (1978).
---------------------------
(17) Vermont Yankee Nuclear Corp., 43 S.E.C. 693, 700 (1968).
---------------------------
(18) American Electric Power Co., 46 S.E.C. at 1307 (1978).
---------------------------
(19) Source: U.S. Securities and Exchange Commission, Financial and Corporate
Report, Holding Companies Registered under the Public Utility Holding
Company Act of 1935 as of July 1, 1999 (data provided is as of Dec. 31,
1998).
<PAGE>
<TABLE>
<CAPTION>
Total Assets Operating Revenues Electric Customers
System ($Million) ($Million) (Thousands)
- ----------- -------------- -------------------- -------------------
<S> <C> <C> <C>
Southern. . $ 36,192 $ 11,403 3,794
Entergy . . 22,848 11,495 2,495
AEP . . . . 19,483 6,346 3,022
GPU . . . . 16,288 4,249 2,041
CSW . . . . 13,744 5,482 1,752
Energy East 7,398 3,983 1,359
</TABLE>
As illustrated by the table above, Energy East will be a small registered
holding company in comparison to other registered holding companies. In
addition, Energy East's operations will not exceed the economies of scale of
current electric generation and transmission technology, or gas transportation
technology, or provide undue power or control to Energy East in the region in
which it will provide service.
Efficiencies and economies: The Commission has rejected a mechanical size
---------------------------
analysis under Section 10(b)(1) in favor of assessing the size of the resulting
system with reference to the efficiencies and economies that can be achieved
through the integration and coordination of utility operations. More recent
pronouncements of the Commission confirm that size is not determinative,
particularly in light of the improved economies of scale that can be achieved
through a combination. (20)
By virtue of the Merger, post-Merger Energy East will be in a position 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 Co.(21) Among other things, the Merger is expected to yield
- -------------------
significant capital expenditure savings through facilities consolidation,
corporate and administrative programs, non-fuel purchasing economies and
combined gas supply. These expected economies and efficiencies from the
combined utility operations are described in greater detail below.
Competitive Effects: In Northeast Utilities (22) the Commission stated that
------------------- -------------------
"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." Energy East, CMP
Group and CTG Resources will file Notification and Report Forms with the DOJ
and FTC pursuant to the HSR Act describing the effects of the Merger on
competition in the relevant markets. It is a condition to the consummation of
each of the CMP Group and CTG Resources Mergers that the applicable waiting
periods under the HSR Act shall have expired or been terminated.
In addition, the competitive impact of the CMP Group Merger is currently
being considered pursuant to the October 1, 1999 filing of Energy East and CMP
Group with FERC under Section 203 of the Federal Power Act. A detailed
explanation concerning why such merger will not threaten competition in even the
most narrowly drawn geographic and product markets is set forth in the prepared
testimony of Stephen Henderson, an economist and Vice President of PHB Hagler
Bailly, filed with the FERC application. Mr. Henderson's testimony addresses
potential horizontal and vertical market power issues by analyzing not only
Energy East's merger with CMP Group, but also its acquisition of the natural gas
operations of CNE and CTG Resources. Mr. Henderson concludes that no market
power concerns are raised by the proposed transactions. A copy of the FERC
application, including Mr. Henderson's prepared testimony as an attachment, is
filed as Exhibit D-1 hereto. It is anticipated that FERC will rule that the CMP
Group Merger will not significantly affect competition in any relevant market.
- -----------------------
(20) See, e.g., 1995 Report at 73-4; Centerior Energy Corp., HCAR No. 24073
--- --- ---------------------
(April 29, 1986).
(21) American Elec. Power Co., Inc., 46 S.E.C. 1299, 1309 (1978).
----------------------------------
(22) Northeast Utilities, HCAR No. 25221 (Dec. 21, 1990).
--------------------
<PAGE>
The Merger has been carefully structured to protect the interests of
consumers and other local interests while ensuring that the only management
interlocks created are those which are necessary to integrate CMP Group and CTG
Resources into the Energy East system. Furthermore, there will be continuity of
management because, following the Merger, the management of the regulated
utility subsidiaries of CMP Group and CTG Resources will largely be comprised of
their respective current management. In addition, the CMP Group Merger
Agreement provides that the current CMP Group Board of Directors will serve as
an advisory board to Central Maine Power, and the CTG Resources Merger Agreement
provides that the current CTG Resources Board of Directors will serve as an
advisory board to the surviving company. Such continuity of management
oversight will help to assure that the management of the regulated utility
subsidiaries of CMP Group and CTG Resources remain responsive to local
regulation and to other essentially local interests. For the reasons set forth
above, the Merger will not "tend toward interlocking relations or the
concentration of control" of public utility companies, of a kind or to the
extent detrimental to the public interest or the interests of investors or
customers within the meaning of Section 10(b)(1).
2. Section 10(b)(2)
-----------------
(a) Reasonableness of Consideration
Section 10(b)(2) requires the Commission to determine whether the
consideration to be given by Energy East to the holders of CMP Group common
stock and CTG Resources common stock in connection with the Merger, including
fees and expenses of the Merger, is reasonable and whether it bears a fair
relation to the investment in and earning capacity of the utility assets
underlying the securities being acquired. Market prices at which securities are
traded have always been strong indicators as to values. As shown in the table
below, the most recent quarterly price data, high and low, for CMP Group and CTG
Resources common stock provide support for the consideration paid in the Merger.
Comparative Per Share Market Price:
<TABLE>
<CAPTION>
ENERGY EAST*
PRICE RANGE
HIGH LOW
------------- --------
<S> <C> <C>
1997
First Quarter. $ 12.25 $ 10.625
Second Quarter $ 11.25 $10.3125
Third Quarter. $ 13.5938 $10.4063
Fourth Quarter $ 17.875 $ 12.875
1998
First Quarter. $ 20.25 $16.5313
Second Quarter $ 22.0938 $19.4689
Third Quarter. $ 25.6875 $19.9375
Fourth Quarter $ 29.00 $ 23.375
1999
First Quarter. $ 28.625 $24.5625
Second Quarter $ 28.125 $ 24.75
Third Quarter. $ 27.0625 $ 22.625
<FN>
*Per share amounts have been restated to reflect Energy East's two-for-one
common stock split effective April 1, 1999.
</TABLE>
<TABLE>
<CAPTION>
CMP GROUP
PRICE RANGE
------------
HIGH LOW
------------ --------
<S> <C> <C>
1997
First Quarter. $ 11.625 $ 10.50
Second Quarter $ 12.75 $ 10.00
Third Quarter. $ 13.5625 $12.0625
Fourth Quarter $ 15.50 $ 12.875
1998
First Quarter. $ 17.8125 $ 15.25
Second Quarter $ 20.375 $17.0625
Third Quarter. $ 20.50 $16.9375
Fourth Quarter $ 20.00 $ 16.75
1999
First Quarter. $ 19.5625 $ 16.25
Second Quarter $ 26.75 $ 17.75
Third Quarter. $ 27.00 $ 26.00
</TABLE>
<TABLE>
<CAPTION>
CTG RESOURCES
PRICE RANGE
HIGH LOW
-------------- --------
<S> <C> <C>
1997
First Quarter. $ 25.375 $ 21.375
Second Quarter $ 22.25 $ 20.75
Third Quarter. $ 23.8125 $ 21.625
Fourth Quarter $ 26.50 $ 22.75
1998
First Quarter. $ 26.75 $ 23.375
Second Quarter $ 25.9375 $21.9375
Third Quarter. $ 24.50 $ 22.375
Fourth Quarter $ 26.3125 $ 22.625
1999
First Quarter. $ 26.375 $ 22.25
Second Quarter $ 36.75 $ 22.125
Third Quarter. $ 37.188 $ 34.25
</TABLE>
On June 14, 1999, the last full trading day before the public announcement
of the execution and delivery of the CMP Group Merger Agreement, the closing
price per share of CMP Group common stock as reported on the NYSE -- Composite
Transaction of CMP Group common stock was $20-1/16. On June 29, 1999, the last
full trading day before the public announcement of the execution and delivery of
the CTG Resources Merger Agreement, the closing price per share of CTG Resources
common stock as reported on the NYSE-- Composite Transaction of CTG Resources
common stock was $35.625.
In its determinations as to whether or not a price meets the reasonableness
standard, the Commission has considered whether the price was decided as the
result of arms-length negotiations (23) and the opinions of investment bankers,
(24) among other things. For the reasons given below, there is no basis in
this case for the Commission to make any negative findings concerning the
consideration being offered by Energy East in the Merger. The Commission has
previously recognized that when the consideration to be paid in an acquisition
is the result of arms length negotiations between the management of the
companies involved, supported by opinions of financial advisors, there is
persuasive evidence that the requirements of Section 10(b)(2) have been
satisfied.(25) The agreed-upon level of consideration was the product of
extensive and vigorous arms length negotiations between Energy East and each of
CMP Group and CTG Resources. These negotiations were preceded by appropriate
due diligence, analysis and evaluation of the assets, liabilities and business
prospects of the respective companies. An extensive discussion of the
negotiations that took place in connection with the CMP Group Merger is found at
pages 17-20 of the CMP Group Proxy Statement, incorporated by reference as
Exhibit C-2. An extensive discussion of the negotiations that took place in
connection with the CTG Resources Merger is found at pages 27-32 of the CTG
Resources Proxy Statement/Prospectus, incorporated by reference as Exhibit C-1.
- -----------------------
(23) In the Matter of American Natural Gas Company, HCAR No. 15620 (Dec. 12,
-----------------------------------------------
1966).
(24) Consolidated Natural Gas Company, Holding Co. Act Release No. 25040 (Feb.
----------------------------------
14, 1990).
(25) See Entergy Corporation, et al, HCAR No. 25952 (Dec. 17, 1993); The
----------------------------- ---
Southern Company, et al., 40 S.E.C. Docket 350 at 352 (Feb. 12, 1988).
-------------------------
<PAGE>
Investment bankers for CMP Group and CTG Resources have reviewed extensive
information concerning the CMP Group Merger and the CTG Resources Merger, have
analyzed the conversion ratios employing a variety of valuation methodologies,
and have opined that the conversion ratios are fair, from a financial point of
view, to the respective holders of CMP Group common stock and CTG Resources
common stock. The investment bankers' analyses and opinions are incorporated by
reference as Exhibits G-1 and G-2. A copy of Warburg Dillon Read's opinion is
attached as Appendix B to the CMP Group Proxy Statement, incorporated by
reference as Exhibit C-2. A copy of PaineWebber's opinion is attached as
Appendix B to the CTG Resources Proxy Statement/Prospectus, incorporated by
reference as Exhibit C-1.
Finally, Energy East engaged Morgan Stanley Dean Witter and Co. with
respect to the CTG Resources Merger, and Goldman Sachs & Co. with respect to the
CMP Merger. Each provided a "fairness" opinion regarding these respective
transactions to the Energy East Board of Directors. In light of these opinions
and an analysis of all relevant factors, including the benefits that may be
realized as a result of the Merger, the Companies believes that the conversion
ratios fall within the range of reasonableness, and the consideration to be paid
in both the CMP Group Merger and the CTG Resources Merger bear a fair relation
to the sums invested in, and the earning capacity of, the utility assets of CMP
Group and CTG Resources.
(b) Reasonableness of Fees
The Companies believes that the overall fees, commissions and expenses
incurred and to be incurred in connection with the Merger are reasonable and
fair in light of the size and complexity of the Merger relative to other
transactions and the anticipated benefits of the Merger to the public, investors
and consumers, that they are consistent with recent precedent, and that they
meet the standards of Section 10(b)(2).
As set forth in Item 2 of this Application/Declaration, Energy East, CMP
Group and CTG Resources together expect to incur a combined total of
approximately $31 million in fees, commissions and expenses in connection with
the Merger, excluding expenses related to integrating the operations of the
merged company. Such fees will be paid on an arms length basis to third parties
and are consistent with fees, commissions and expenses paid for similar
transactions and approved by the Commission as reasonable. For example,
Northeast Utilities alone incurred $46.5 million in fees and expenses in
connection with its acquisition of Public Service of New Hampshire, and Entergy
incurred $38 million in fees in connection with its recent acquisition of Gulf
States Utilities -- which amounts all were approved as reasonable by the
Commission.(26)
The Companies also believe that the financial advisory fees payable to
their respective investment bankers are fair and reasonable for similar reasons.
Pursuant to its engagement letter, CMP Group paid Warburg Dillon Read $1 million
upon the rendering of Warburg Dillon Read's fairness opinion. In addition,
Warburg Dillon Read received $100,000 upon the execution of the engagement
letter and is receiving a $50,000 quarterly retainer. Upon the approval of the
CMP Group Merger Agreement by shareholders, Warburg Dillon Read received an
additional $1 million. At the completion of the CMP Group Merger, Warburg
Dillon Read will receive a fee equal to 0.6 percent of the aggregate
consideration paid in the CMP Group Merger, which fee is expected to equal
approximately $5.74 million, less the amount of all fees previously paid. CMP
Group has agreed to indemnify Warburg Dillon Read against certain liabilities
under federal securities laws, relating to or arising out of its engagement.
- -----------------------
(26) See Northeast Utilities, HCAR No. 25548 (June 3, 1992); Entergy Corp., HCAR
------------------- ------------
No. 25952 (Dec. 17, 1993).
<PAGE>
Pursuant to its engagement letter with CTG Resources dated June 25, 1998,
PaineWebber has earned a retention fee of $200,000 and a fee of approximately
$1,742,000 for the rendering of a fairness opinion. In addition, PaineWebber
will receive a fee of approximately $1,642,000 upon completion of the CTG
Resources Merger, and will be reimbursed for certain related expenses.
PaineWebber will not be entitled to any additional fees or compensation in the
event the CTG Resources Merger is not approved or otherwise completed. CTG
Resources also separately agreed to indemnify PaineWebber against certain
liabilities, including liabilities under federal securities laws.
Pursuant to the engagement letter between Energy East and Goldman Sachs,
Energy East paid Goldman Sachs $2.3 million upon the public announcement of the
CMP Group Merger Agreement. In addition, Goldman Sachs received $2.3 million
upon the approval of the CMP Group Merger Agreement by the shareholders of CMP
Group. Goldman Sachs will receive an additional payment of $2.4 million at the
completion of the CMP Group Merger. Energy East has agreed to indemnify Goldman
Sachs against certain liabilities under federal securities laws, relating to or
arising out of its engagement.
Pursuant to the engagement letter between Energy East and Morgan Stanley
Dean Witter, Energy East paid Morgan Stanley Dean Witter $1.2 million upon the
public announcement of the CTG Resources Merger Agreement. In addition, Morgan
Stanley Dean Witter received $1.2 million upon the approval of the CTG Resources
Merger Agreement by the shareholders of CTG Resources. Morgan Stanley Dean
Witter will receive an additional payment of $1.3 million at the completion of
the CTG Resources Merger. Energy East has agreed to indemnify Morgan Stanley
Dean Witter against certain liabilities under federal securities laws, relating
to or arising out of its engagement.
The investment banking fees paid by CMP Group, CTG Resources and Energy
East are lower than fees paid in other similar transactions and approved by the
Commission as reasonable. The fees reflect the financial marketplace, in which
investment banking firms actively compete with each other to act as financial
advisors to merger partners.
3. Section 10(b)(3)
-----------------
Section 10(b)(3) requires the Commission to determine whether the Merger
will unduly complicate Energy East's capital structure or will be detrimental to
the public interest, the interests of investors or consumers or the proper
functioning of Energy East's system.
The Commission has found that an acquisition satisfies this requirement
where the effect of a proposed acquisition on the acquirer's capital structure
is negligible and the equity position is at or above the traditionally
acceptable 30 percent level prescribed by the Commission. (27) The Commission
has approved common equity to total capitalization ratios as low as 27.6
percent. (28) Under these standards, the proposed combination of Energy East,
--- --------- -----
CMP Group and CTG Resources will not unduly complicate the capital structure
of the combined system.
Set forth below are summaries of the historical capital structures of
Energy East, CMP Group and CTG Resources as of June 30, 1999 and the pro forma
consolidated capital structure of post-Merger Energy East as of June 30, 1999:
- -----------------------
(27) See, e.g., Entergy Corp., 55 S.E.C. 2035 (Dec. 17, 1993); Northeast
--- ---- ------------- ---------
Utilities, 47 S.E.C. 1279 (1990).
---------
(28) See Northeast, supra.
--- --------- -----
<PAGE>
<TABLE>
<CAPTION>
Energy East, CMP Group and CTG Resources
Historical Consolidated Capital Structures
(Dollars in thousands)
CTG
PRE-MERGER ENERGY EAST CMP GROUP RESOURCES
<S> <C> <C> <C> <C>
Common Stock Equity. . . . . . $ 1,754,365 52.8% $ 541,478 $ 133,779
Preferred stock not subject to
mandatory redemption . . . . . 10,131 .3% 35,528 879
Preferred stock subject to
mandatory redemption . . . . . 25,000 .8% 18,910 --
Long-Term Debt . . . . . . . . 1,535,079 46.1% 124,205 217,516
- ------------------------------ ----------- ------------ ---------- ----------
Total. . . . . . . . . . . . . $ 3,324,575 100.0% $ 720,121 $ 352,174
</TABLE>
<TABLE>
<CAPTION>
Post-Merger Energy East Pro Forma Consolidated Capital Structure*
(Dollars in thousands)
(unaudited)
POST-MERGER
ENERGY EAST
------------------
<S> <C>
Common Stock Equity (incl. additional paid in capital). . . . . . . . $1,913,921 43.7%
Preferred stock not subject to mandatory redemption (of subsidiaries) 46,538 1.1%
Preferred stock subject to mandatory redemption (of subsidiaries). . . 43,910 1.0%
Long-Term Debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,376,800 54.2%
- ---------------------------------------------------------------------- ------------------
Total $4,381,169 100.0%
</TABLE>
As can be seen from these tables, post-Merger Energy East's pro forma
consolidated equity to total capitalization will be 43.7 percent, which will be
significantly higher than Northeast Utilities' approved 27.6 percent common
equity position and will exceed the traditionally accepted 30 percent level.
The capital structure of post-Merger Energy East will also be substantially
similar to the capital structures approved by the Commission in other orders.
(29)
Protected interests: As set forth more fully in Item 3.C.4 (Efficiencies
--------------------
and Economies from the Merger (Section 10(C)(2)), Item 3.C.2(b)(iii)
(Coordination between ISO-NE and NYISO) and Item 3.C.4. (Economics and
Efficiencies from the Merger (Section 10(c)(2)), and elsewhere in this
Application/Declaration, the Merger is expected to result in economies and will
integrate and improve the efficiency of the Energy East, CMP Group and CTG
Resources utility systems. The Merger will create an entity poised to respond
effectively to the fundamental changes taking place in the markets for natural
gas and electric power and to compete effectively for consumers' business. The
Merger will therefore 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.
As indicated previously, consummation of the Merger is conditioned upon
receipt not only of the Commission's approval, but also on several state and
other federal regulatory approvals. Those regulatory approvals give additional
assurance that the interests of retail customers are adequately protected.
FERC's approval of the CMP Group Merger will further assure that there is no
significant adverse effect on competition. In sum, because the Merger does not
add any complexity to Energy East's capital structure, is in the interest of
investors and consumers, and is consistent with the public interest, the
requirements of Section 10(b)(3) are met.
C. SECTION 10(C)
Section 10(c) of the Act provides that, notwithstanding the provisions of
Section 10(b), the Commission shall not approve:
- -----------------------
(29) See, e.g., Ameren Corporation, HCAR No. 26809 (Dec. 30, 1997); CINergy
--- ---- ------------------- -------
Corp., HCAR No. 26934 (Nov. 2, 1998); and Centerior Energy Corp., HCAR No. 24073
---------------------
(April 29, 1986).
<PAGE>
(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 the efficient development
of an integrated public utility system.
1. Acquisition Must Be Lawful
-----------------------------
Section 10(c)(1) requires that an acquisition be lawful under Section 8.
Section 8 prohibits registered holding companies from acquiring, owning
interests in or operating both a gas and an electric utility serving
substantially the same area if state law prohibits it. As discussed below, the
Merger does not raise any issue under Section 8. Indeed, Section 8 indicates
that a registered holding company may own both gas and electric utilities where,
as here, the acquisition is subject to approval by the state utility commissions
with jurisdiction over the acquired companies. CMP Group and CTG Resources have
filed applications with the MPUC and the DPUC for approvals to approve their
mergers and they anticipate that such applications will be approved.
Section 10(c)(1) further requires that an acquisition not be detrimental to
carrying out the provisions of Section 11 of the Act. Section 11(a) of the Act
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. As described above, the Merger
will not result in unnecessary complexities or unfair voting powers.
Although Section 11(b)(1) generally requires a registered holding company
system to limit its operations "to a single integrated public utility system,
and to such other businesses as are reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public utility
system," a combination integrated gas and electric system within a registered
holding company is permissible under Section 8.(30) Additionally, Section
- ------- -------
11(b)(1) provides that "one or more additional integrated public utility
systems" may be retained if, as here, certain criteria are met. Section 11(b)(2)
directs the Commission "to 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."
- -----------------------
(30) See, e.g., New Century Energies, Inc., supra.
--- --- ----------------------------- -----
<PAGE>
As detailed below, the Merger will not be detrimental to the carrying
out of the provisions of Section 11. The combination of NYSEG's electric system
and CMP Group's electric operations will result in a single, integrated electric
utility system (the "new Energy East Electric System"). Integration of the new
Energy East Electric System will be facilitated by NYSEG's and Central Maine
Power's memberships in adjacent, highly interconnected and coordinated power
pools and participation in their ISOs, and will be accomplished by the
functioning of the open, competitive markets administered by the interconnected
ISOs. Sellers and purchasers in either ISO's control area may engage in
transactions in the other ISO's control area through readily-accessible,
OASIS-based transmission access. Further, the combination of Energy East's
current gas system (i.e., NYSEG's gas operations, Connecticut Energy and Maine
Gas Co.) with the gas operations of CMP Group and CTG Resources will result in a
single, integrated gas utility system operations in the same states as the
electric system or states adjoining those states (the "new Energy East Gas
System"). The Commission should accordingly find that the new Energy East
Electric System will be the primary integrated public utility system for
purposes of Section 11(b)(1) and the new Energy East Gas System is a permissible
additional system under Section 11(b)(1)A-C.
Furthermore, Section 10(c)(2) requires that the Commission approve a
proposed transaction if it will serve the public interest by tending toward the
economical and efficient development of an integrated public utility system.
This Section 10(c)(2) standard is met where the likely benefits of the
acquisition exceed its likely cost.(31) As discussed below, the Merger will
result in the creation of an integrated electric utility system and an
additional integrated gas utility system and will produce economies and
efficiencies more than sufficient to satisfy the standards of Section 10(c)(2).
- -----------------------
(31) See City of Holyoke v. SEC, 972 F.2d 358 (D.C. Cir. 1992).
--- --------------------------
<PAGE>
2. Combination and Integration of Electric Utility Operations
----------------------------------------------------------------
Section 2(a)(29)(A) of the Act defines an "integrated public utility
system," as applied to electric utilities, 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 operation 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. (emphasis added)
The Commission has established four standards under the statutory
integration requirement:
(1) The utility assets of the system are physically interconnected or
capable of physical interconnection;
(2) The utility assets, under normal conditions, may be economically
operated as a single interconnected and coordinated system;
(3) The system must be confined in its operations to a single area or
region; and
(4) 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.(32)
- -----------------------
(32) See, e.g., Environmental Action, Inc. v. Sec, 895 F.2d 1255, 1263 (9th Cir.
--- ---- ---------------------------------
1990), citing Electric Energy, Inc., 38 S.E.C. 658, 668 (1958).
-----------------------
<PAGE>
The Commission has traditionally been called upon to evaluate merger
applications that involve the combination of two traditional electric utilities.
That is, the utility applicants have been involved in all three levels or
sectors of utility operations: generation, transmission, and distribution.
Thus, the Commission has evaluated whether the Act's integration standard has
been met when combining the assets of fully integrated utilities. Where, as
here, the applicants are utilities that previously were vertically integrated,
but have become almost entirely engaged in transmission and distribution, the
Commission should, consistent with earlier precedent, find that an integrated
public utility system can be comprised of two or more transmission/distribution
companies.(33)
Since the function of transmission and distribution facilities is to
transfer electric energy from points of generation, or point of receipt from
another system, to load, or point of delivery with another system, transmission
facilities in and of themselves can, in appropriate circumstances, constitute an
integrated system and can perform an integrating function. Because of the
contiguous, highly interconnected, and coordinated relationships between the
power pools and ISOs to which NYSEG and Central Maine Power belong, their
transmission and distribution systems are now used, and in the future will be
used even more, to accomplish transfers of power between generation and load
within NYPP and NEPOOL and for transfers of power to, and through, both systems.
If the Merger is approved, the Companies will implement their proposal to reduce
transmission charges for transactions involving the NYSEG and Central Maine
systems; that price reduction should result in increased use of the NYSEG and
Central Maine Power transmission facilities and therefore an increased degree of
integration.
- -----------------------
(33) The Commission has previously determined that, without regard to the
combining of operations of generating facilities, transmission facilities,
on their own, can comprise an "integrated public utility system." See In re
--- -----
Sierra Pacific Power Company, 40 S.E.C. Docket 103 (Jan. 28, 1988), aff'd sub
- ---------------------------- ----- ---
nom., Environmental Action, Inc. v. SEC, 895 F.2d 1255 (9th Cir. 1990). As a
- ----------------------------------------
consequence the provisions of the Act, such as Section 10(c)(2), that
incorporate or refer to this term must be interpreted so as not to thwart the
Congressional intent.
<PAGE>
(a) Changes in the Electric Utility Industry
This section and the following sections describe the sweeping
structural changes that have taken place in the electric utility industry over
the last two decades. These changes include transformation of the markets at
both the wholesale and retail levels. Both this Commission and FERC have
recognized the significance of the changes. Recent FERC initiatives are likely
to promote the so-called "de-integration" of the industry even further. FERC's
recent RTO NOPR is promoting further regional transmission integration efforts
in order to facilitate even more competitive generation markets.(34)
The concept of a non-vertically integrated, generation-only business
enterprise was introduced with the enactment of PURPA. By the mid-1980's,
non-utility generation had out-paced utility generation additions. Power
marketers, which generally own no generating assets, but purchase and resell
power, also had become prevalent by the early 1990's. The Energy Policy Act of
1992 further contributed to the elimination of vertical integration of electric
utilities by enabling stand-alone generation of any type, with no restriction on
utility ownership or technology, to be exempted from "electric utility company"
status under the Act, and by significantly expanding the FERC's authority to
require utilities to provide non-discriminatory transmission for third-party
wholesale transactions.
In April 1996, in its Order Nos. 888 and 889, the FERC established the
framework for the development of fully competitive wholesale power markets in
the United States. These orders required vertically-integrated utilities
functionally to separate operation of their transmission systems from their
wholesale "merchant" function -- i.e., their role as a generator and seller,
----
and/or reseller of purchased power, to wholesale customers. Order No. 888
required all transmission-owning public utilities to establish open access
non-discriminatory transmission tariffs containing "pro forma" terms and
conditions. Utilities were also required to functionally unbundle wholesale
power services, so that they obtained wholesale transmission services under the
same tariff of general applicability as do unaffiliated third parties. Under
Order No. 889, utilities were required to establish or participate in an OASIS,
through which any eligible customer can obtain information regarding a public
utility's transmission availability and can reserve transmission capacity
through the Internet pursuant to a transparent, non-discriminatory process.
Finally, utilities were required to comply with standards of conduct designed to
prevent employees engaged in wholesale power marketing functions from obtaining
preferential access to pertinent transmission system information.
- -----------------------
(34) Notice of Proposed Rulemaking, Regional Transmission Organizations, Docket
-------------------------------------------------------------------
No. RM99-2-000, 87 FERC 61,173 at 33,693 (May 13, 1999) ("RTO NOPR").
<PAGE>
In summary, PURPA, the Energy Policy Act of 1992, and Order Nos. 888 and
889 transformed the industry to a more competitive structure. Where previously
vertically integrated companies combined generation, transmission and
distribution functions to provide a "bundled" product -- delivered electricity
- -- to retail customers within franchised service areas, under the new
functionally, or operationally, separated industry structure, separate
companies, or separate functional/operational components of companies, perform
the generation, merchant, transmission and distribution functions, with the goal
of fostering competition in the generation sector.
Among other things, these structural changes have resulted in the
rapid development of wholesale markets through which load-serving utilities,
retail aggregators, and individual retail customers are able to obtain needed
electricity products. Also, there has been significant growth in the volume of
trading in the wholesale electricity market, from 1.8 million MWh in the first
quarter of 1995 to 513 million MWh in the second quarter of 1998.(35) Actual
separation of utility generation and transmission functions has resulted from
widespread divestiture of generating assets, in some cases required by state
legislatures or state regulatory commissions. As reported in the RTO NOPR,
since August 1997 approximately 50,000 MW of utility generating capacity has
been sold, or is under contract to be sold, and an additional 30,000 MW is
currently for sale; this represents more than 10 percent of all generating
capacity in the United States. FERC reports that 27 utilities have sold all or
some of their generating assets and seven others have assets for sale.
Finally, many state commissions and legislatures have implemented or
are considering open access at the retail level. As of October 1, 1999,
twenty-four states have enacted policies, either through legislation or
administrative action, requiring utilities to offer open access to retail
customers. Where open retail access is provided, retail customers have the
ability to "shop" for their electric power from a power supplier other than
their traditional distribution utility. The distributor is obligated to deliver
the third party power supplies to the customer.
In the early years of the Act, the Commission construed the
integration standard to preclude significant geographic expansion by holding
company systems. However, the Commission has acknowledged that the Act must
"keep pace with changing economic and regulatory climates.".(36) Thus, the
Commission has attempted to "respond flexibly to the legislative, regulatory,
and technological changes that are transforming the structure and shape of the
utility industry." The 1995 Report states that
The statute recognizes that the application of the integration standards must
be able to adjust in response to changes in "the state of the art." [T]he
Division believes the SEC must respond realistically to the changes in the
utility industry and interpret more flexibly each piece of the integration
equation.(37)
The integration model presented herein represents the state of the utility
industry in 1999, and accordingly should elicit the flexible and realistic
response described in the 1995 Report.
- -----------------------
(35) RTO NOPR at 33,690.
(36) Union Elec. Co., HCAR No. 18368, at note 52 (April 10, 1974), quoted in
----------------
Consolidated Natural Gas Co., HCAR No. 35-26512 (April 30, 1996).
------------------------------
(37) 1995 Staff Report at 66.
<PAGE>
(b) Restructuring of NEPOOL and NYPP into Open, Competitive and
Coordinated Markets
Both NYSEG and Central Maine Power are members of power pools in which
transmission-owning members have turned over operational control of their
transmission assets to ISOs. As indicated earlier, NYSEG is a member of the
NYPP and has committed to transfer control over its transmission facilities to
the NYISO; Central Maine Power is a member of NEPOOL and has transferred control
over its transmission facilities to ISO-NE. As noted by the FERC in its RTO
NOPR, the NYISO and ISO-NE were established on the platform of existing tight
power pools following FERC's encouragement in Order No. 888. NYISO was formed
based upon the NYPP and ISO-NE was formed based upon NEPOOL.
The two ISOs administer competitive, bid-based markets for electric
energy and other electric power products, provide non-discriminatory
transmission service at a single, embedded cost-based rate, and facilitate
transmission planning and expansion on a regional basis. NYISO and ISO-NE are
contiguous along a 500-mile border and are interconnected by eight different
interties with aggregate transfer capability of 1,600 to 2,300 MW, depending on
direction and system conditions. Trade between the two ISOs is significant.
Scheduled energy transfers between NEPOOL and New York were approximately
7,100,000 MWh per year for the three years ending December 31, 1998. This is
equivalent to the transfer of between NYISO and ISO-NE, of 1,707 MW during every
peak hour of the year.(38) As discussed below, the eight existing interties
between NYPP and NEPOOL provide significant transfer capability between these
control areas.
The two ISOs engage in regular coordinated activities to ensure
reliable interregional operations and to encourage robust competitive markets by
simplifying interregional transactions.(39) Both ISOs operate as non-profit
organizations and include investor-owned utility ("IOU") and non-IOU members,
and both operate centralized power markets. In addition, both perform
congestion management to free up transmission capacity for the most economic
uses of the system. Through these activities, the NYISO and ISO-NE have largely
accomplished the integration function that is the legislative goal of Sections
2(A)(29)(A) and 10(c)(2) and 11(b) of the Act. Furthermore, in their
application to the FERC under Section 203 of the Federal Power Act, the parties
have committed to reduce the effects of rate pancaking between the NYISO and
ISO-NE for transactions that use both NYSEG's and Central Maine Power's
transmission systems. As a result, the Merger will further enhance integration
between the NYISO and ISO-NE with respect to NYSEG and Central Maine Power
beyond that which has already been accomplished by the coordinated activities of
the two ISOs.
- -----------------------
(38) The peak hours of the year for electricity demand are the 16 "on peak"
hours Monday through Friday
(39) For example, when one of the two control areas experiences energy supply or
reserve shortages, the other control area will provide as much energy as
possible to assist its neighbor. On a routine basis, the control areas
exchange energy for economic efficiency reasons. NYPP, NEPOOL and members
of both pools, including NYSEG and Central Maine Power, participate in
joint pool and regional transmission planning and reliability studies.
<PAGE>
Finally, all of the states in which transmission-owning utility members of
the NYISO and ISO-NE are located, with the exception of Vermont, have
established requirements for retail choice. These state initiatives frequently
include a requirement that the utilities divest some or all of their generating
assets. This is designed to mitigate or eliminate the utilities' generation
market power, thus making generation markets more competitive. Central Maine
Power, upon completion of divestiture of its generating assets and power
exchange contracts, will be solely a "wires" company that does not provide, and
has no obligation to provide, electric power to customers.
(i) The NYPP and NYISO
Opinion No. 96-12,(40) issued by the New York Public Service Commission
("NYPSC"), sets forth the vision and goals for the future electric regulatory
regime. The NYPSC's stated vision includes the following factors: (1)
effective competition in the generation and energy services sectors; (2) reduced
prices resulting in improved economic development for New York as a whole; (3)
increased consumer choice of supplier and service company; (4) a system operator
that treats all participants fairly and ensures reliable service; (5) a provider
of last resort for all consumers and the continuation of a means to fund
necessary public policy programs; (6) ample and accurate information for
consumers to use in making informed decisions; and (7) the availability of
information that permits adequate oversight of the market to ensure its fair
operation.(41)
The NYPSC directed NYSEG (and four other electric utilities) to submit a
rate and restructuring plan consistent with the NYPSC's policy and vision for
increased competition. These plans were to address, at a minimum: (1) the
structure of the utility, both in the short and long term, including a
description of how that structure complies with the NYPSC's vision and, in cases
where divestiture is not proposed, effective mechanisms that adequately address
resulting market power concerns; (2) a schedule for the introduction of retail
access to all of the utility's customers, and a set of unbundled tariffs that is
consistent with the retail access program; (3) a rate plan to be effective for a
significant portion of the transition; and (4) numerous other issues relating to
strandable costs, load pockets, energy services and public policy costs.(42) On
October 9, 1997, NYSEG filed its plan in the form of an "Agreement Concerning
the Competitive Rate and Restructuring Plan" (the "Agreement"). By orders
issued January 27, 1998 and March 5, 1998, the NYPSC approved the Agreement with
modifications.(43)
The Agreement provides for the continued operation of NYSEG in a
holding company structure and the formation of a competitive generating company
to facilitate a subsequent divestiture of generation assets, and established a
five-year period (the "Price Cap Period"), beginning March 3, 1998, during which
NYSEG will reduce its retail rates. In addition, NYSEG committed to make retail
access available in phases, beginning on August 1, 1999. Retail access became
available to all industrial, commercial, public authority, and residential
customers taking service at standard retail rates. NYSEG also agreed to
unbundle its retail rates over the five year Price Cap period.
- -----------------------
(40) Case 96-E-0952 - In the Matter of Competitive Opportunities Regarding
-------------------------------------------------------
Electric Service, Opinion No. 96-12, issued May 20, 1996.
-----------------
(41) Id. at 24.
--
(42) Id. at 75-76, 90.
--
(43) Opinion No. 96-12, May 20, 1996, Case 94-E-0952.
<PAGE>
NYSEG also committed to divest its coal-fired generation plants and agreed
to sell its interest in the NM2. That transaction is expected to close in the
second quarter of 2000. NYSEG agreed to be the provider of last resort during
the Price Cap Period, subject to change by the NYPSC. As authorized by FERC
order,(44) NYSEG's generating company affiliate, NGE Generation, Inc., sold its
50% interest in the 1,884 MW Homer City coal plant to an affiliate of Edison
Mission Energy Co. NGE Generation sold six remaining coal units, representing
1,334 MW of capacity, to affiliates of the AES Corporation.(45) NYSEG
subsequently entered into a contract to sell its 18% share of the NM2,
representing 205 MW, to AmerGen. The only generation assets or contracts which
will remain after that sale are NYSEG's hydroelectric projects, amounting to 62
MW, its NUG contracts and the contracts pursuant to which NYSEG purchases power
from the New York Power Authority. In sum, NYSEG has completed divestiture of
all of its fossil-fired generation, amounting to approximately 2,500 MW, and is
functioning almost exclusively as a transmission/distribution company engaged
exclusively in transmitting electricity from unaffiliated producers to wholesale
and retail customers, located both within New York State and in adjacent states.
On January 31, 1997, pursuant to the NYPSC's directive, the
transmission-owning Member Systems of the NYPP(46) filed a proposal with the
FERC to establish a fully competitive electric market in New York by forming an
ISO and a power exchange. The Member Systems also proposed a joint Open Access
Transmission Tariff ("OATT") to be administered by the ISO. Under this
proposal, operation of the combined transmission systems of the Member Systems
will be turned over to the NYISO, the governance structure of which ensures the
independence of the NYISO board. On December 19, 1997, the Member Systems
submitted a supplemental filing proposing the establishment of an hourly spot
energy market, the implementation of congestion pricing for transmission
services, the creation of transmission congestion contracts and markets for
ancillary services. The Member Systems also sought authorization to engage in
market-based rates for sales of energy into the NYISO administered spot market.
On June 30, 1998, FERC conditionally approved the Member Systems' proposal to
establish the NYISO.(47) Subsequently, on January 27, 1999, FERC conditionally
accepted the NYISO OATT and related market rules, and authorized market-based
rates for energy sales by the Member Systems into the NYISO administered spot
market.(48) The NYISO has now satisfied the conditions under FERC's orders and
is scheduled to become operational by no later than January 2000.
- -----------------------
(44) New York State Electric & Gas Corp., et al., 86 FERC 61,020 (1999).
-------------------------------------------------
(45) New York State Electric & Gas Corp., et al., 86 FERC 61,020 (1999).
-------------------------------------------------
(46) Central Hudson Gas & Electric Corp. ("Central Hudson"), Consolidated
Edison Co. of New York, Inc. ("Con Ed"), Long Island Lighting Co.
("LILCO"), NYSEG, Niagara Mohawk Power Corp. ("Niagara Mohawk"), Orange and
Rockland Utilities, Inc. ("O&R"), Rochester Gas and Electric Corp.
("RG&E"), and NYPA.
(47) Central Hudson Gas & Electric Co., et al., 83 FERC 61,352 (1998).
----------------------------------------------
(48) Central Hudson Gas & Electric Co., et al, 86 FERC 61,062 (1999).
----------------------------------------------
<PAGE>
The establishment of the NYISO and its concomitant assumption of
operational control of the bulk power transmission system in New York State,
will ensure that all participants in the newly-established competitive market
have access to the transmission system on an open and non-discriminatory basis.
The creation of a competitive market for electricity, coordinated and
administered by the NYISO, will ensure that all sellers and purchasers are able
to use voluntary bids to create a market of energy with substantial liquidity
and to allow the ISO to optimize the efficiency of the spot market for
electricity. The implementation of locational based marginal pricing for
electricity sales and transmission service will ensure that power sold in the
spot market is priced on an economically sound basis, and that the price paid
for transmission service reflects the true economic cost of using the combined
Member Systems' transmission systems.
Finally, in accordance with the requirements of FERC Order No. 888
governing "tight" power pools, transmission customers transmitting power (i)
within New York State, (ii) out of New York State, (iii) into New York State, or
(iv) through New York State, pay only one transmission charge under a "license
plate" rate approach. This is in contrast to the traditional "pancaked" rate
approach where the customer paid a separate transmission charge for the use of
each utility's system. Under the "license plate" approach, only the
transmission charge of the utility system to which power is delivered, or which
is the point of export from the NYISO, is assessed. The elimination of pancaked
transmission rates greatly reduces the cost of transmitting electricity which,
in turn, increases the competition among suppliers to serve wholesale and retail
customers and thus reduces prices.
In summary, the establishment of the NYISO creates a competitive
electricity market in which every generation and every reseller of such power,
can participate in a competitive market. The NYISO administers a bid-based
power sales system. Each day, power from sellers submitting the lowest bid will
be selected to serve the aggregate customer load that participates in the
market. The bid approach differs from traditional "economic dispatch" of
generation only in that the seller's offered bid price, rather than its
"cost-of-service," determines the rank in which it is selected to meet load. In
the restructured NYPP and NYISO, every transmission system under the control of
the NYISO will be used to transmit power to meet load from the most competitive
suppliers, whether in state or out-of-state, including to, or through, NYSEG's
and Central Maine Power's systems. Each component of the restructured functions
will be part of an optimally integrated system. In other words, there are no
artificial constraints or electrically isolated subsystems or areas that are not
included in the larger, optimized system.
Consistent with the terms of its OATT, when the NYISO becomes
operational, it will also have the responsibility to facilitate transmission
capacity additions to alleviate transmission constraints which occur during
periods of high demand. As a result, through the creation of a workably
competitive market structure and the "invisible hand" of supply and demand, the
operations of the NYISO establish a fully integrated system for the generation,
transmission and distribution by participants in the markets served by the
NYISO. As discussed below, because of the strong interconnections between
NYPP/NYISO and NEPOOL/ISO-NE, market participants in NEPOOL and ISO-NE are able,
merely by using the Internet-based OASIS, to sell to, or purchase, from buyers
or sellers, respectively, into the NYPP/NYISO and to reserve transmission rights
to consummate such transactions, including transactions to, or through, NYSEG's
and Central Maine Power's systems.
<PAGE>
(ii) NEPOOL and ISO-NE
On December 31, 1996, NEPOOL Members filed a comprehensive proposal to
comply with FERC Order No. 888 and to restructure NEPOOL. Among the key
elements of the NEPOOL filing were (1) the formation of ISO-NE, an independent
system operator that would assume operational control of NEPOOL Members'
high-voltage pool-related transmission facilities, (2) a NEPOOL OATT which
replaced "pancaked" rates with a single transmission rate under the "license
plate" approach, and later transactions to a single pool-wide "postage stamp"
that rate initially incorporates features of (3) the creation of a power
exchange, and (4) authorization for participants in NEPOOL to charge
market-based rates for power and ancillary services. FERC conditionally approved
the filing and required further changes. As required, NEPOOL adopted the FERC's
pro forma tariff policies regarding open admission to NEPOOL, with a
modification, concerning the obligations of transmission utilities to determine
the need for new transmission facilities or upgrades of the NEPOOL transmission
system.(49)
Under the restructured NEPOOL, any "eligible customer" under the FERC's pro
forma tariff may, upon compliance with the applicable requirements, become a
member of NEPOOL.(50) A member of NEPOOL may participate fully in the
competitive, integrated market including NEPOOL and adjacent areas connected by
transmission. Operational control over all "Pool Transmission Facilities"
("NEPOOL PTF")(51) has been transferred to ISO-NE, and transmission anywhere on
the integrated NEPOOL PTF network is provided under the ISO-NE administered
OATT. In compliance with Order No. 888, NEPOOL provides for transmission
service to any retail or wholesale customer located within the NEPOOL area, or
service "through" the NEPOOL grid, to an interconnected utility at a single,
non-pancaked transmission charge.(52) Thus, transmission from any point on the
NEPOOL PTF grid to another control area, such as the NYISO, is subject to only a
single transmission charge, irrespective of the number of individual utility
transmission systems used to transmit the power to the New York border.
Moreover, under the NEPOOL OATT, retail and wholesale customers are responsible
for payment of transmission charges for use of the PTF. Irrespective of how
many NEPOOL Members' transmission systems are used, there are no additional
charges for use of PTF. Thus, there is no additional charge for power imported
from, for example, the NYISO and delivered to a customer on the NEPOOL PTF
system.
NEPOOL and ISO-NE presently operate and administer a bid-based
competitive market for electricity, in which sellers submit bids for any of
seven electric power products and services: energy, ten minute spinning
reserve, automatic generation control, ten minute non-spinning reserve, thirty
minute operating reserve, operating capability, and installed capability. Based
on these bids and on rules reflecting system conditions and constraints, NEPOOL
determines which sellers will be selected to meet the aggregate load and
establishes the market clearing price for those products.
- -----------------------
(49) New England Power Pool, et al., 83 FERC at 61,045 (1998).
-----------------------------------
(50) FERC defines an "eligible customer" as: (i) Any electric utility (including
the Transmission Provider and any power marketer), federal power marketing
agency, or any person generating electric energy for sale for resale.
Electric energy sold or produced by such entity may be electric energy
produced in the United States, Canada or Mexico. However, with respect to
transmission service that the FERC is prohibited from ordering by Section
212(h) of the Federal Power Act, such entity is eligible only if the
service is provided pursuant to a state requirement that the Transmission
Provider offer the unbundled transmission service, or pursuant to a
voluntary offer of such service by the Transmission Provider, (ii) any
retail customer taking unbundled transmission service pursuant to a state
requirement that the Transmission Provider offer the transmission service,
or pursuant to a voluntary offer of such service by the Transmission
Provider, is an Eligible Customer under the Tariff.
(51) The NEPOOL PTFs, generally transmission facilities rated 69kV and above,
constitute the bulk transmission system operated by ISO-NE.
(52) The Member Systems of NEPOOL offer service over their non-NEPOOL PTFs,
i.e., non-bulk power transmission facilities that remain under the
---
operational control of individual utilities, under Local OATTs administered
by the individual member systems.
<PAGE>
Based on its finding that no market participant in NEPOOL has market power,
the FERC has authorized participants in the NEPOOL market to charge competitive,
market-based rates, which are reflected in sellers' bids. These bids, in turn,
are subject to competitive pressure which prevents excessive proposals. In
addition, ISO-NE monitors the market and identifies patterns of anomalous
conduct, particularly withholding of supply, to ensure the proper functioning of
the market.
Under a 1997 State of Maine law restructuring electric utilities in
the State of Maine, Central Maine Power has divested all of its non-nuclear
generating assets. On April 7, 1999, Central Maine Power completed the sale of
its fossil, hydroelectric and biomass generating assets to an affiliate of FPL
Group, Inc. Central Maine Power recently announced the sale of its 4 percent
ownership share in Vermont Yankee to AmerGen, and is in the process of selling
its entitlements to energy from its 2.5 percent interest in Millstone 3 and its
purchased-power contracts with non-utility generators.(53)
In summary, under the restructured NEPOOL and ISO-NE, the high voltage
grids of each transmission-owning utility in New England are combined (as they
were under the prior NEPOOL Agreement) to form a single integrated transmission
system. In contrast to the prior NEPOOL structure, which enabled only utility
members to participate, the restructured NEPOOL allows any seller or buyer to
obtain nondiscriminatory access to the fully integrated NEPOOL transmission
system. Power sellers and purchasers can use this entire system by paying a
single "poolwide" rate, to transmit power through and out of the NEPOOL system,
to a retail or wholesale customer within NEPOOL, or as part of a sale to or
purchase from one of the NEPOOL competitive markets for power described above.
Through this open, transparent structure, every generator located within NEPOOL
(or that can transmit its power to NEPOOL's interfaces at its border) is able to
transmit power to any load within NEPOOL, or, through an interface, to load
outside of NEPOOL, including in NYPP. Included in this category of transactions
are transmission arrangements over the systems of Central Maine Power and NYSEG.
By proposing, following the Merger, to reduce transmission charges for certain
such transactions, Central Maine Power and NYSEG would increase the economic
opportunities for such transactions.
(iii) Coordination between ISO-NE and NYISO
As demonstrated below, NYSEG and Central Maine Power are actively engaged,
and, if the Merger is approved, will be increasingly engaged, in coordinated
activities. These activities include their membership in the NYISO and ISO-NE,
the strong interties, active trading, and coordinated activities of these ISOs,
the active participation by their representatives in inter-ISO working groups,
and their participation in the NPCC Pursuant to the above-cited precedent,
these coordinated activities provide an additional basis for finding that the
Merger satisfies the integration standard.
- -----------------------
(53) Elsewhere in New England, full customer choice began in Massachusetts on
March 1, 1998; several Massachusetts utilities have divested generation
assets. In Connecticut, as of January 1, 2000, up to 35 percent of peak
load of each rate class in certain municipalities may choose their
electric suppliers; there will be full customer choice in Connecticut by
July 1, 2000. In New Hampshire, government officials expect to begin
customer choice in early 2000. In Rhode Island, customer choice will
occur within three months after retail access becomes available to 40
percent of customers (measured by energy sales) in New England. Vermont
has not yet adopted customer choice.
<PAGE>
(a) Interface transfer capacity
As demonstrated by the Franchise Area Map of Major Utilities in the
Northeast attached as Exhibit E-1, NYISO and ISO-NE are adjacent along the
entire New York State/Vermont/Massachusetts/Connecticut border, which extends
from Canada to the Long Island Sound. The ISOs are interconnected through eight
separate interties: four in Vermont, one in Massachusetts, and three in
Connecticut (including the undersea Long Island Sound Cable). These interties,
referred to as the New York/NEPOOL Interface, consist of (1) a 345 kilovolt
("kV") intertie between Connecticut Power & Light ("CP&L") in NEPOOL and ConEd
in NYPP; (2) a 345 kV intertie between Massachusetts Electric Co. in NEPOOL and
Niagara Mohawk in NYPP; (3) a 230 kV intertie between the New England Electric
System in NEPOOL and Niagara Mohawk in NYPP; (4) a 115 kV intertie between
Vermont Electric Power Company ("Vermont Electric") in NEPOOL and the NYPA in
NYPP; (5) a 115 kV intertie between Vermont Electric in NEPOOL and Niagara
Mohawk in NYPP; (6) an additional 115 kV intertie between Vermont Electric in
NEPOOL and Niagara Mohawk in NYPP; (7) a 69 kV intertie between CP&L in NEPOOL
and Central Hudson in NYPP; and (8) a 138 kV intertie between CP&L in NEPOOL and
LIPA in NYPP.
The New York/NEPOOL Interface has aggregate transfer capacity -- between
1,600 to 2,300 MW, depending on direction and system conditions.(54) As noted
previously, transfers between NEPOOL and NYPP averaged 7,100,000 MWh per year
over the three years from 1995 to 1998, equal to an average of 1,707 MW of
transfers for every peak hour of the year, and to an average of 810.5 MW of
transfers for all hours of the year.(55) As new generation is added in Maine,
transfer capability increases, and NYSEG and Central Maine Power implement their
transmission pricing proposal, transfers between NYPP and NEPOOL are expected to
increase significantly.
Vermont Electric has proposed to expand the Interface capacity by
constructing a new 230 kV transmission line under Lake Champlain interconnecting
to the NYPA system, which would add 400-500 MW of transfer capability. In
addition to transmission-owning utilities in NYPP and NEPOOL, new entrants have
announced plans to add significant new transmission facilities between NYISO and
ISO-NE. For example, TransEnergie U.S. LTD., a subsidiary of Hydro-Quebec, has
submitted an application to the FERC seeking rate approvals for a high voltage
direct current ("HVDC") transmission interconnection, via 26 miles of cable
underneath Long Island Sound, that would connect the United Illuminating
Company's 345 kV system with LIPA's 138 kV system.(56) This project would
provide fully controllable, bi-directional transfer capability of approximately
600 MW between the control areas of the NYISO and ISO-NE.
(b) Coordination and joint planning by NYSEG and Central
Maine Power through the NYISO and ISO-NE
- -----------------------
(54) Prior to its divestiture of generating assets, the aggregate capacity of
all of NYSEG's fossil generation was 2,366 MW, and Central Maine Power's
fossil, hydroelectric and biomass generation represented approximately
1,070 MW. Thus the existing NYPP/NEPOOL Interface is capable of
transferring virtually all of the power output of NYSEG's divested fossil
plants to Central Maine Power customers, and more than twice the amount
needed for transfers from former Central Maine Power units to NYSEG
customers.
(55) Peak hours are 16 hours Monday for five days a week.
(56) Petition of TransEnergie U.S. LTD. For Order Accepting Tariff For
Transmission Interconnector and Granting Related Authorizations and
Waivers, TransEnergie U.S. LTD., ER00-1-000 (Oct. 1, 1999).
---------------------
<PAGE>
In applying the integration standard, the Commission looks beyond simply
the coordination of the generation and transmission within a system to the
coordination of other activities.(57) In that regard, on August 9, 1999, ISO-NE
and NYISO entered into a memorandum of understanding ("MOU"), in which, based on
their recognition that better coordination among these ISOs "would result in
more robust, competitive markets and facilitate interregional monitoring." The
ISOs agreed to:
Place a high priority on studying the feasibility of increasing intertie
capacity;
Identify and address market interface issues to facilitate broader
competitive markets;
Encourage market participants and others to contribute to the process of
improving competition and interregional coordination, and
Require staff of the ISOs to report periodically to the ISO CEOs, market
participants and other constituencies on the status and progress of their joint
interregional coordination activities.
The ISOs have established four joint working groups to carry out the
goals of the MOU. The Operations Working Group will develop and implement
procedures and practices which maximize the efficiency of markets while
protecting bulk power system reliability and security. Among other things, this
group will implement uniform procedures for confirming transactions and
schedules between control areas and will establish a uniform procedure for
administering dispatchable contracts.
The Planning Working Group is charged with enhancing the overall
coordination of reliability planning among the three ISOs. It will establish
protocols for coordinating planning activities between the ISOs; establish
technical processes to strengthen coordination between the ISOs' planning and
assessment procedures; and investigate the feasibility of increasing inter-tie
capacity.
The Business Practices Working Group is charged with furthering the
seamless interfaces between the ISOs, minimizing the potential for contract
curtailments, and identifying business practices that promote market
effectiveness and efficiency. It will identify rules or practices that need to
be addressed to enhance seamless markets; develop guidelines to mitigate the
need for Transmission Load Relief by identifying and coordinating regional
redispatch opportunities, and identify and provide consistent information
required to support competitive markets. Finally, the Public Information
Working Group will seek to optimize the information available to market
participants to facilitate multi-regional trading and will focus on using
information technologies to create synergies within the ISOs' on-line trading
systems.
- -----------------------
(57) See, e.g., General Public Utilities Corp., HCAR No. 13116 (Mar. 2, 1956)
--- ---- ------------------------------
(coordination of maintenance and construction requirements); Middle South
-------------
Utilities, Inc., HCAR No. 11782 (March 20, 1953), petition to reopen
---------------
denied, HCAR 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 accomplished
------------
through an operating committee which 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); North American Company, HCAR No. 10320 (Dec. 28, 1950)
-------
(coordination of future power demand, sharing of extensive experience with
regard to engineering and other operating problems, and furnishing of
financial aid to the company being acquired are elements of integration).
(58)
<PAGE>
Also, representatives of Central Maine Power and NYSEG presently serve as
members of working groups, and committees that address, on a continuing basis,
the issues of coordination between ISO-NE and NYISO. Following the CMP
Group Merger, these representatives will continue to be engaged in these
activities. As representatives of subsidiaries of the same company, Energy East,
NYSEG and Central Maine Power will have an increased focus on the development
and implementation of inter-pool activities, such as enhanced inter-pool
transmission, "loop-flow" coordination, reserve sharing, maximization of
interpool trades, and other activities which enhance the benefits of economic
and efficient coordination for the Energy East electric companies.
Finally, both NYSEG and Central Maine Power are members of the
Northeast Power Coordinating Council ("NPCC"). NPCC was established in 1966 to
promote the reliability of the international interconnected bulk electric
systems in Northeastern North America. The NPCC establishes reliability
criteria, coordinates system design and operations, and regularly assesses and
assures compliance with such reliability criteria. The NPCC Membership
Agreement was modified in November 1998 to provide for open, inclusive
membership and fair and non-discriminatory governance. The NPCC task forces
include the Task Force on Coordination of Planning and the Task Force on
Coordination of Operations, both of which are focused on the enhancement of
coordination between members of the NPCC, including NYSEG and Central Maine
Power.
(iv) Integrating effects of NYISO and ISO-NE Transmission Tariffs
With the introduction of non-pancaked transmission charges within the
NYISO and ISO-NE control areas, the historic pattern of appreciable energy
exchanges between the New York and NEPOOL control areas is likely to increase.
This is due to a number of factors, including the elimination of pancaked rates
in the two ISOs; the elimination of pancaked losses; the ease of conducting
transactions over the two ISOs' OASIS sites; the active marketing efforts by the
new generating capacity owners and marketers; the expected construction of new
so-called "merchant plant" generating capacity to serve distant loads; and the
planned increase in New York-NEPOOL interface capacity. The old system of
pancaking rates made transactions using several transmission systems less
economic. Moreover, the old system of multiple transmission providers and OASIS
sites administered by individual utilities, rather than ISOs, was
administratively burdensome. The combination of increased centralized control
within NEPOOL and the New York control areas, decreased pancaking, one-stop
shopping for transmission service, and the direct interconnection of the two
control area operators that administer service over the NYSEG and Central Maine
Power systems will enhance the integration of NYSEG and Central Maine Power.
(v) NYSEG's and Central Maine Power's transmission pricing proposal will
provide additional integration
<PAGE>
As discussed above, most owners of generating facilities in New York
and New England today do not own transmission or distribution. Under the terms
of the ISO-NE and NYISO transmission tariffs, these companies can reserve
transmission capacity, including, if necessary, across the NEPOOL-NYPP
Interface, and thereby access markets anywhere within NEPOOL or NYPP. Once the
NYISO becomes operational, it will have control over all transmission facilities
in that State. In New England, in accordance with existing NEPOOL policies,
NEPOOL PTFs are controlled by ISO-NE, while control over lower voltage and other
non-NEPOOL PTF facilities is retained by their utility owner. Access over
non-PTF transmission facilities is available pursuant to each individual
utility's open access transmission tariff. Central Maine Power, for example,
provides service over its non-PTF, consisting primarily of 34.5kV facilities,
under its Local OATT.
As part of their filing with the FERC under Section 203 of the Federal
Power Act, NYSEG and Central Maine Power have developed a proposal that will
further integrate their two transmission systems without disrupting the current
operations of the NYISO and ISO-NE or the carefully constructed ISO tariff
mechanisms that are already in place. To the extent that NYSEG and Central
Maine Power are able to assess charges for transactions that use both of their
transmission systems, the applicants have committed to eliminate the effects of
one of the two system charges, thereby reducing "pancaking" effects for those
transactions. Although control of all New England utilities' PTF, is under the
operational control of ISO-NE, New England utilities, including Central Maine
Power, directly provide transmission service over their non-transferred
facilities, i.e., their non-PTF system, under the terms of their individual
----
OATTs. In the FERC application, the applicants committed that, upon
consummation of the CMP Group Merger, they would eliminate the local
point-to-point transmission charge under Central Maine Power's OATT in
situations where a generator could be assessed charges by both Central Maine
Power and NYSEG with respect to wheeling transactions over both the CMP and
NYSEG systems. A more detailed explanation of the proposal is contained in the
FERC application including the joint affidavit of Messrs. Garwood and McKinney.
See Exhibit D-1. Reducing the charges for these types of transmission
arrangements will increase the quantity of economic transactions between sellers
and purchasers with access to the NYSEG and Central Maine Power systems, thus
increasing the degree of integration between these companies. At present, more
than 5,000 MW of new generation capacity has been proposed for development in
Maine, and approximately 1,700 MW of new "merchant" plant capacity is currently
under construction in Maine. Reductions in the cost of transmitting the output
of these plants to markets in New York will inevitably result in greater sales
and increased integration between these two systems and increasing power flows
to and through the two systems.
<PAGE>
A more detailed explanation of the proposal is contained in the FERC application
including the joint affidavit of Messrs. Garwood and McKinney. See Exhibit D-1.
Reducing the charges for these types of transmission arrangements will increase
the quantity of economic transactions between sellers and purchasers with access
to the NYSEG and Central Maine Power systems, thus increasing the degree of
integration between these companies. At present, more than 5,000 MW of new
generation capacity has been proposed for development in Maine, and
approximately 2,000 MW of new "merchant" plant capacity is currently under
construction in Maine. Reductions in the cost of transmitting the output of
these plants to markets in New York will inevitably result in greater sales and
increased integration between these two systems and increasing power flows to
and through the two systems.
(c) Statutory Standards For Electric Integration Will Be
Satisfied As demonstrated below, the Merger satisfies all four of the previously
cited standards under the integration requirement.
(i) Physical interconnection or capability of physical
interconnection
In applying the requirement that the electric generation and/or
transmission and/or distribution facilities comprising the system be "physically
interconnected or capable of physical interconnection," the Commission
historically focused on physical interconnection through facilities that the
parties owned or, by contract, controlled. (58) To date, the Commission
______________________
58. See, e.g., Northeast Utilities, HCAR No. 35-25221 (Dec. 21, 1990)
--- ---- --------------------
("Northeast Utilities") at note 85, supplemented, HCAR No. 25273 (March 15,
1991), aff'd sub nom. City of Holyoke v. SEC, 972 F.2d 358 (D.C. Cir. 1992)
--------------- -----------------------
Northeast had the right to use a Vermont Electric line for ten years, with
automatic two-year extensions, subject to termination upon two years notice, in
order to provide power to a Northeast affiliate); Centerior Energy Corp., HCAR
----------------------
No. 35-24073 (April 29, 1986) (Cleveland Electric Illuminating Company and
Toledo Edison Company were connected by a line owned by Ohio Edison. All three
were members of the Central Area Power Coordination Group ("CAPCO"). The line
connecting Cleveland Electric, Ohio Edison and Toledo was a CAPCO line with
segments owned by each of the three names utilities.); Cities Service Power &
----------------------
Light Co., 14 S.E.C. 28, 53, at note 44 (1943) (two companies in the same
- ----------
holding company system were found to be interconnected where energy was
transmitted between two separated parts of the system over a transmission line
owned by the United States Bureau of Reclamation, under an arrangement which
afforded the system the privilege of using the line).
<PAGE>
has determined that the interconnection requirement is met through memberships
in "tight" power pools and ISOs. (59) In 1992, for example, the Commission
approved the merger of UNITIL Corporation with Fitchburg Gas and Electric Light
Company, based on their common membership in NEPOOL (60), a regional power pool
that was the basis for the FERC approved ISO-NE and associated power exchange.
UNITIL and Fitchburg were not connected through transmission lines that they
owned. Rather, as the Commission noted in its order:
[T]he Companies are indirectly interconnected through NEPOOL-designated
transmission facilities ("PTF") and other nonaffiliate transmission
facilities pursuant to the NEPOOL Agreement and other separate agreements
with nonaffiliate companies. (61)
With respect to the "other separate agreements with nonaffiliate
companies" described above, the Commission explained that Fitchburg obtained
primary transmission service from New England Power Company ("NEPCO") under the
NEPOOL Agreement and through NEPCO's FERC Tariff No. 3, which provided for
______________________
59. See, e.g., UNITIL Corp., supra (interconnection through NEPOOL), and
--- ---- ------------- -----
Conectiv, Inc. HCAR No. 35-26832 (Feb. 25, 1998) (interconnection through PJM,
- ---------------
Inc.). See also Yankee Atomic Elec. Co., 41 S.E.C. 552, 565 (1955) (authorizing
--------------------------------
various New England companies to acquire interests in a commonly-owned nuclear
power company and finding the interconnection requirement met because the New
England transmission grid already interconnected the companies).
60. New England Power Pool, 79 FERC 61,374 (1997); New England Power Pool,
---------------------- ----------------------
83 FERC 61,045 (1998).
61. UNITIL Corp. at 1997 SEC LEXIS 1016, at *12.
-------------
<PAGE>
non-firm service. The Commission went on to note that Fitchburg was eligible to
use NEPCO's FERC Tariff No. 4 (62) should Fitchburg and UNITIL Power conduct
more power sales or swaps.
In 1998, based on UNITIL, the Commission found that Delmarva Power &
------
Light Company and Atlantic Energy, Inc. met the physical interconnection
requirements of Section 2(a)(29)(A) through their common membership in PJM
Interconnection, LLC ("PJM"), which was a regional power pool and the first
FERC-approved, operational ISO. (63) In both UNITIL and Conectiv, the Commission
stated that it was not necessary for the applicant to construct an additional
transmission line interconnecting the affected electric utility companies "since
present transmission arrangements provide adequate service." (64)
The NYSEG and Central Maine Power systems satisfy the requirement that
they be "physically interconnected or capable of physical interconnection"
through their respective memberships in NYPP/NYISO and NEPOOL/ISO-NE and
through the interconnections and trading between NYPP/NYISO and NEPOOL/ISO-NE
described above. A finding of interconnection through membership in directly
interconnected tight power pools and ISOs, such as NYPP/NYISO and NEPOOL, where
market participants, including NYSEG and Central Maine Power, are free to and
frequently do engage in interpool transactions, is consistent with Commission
precedent and the Act's integration standards, particularly in light of the
continued evolution of the electric industry.
As discussed above, any person satisfying the minimal Order No. 888
standards to be an eligible customer may directly reserve transmission capacity
______________________
62. Under FERC Tariff No. 4, Fitchburg would receive firm transmission
service. Amendment No. 11 to Form U-1 of UNITIL Corporation, File No. 70-7628,
at 55.
63. Conectiv, Inc., HCAR No. 35-26832 (Feb. 25, 1998) ("Conectiv").
--------------- --------
64. UNITIL Corp., HCAR No. 25524 (1992), citing Electric Energy, Inc., 38
------------- --------------------
S.E.C. 658, 669 (1953) (direct interconnection not required in circumstances
which would have resulted in an uneconomic duplication of transmission
facilities); Conectiv, Inc., HCAR No. 35-26832, at 1998 SEC LEXIS 326, at 29,
--------------
note 27.
<PAGE>
required for a proposed transaction through the NYISO or ISO-NE, or both. If
the customer's request for transmission service cannot be accommodated with
existing transmission capacity or through congestion management procedures,
member utilities under the ISO are obligated to build the necessary transmission
capacity to accommodate the requested transaction under the terms of the ISO's
OATT. Both the NYISO and NE-ISO have extensive planning processes designed to
identify necessary capacity upgrades. The recently signed MOU commits the ISOs
to coordinate their respective planning processes in order to identify and
address market interface issues (such as planning for necessary capacity
additions) with the goal of facilitating broader competitive markets. NYSEG and
Central Maine Power personnel participate extensively in the coordinated
activities of NYISO and ISO-NE and will, after the merger, jointly participate
to achieve benefits for the Energy East System as a whole.
Finally, the above-cited UNITIL and Conectiv holdings are consistent
------ --------
with the recommendation of the 1995 Report that the Commission "adopt a more
flexible interpretation of the geographic and physical integration standards,
with more emphasis on whether an acquisition will be economical and subject to
effective regulation." The 1995 Report further recommended that the Commission
increasingly rely on an acquisition's demonstrated economies and efficiencies,
rather than upon physical interconnection, to meet the integration standard. It
also noted that the Act provides the necessary flexibility for the Commission to
adjust its application of the integration standards in response to changes in
the state of the art, and concluded that it would be a logical extension of
prior orders for the Commission to find that wheeling and other forms of sharing
power (such as reliability councils and proposed regional transmission groups)
also qualify as interconnection. Here, the compliance with this statutory
requirement to keep apace with the industry leads to the conclusion that,
through their participation in highly interconnected and coordinated power
pools, in which access over the interconnected transmission systems of the pool
members is available on an open access, non-discriminatory basis, and in which
there has and will continue to be a significant amount of interpool
transactions, NYSEG and Central Maine Power satisfy the integration standard.
<PAGE>
(ii) Coordination of electric operations
NYSEG and Central Maine Power
---------------------------------
Section 2(a)(29)(a) further requires that the utility assets, under
normal conditions, may be "economically operated as a single interconnected and
coordinated system." The Commission has interpreted this language as requiring
that, in addition to physical interconnection, "the properties [must] be so
connected and operated that there is coordination among all parts, and that
those parts bear an integral operating relationship to each other." (65) The
Commission must find that "the isolated territories are or can be so operated in
conjunction with the remainder of the system that central control is available
for the routing of power within the system, North Am. Co. (66) The Commission
has explained that this language "refers 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." (67) In UNITIL, as the Commission observed that with regard to
------
coordinated operations of an integrated utility system:
Congress did not intend to impose rigid concepts but instead expressly included
flexible considerations to accommodate changes in the electric utility industry.
Thus, the Commission has considered advances in technology and the particular
operating circumstances in applying the integration standards. (68)
______________________
65. UNITIL Corp., at 1992 SEC LEXIS 1016, at *14, note 31, citing Cities
------------- ------
Service Co., 14 S.E.C. at 55.
- -----------
66. 11 S.E.C. 194, 242, aff'd, 133 F.2d 148 (2d Cir. 1943), aff'd on
------ --------
constitutional issues, 327 U.S. 686 (1946).
- ----------------------
67. Id.
---
68. UNITIL Corp., at 1992 SEC LEXIS 1016, at *15, citing Mississippi Valley
------------- -------------------------
Generating Co., 36 S.E.C. 159,186 (1955), cited in Yankee Atomic Elec. Co., 36
- -------------- -------------------------------
S.E.C. at 565.
<PAGE>
The requirement regarding a single interconnected system is intended
to prevent the evils that arise when holding companies are expanded to include
properties the operation of which has no relationship to the other properties,
i.e., to prohibit ownership of properties that are electrically isolated from,
- ----
and not operated in coordination with, other utility properties owned by the
holding company. The opposite of that scenario is the case here.
First, as described above, the transmission facilities of NYSEG and
Central Maine Power are physically interconnected through the ISOs which operate
them, and through the NEPOOL/NYPP Interface, which provides transfer capability
of approximately 2,000 MW for transactions between the two ISOs and the electric
companies in the Energy East System. Transactions between the NYPP and NEPOOL
are frequent, amounting to an average of 7,100,000 MWh for years 1995-1998.
Second, once the NYISO becomes operational (by early 2000), power flows over the
combined transmission systems will be centrally directed by the two ISOs, in
accordance with reservations for transmission use made by transmission users,
i.e., sellers or purchasers seeking to use one or both systems to accomplish
- ---
transactions. Simply by accessing the two ISOs via the Internet, transmission
customers can arrange for seamless transmission on the NYSEG and Central Maine
Power systems, including access through the NEPOOL/NYPP Interface, and thereby
transmit power to either system, or, using "through and out" service, to other
interconnected utilities. Finally, economical operation as an interconnected and
coordinated system is enhanced by the proposal of Energy East and CMP Group to
eliminate duplicative transmission charges for transactions involving the NYSEG
and Central Maine Power systems.
Because access between ISO-NE and NYISO is not restricted by any
artificial barriers, each generator that provides power to the transmission
systems of Central Maine Power or NYSEG, and the transmission and distribution
facilities of those companies over which such power flows, are "so connected and
<PAGE>
operated that there is coordination among all parts, and that those parts bear
an integral operating relationship to the other." (69) Through the economic
incentives of the bid process, and the availability of open access transmission,
the most competitive sources of generation, located within ISO-NE, NYISO, or
other areas able to import to these ISOs, are selected to meet load. Thus, the
historical efficiencies achieved through economic dispatch within NEPOOL and
NYPOOL can be exceeded with the combined resources available in both pools.
The resulting optimization of resource use that occurs through the
combination of the contiguous, mutually-accessible competitive markets in New
York and New England, as enhanced by the elimination of pancaked transmission
rates for transmission facilities controlled by the NYSEG and Central Maine
Power and the joint activities of NYSEG and Central Maine Power in electric
transmission and distribution functions, satisfies the requirement that the
resulting system be capable of being economically operated as a single
integrated and coordinated system.
Further, the companies anticipate that the electric operations of NYSEG and
Central Maine Power after the CMP Group Merger will be further coordinated
through joint purchases of electric transmission and distribution equipment,
participation in a joint task force for transmission planning, development and
usage, and a joint task force on electric distribution issues and emergency
planning and unified Energy East activities and participation on the respective
operating and business committees of NYISO and ISO-NE.
Maine Electric Power Company.
-------------------------------
MEPCo owns and operates a 345-kV transmission interconnection between
Wiscasset, Maine and the Maine-New Brunswick international border at Orington,
Maine, where its lines connect with the portion of the interconnection
constructed in the province of New Brunswick, Canada, by The New Brunswick Power
Corporation. Central Maine Power owns 78.3% of MEPCo's common stock. The
______________________
69. Cities Service Power & Light Co., 14 S.E.C. 28, at 55.
-------------------------------------
<PAGE>
remaining voting stock of MEPCo is owned by two other Maine electric utilities,
Bangor Hydro Electric Company and Maine Public Service Company. MEPCo provides
service over its facilities pursuant to a non-discriminatory FERC approved OATT.
Long-term transmission capacity on MEPCo's facilities is fully reserved. MEPCo
is directly connected to Central Maine Power and the two transmission systems
are fully integrated; as shown above, Central Maine Power will be a fully
integrated component of the new Energy East Electric System. Therefore, MEPCo
satisfies the Act's requirements for integration of electric utility systems.
NORVARCO
--------
NORVARCO holds a 50% general partnership interest in Chester SVC
Partnership, a general partnership which owns a static var compensator, in
Chester, Maine, adjacent to MEPCo's transmission interconnection. Operation of
the static var compensator helps to ensure the reliable interconnection between
NEPOOL and Canadian utilities (New Brunswick Power and Hydro-Quebec), by
providing voltage control on the Brunswick transmission interconnection that
prevents the loss of the MEPCO line that might otherwise occur following the
loss of the Hydro-Quebec transmission interconnection. Following the CMP Group
Merger, NORVARCO would similarly function as a fully integrated component of the
new Energy East Electric System and thus will satisfy the Act's integration
standard.
(iii) Single area or region
The Commission's third requirement for integration is also satisfied. The
Energy East electric system will operate in a single area or region. The
electric system will operate in upstate New York and central and southern Maine
in the northeast region of the United States. Although the service territories
of NYSEG and CMP do not touch or overlap, they are within the same general
region. The Commission has approved a number of similar combinations of
electric utilities. (70)
______________________
70. See, e.g., WPS Resources Corp., HCAR No. 26922 (Sept. 28, 1998).
--- ---- ---------------------
<PAGE>
The Commission has made clear that the "single area or region" requirement
does not mandate that a system's operations be confined to a small geographic
area or a single state. In considering size, the Commission has consistently
found that utility systems spanning multiple states satisfy the single area or
region requirement of the Act. (71)
It should be noted that in the 1995 Report, the Division has stated that
the evaluation of the "single area or region" portion of the integration
requirement "should be madein light of the effect of technological advances on
the ability to transmit electric energy economically over longer distances, and
other developments in the industry, such as brokers and marketers, that affect
the concept of geographic integration." (72) The 1995 Report also recommends
that primacy be given to "demonstrated economies and efficiencies to satisfy the
statutory integration requirements." (73) As set forth in Item 3.C.3, the
Merger will result in numerous economies and efficiencies for the utilities and,
in turn, their customers. Additionally, as discussed above, given the high
level of interpool transactions and ready transmission access between NEPOOL and
NYPP, and the elimination of rate pancaking, the net effect is a regional
northeast U.S. grid, from both an operational and economic standpoint. By virtue
of their common memberships in the highly interactive NYPP and NEPOOL tight
pools, and their respective ISOs, NYSEG and Central Maine Power will be part of
the same region.
______________________
71. See, e.g., Entergy, supra, (approving power system covering portions of
--- ---- --------------
four states): Southern Co., HCAR No. 24579 (Feb. 12, 1988); (approving power
-------------
system covering portions of four states); New Century Energies, Inc., HCAR No.
-------------------------
26748 (Aug. 1, 1997) (approving integrated system covering portions of five
states).
72. 1995 Report at 73.
73. 1995 Report at 73.
<PAGE>
(iv) Not so large as to impair advantages of localized
management, efficient operation, and the effectiveness of regulation
Finally, with respect to the Commission's fourth requirement, the Energy
East system will not be so large as to impair the advantages of localized
management, efficient operations, and the effectiveness of regulation. CNE will
maintain its corporate headquarters in Bridgeport, Connecticut. After the
Merger, Energy East will maintain its principal office in Stamford, Connecticut,
while CMP Group will continue to maintain its corporate headquarters in Augusta,
Maine and CTG Resources will continue to maintain its corporate headquarters in
Hartford, Connecticut. The management of post-Merger Energy East will be drawn
primarily from the existing management of Energy East, Connecticut Energy, CMP
Group, CTG Resources, and their subsidiaries. (74) This structure will preserve
all the benefits of localized management that Energy East, CMP Group and CTG
Resources presently enjoy while simultaneously allowing for the efficiencies and
economies that will derive from the Merger.
Additionally, the post-Merger Energy East system will not impair the
effectiveness of state regulation. NYSEG, CMP Group's and CTG Resources'
utility subsidiaries will continue their separate existence as before and their
utility operations will remain subject to the same regulatory authorities by
which they are presently regulated, namely the NYPSC, MPUC, DPUC, the FERC and
the NRC. Energy East, CMP Group and CTG Resources are working closely with all
agencies to the extent necessary to ensure they are well informed about the
Merger, and the Merger will not be consummated unless all required regulatory
approvals are obtained. Pursuant to the recommendations contained in the 1995
Report this last factor is significant, as the Division stated therein "where
the affected state and local regulators concur, the [Commission] should
interpret the integration standard flexibly to permit non-traditional systems if
______________________
74. The Commission has found that an acquisition does not impair the
advantages of localized management where the new holding company's "management
[would be] drawn from the present management," (Centerior, supra) or where the
--------- -----
acquired company's management would remain substantially intact. (AEP, supra).
--- -----
<PAGE>
the standards of the Act are otherwise met," (75) especially since the Merger
will result in a system similar to the traditional registered holding company
system.
The electric operations of NYSEG and Central Maine Power are coordinated
through joint planning with, and for, NYISO and ISO-NE and joint distribution
activities. Given the close coordination of NYISO and ISO-NE, the area
encompassed should be considered a single area or region and given the
maintenance of corporate headquarters in Connecticut, Maine and New York and
ongoing regulation by various state and federal authorities, there is no
impairment of localized management, efficient operation or effective regulation.
3. Combination of Gas Utility Operations
-----------------------------------------
(a) Section 10(c)(1)
Energy East's acquisition of the gas operations of CMP Group and CTG
Resources, as well as Energy East's retention of NYSEG's, Connecticut Energy's
and Maine Gas Co.'s existing gas operations, is lawful under Section 8 of the
Act and would not be detrimental to the carrying out of Section 11 of the Act.
(i) Section 8
Section 8 of the Act provides that:
[w]henever a State law prohibits, or requires approval or
authorization of, the ownership or operation by a single company of
the utility assets of an electric utility company and a gas utility
company serving substantially the same territory, it shall be unlawful
for a registered holding company, or any subsidiary company thereof
(1) to take any step, without the express approval of the state
commission of such state, which results in its having a direct or
indirect interest in an electric utility company and a gas company
serving substantially the same territory; or (2) if it already has any
such interest, to acquire, without the express approval of the state
commission, any direct or indirect interest in an electric utility
company or gas utility company serving substantially the same
territory as that served by such companies in which it already has an
interest.
______________________
75. 1995 Report at 74.
<PAGE>
<PAGE>
A fair reading of this section indicates that, with the approval of the
relevant state utility commissions, registered holding company systems can
include both integrated electric utility systems and integrated gas utility
systems.
Energy East, as a combination company, is permissible pursuant to the terms
of Section 8 of the Act and is in the public interest. First, the combination
of electric and gas operations in Energy East is lawful under all applicable
state laws and regulations. The Merger will not result in any change in the
provision of gas and electric services of any so-called combination system
within a given state. Energy East, through NYSEG, will continue to provide
electric and gas service in the State of New York and CMP Group, through its
utility subsidiaries, will continue to provide electric service in the State of
Maine. Since New York and Maine both permit combination gas and electric
utilities serving the same area, the Merger does not raise any issue under
Section 8. Moreover, earlier concerns that a holding company such as Energy
East would be able to greatly emphasize one form of energy over the other based
on its own agenda have substantially receded because of the competitive nature
of the energy market, which requires utilities to meet customer demand for
energy in whatever form. Furthermore, state regulators will have sufficient
control over, and are unlikely to approve, a combination company that attempts
to undertake such practices. Indeed, with regard to retail sales of electric
power, Energy East and CMP Group have divested virtually all of their generation
assets, and Central Maine Power has transferred and NYSEG either has transferred
or, as soon as the NYISO becomes operational, will transfer, operational control
of their transmission facilities(76) to an ISO, effectively depriving the
utilities (and their holding companies) of both the ability and the incentive to
favor one form of energy over the other.
______________________
76. As noted above, Central Maine Power has retained control of its
"non-PFT" facilities.
<PAGE>
(ii) Section 11
Even if Section 8 of the Act were not interpreted as generally permitting
the combination of separate gas systems where such combination is approved and
accepted by the relevant state commissions, Sections 10 and 11 of the Act
contain additional provisions that permit the retention by Energy East of its
existing integrated gas system (consisting of the gas operations of NYSEG,
Connecticut Energy and Maine Gas Co.) and the acquisition of the gas operations
of CMP Group and CTG Resources.
Section 10(c)(1) prevents the Commission from approving an acquisition that
"would be detrimental to the carrying out of the provisions of Section 11."
Section 11(b)(1) of the Act generally confines the utility properties of a
registered holding company to a "single integrated public-utility system,"
either gas or electric.
An exception to the requirement of a "single system" is provided in Section
11(b)(1) A-C (the "ABC clauses").(77) A registered holding company may own one
or more additional integrated public utility systems -- i.e., gas as well as
----
electric -- if each system meets the criteria set forth in these clauses. As
discussed below, post-Merger Energy East qualifies under the exception
established pursuant to the ABC clauses to retain the integrated gas system,
comprised of the gas operations of NYSEG, Connecticut Energy, Maine Gas Co. and
CTG Resources.
(b) "ABC" Clauses
Section 11(b)(1) of the Act permits a registered holding company to control
one or more additional integrated public utility systems if:
(A) each of such additional systems cannot be operated as an
independent system without the loss of substantial economies
which can be secured by the retention of control by such holding
company of such system;
______________________
77. See, generally, NIPSCO Industries, Inc., HCAR No. 26975 (Feb. 10, 1999).
--- --------- ----------------------
<PAGE>
(B) all of such additional systems are located in one state, adjoining
states, or a contiguous foreign country; and
(C) the continued combination of such systems under the control of such
holding company is not so large (considering the state of the art
and the area or region affected) as to impair the advantages
of localized management, efficient operation, or the effectiveness
of regulation.
For the reasons set forth below, a divestiture order would be contrary to
the public interest and Energy East therefore requests that the Commission
authorize retention of Energy East's existing gas operations, including
Connecticut Energy's. Furthermore, Energy East requests that the Commission
authorize Energy East's acquisition of the gas operations of CMP Group and CTG
Resources.
In the 1995 Report, the Commission Staff recommended that the Commission
"liberalize its interpretation of the 'ABC' clauses."(78) In its recent
decisions in New Century Energies, Inc.,(79) Conectiv, Inc.,(80) and WPL
----------------------------- --------------- ---
Holdings, Inc.,(81) the Commission applied the ABC clauses to a proposed
- --------------
acquisition by a to-be-registered holding company. The Commission reconsidered
and rejected the implicit requirement, in many of its earlier decisions, of
evidence of a severe, even crippling, effect of divestiture upon the separated
system, stating that this approach is outmoded in the contemporary utility
industry, and explained that as a result of the convergence of the gas and
______________________
78. 1995 Report at 74.
79. New Century Energies, Inc., HCAR No. 26749 (1997)
-----------------------------
80. Conectiv, Inc., HCAR No. 26832 (1998).
---------------
81. WPL Holdings, Inc., HCAR No. 26856 (1998).
--------------------
<PAGE>
electric industries now under way, separation of gas and electric businesses may
cause the separated entities to be weaker competitors than they would be
together, and that this factor operates to compound the loss of economies
represented by increased costs. The above-cited decisions support a favorable
consideration by the Commission of the instant Application/Declaration.
Historically, under its previous narrow interpretation of Section
11(b)(1)(A), as a guide to determining whether lost economies are "substantial,"
the Commission has given consideration to ratios which measure the projected
loss of economies as a percentage of: (1) total gas operating revenues; (2)
total gas expense or "operating revenue deductions;" (3) gross gas income; and
(4) net gas income or net gas utility operating income. Although the Commission
has declined to draw a bright-line numerical test under Section 11(b)(1)(A), it
has indicated that cost increases resulting in a 6.78 percent loss of operating
revenues, a 9.72 percent increase in operating revenue deductions, a 25.44
percent loss of gross income and a 42.46 percent loss of net income would afford
an "impressive basis for finding a loss of substantial economies."(82)
Here, the lost economies that would be experienced if the gas properties of
Energy East (including the Connecticut Energy gas properties), CTG Resources and
CMP Group were to be operated on a stand-alone basis exceed these numbers,
without any increase in benefits to consumers from such divestiture. Attached
to this application at Exhibit J-1 is an "Analysis of the Economic Impact of a
Divestiture of the Gas Operations of Energy East." As shown in Table I-1 of
that analysis, divestiture of the gas business of Energy East into a stand-alone
gas company would result in a 9.6 percent loss of operating revenue, a 10.2
percent increase in operating revenue deductions; a 147.3 percent loss of gross
income, and a 239.3 percent loss of net income. These figures show that the
lost economies associated with the divestiture of Energy East's gas business are
substantial, even under a narrow interpretation of Section 11(b)(1)(A).
It should be noted that lost economies are typically analyzed with respect
to the divestiture of an existing, and hence operationally integrated, utility.
As a result, a large component of such analyses represents lost economies
resulting from the immediate need to replicate services heretofore performed by
the combination company, the loss of economies of scale relating to physical
plant and office space and purchasing, and other factors. In contrast, when
lost economies are assessed in the context of companies which, at present, are
operating as stand-alone entities, the lost economies equal the foregone savings
that would have been realized had the Merger taken place. In the latter case,
______________________
82. Engineers Public Service Co., 12 S.E.C. 41, 59 (1942) (citation omitted).
-------------------------------
<PAGE>
the lost economies, representing economies associated with the Merger, are not
the dramatic changes that result from separation of ongoing businesses that have
operated long-term on a combined basis, but rather, are economies that could
have been realized over time through the combination of previously unconnected
businesses. By definition, measurement of lost economies associated with
acquisition of currently stand-alone companies is more speculative. Energy
East's divestiture analysis therefore appropriately focuses on the more concrete
lost economies associated with divestiture of the gas division of NYSEG.
As shown in Exhibit J-1, divestiture of the Companies' gas operations would
cause a significant, although difficult to quantify, amount of damage to
post-Merger Energy East's customers and would disrupt plans of its regulators to
create a fluid and efficient total energy marketplace, and set of services.
Likewise, divestiture would interfere with Energy East's ability to compete in
the marketplace. Such costs to customers involve the additional expenses of
doing business with two utilities instead of one (i.e., additional telephone
----
calls for service and billing inquiries, and cost of providing access to meters
and other facilities for two utilities) and costs associated with making the
entities supply information to shareholders and publish the reports required by
the Act. Similarly, increased costs would involve additional duties for the
staffs of the NYPSC, the DPUC and the MPUC as a result of each agency dealing
with one to two additional utilities. These additional duties would largely be
the result of duplicating existing functions, such as separate requests for
approval of financing and rate case requests.
Energy East's competitive position in the market would also suffer from
divestiture of the Companies' gas operations because, as the utility industry
moves toward a complete energy services concept, competitive companies must be
able to offer customers a range of options to meet their energy needs.
<PAGE>
Divestiture of gas operations would render Energy East unable to offer its
customers a significant and important option, namely gas services, and could
damage Energy East's long-term competitive potential. As the Commission
recognized in New Century Energies, Inc., in a competitive utility environment,
--------------------------
any loss of economies threatens a utility's competitive position, and even a
"small" loss of economies may render a utility vulnerable to significant
erosion of its competitive position.(83)
With respect to Clause B, as the Commission noted in WPL Holdings, Inc., et
----------------------
al.,(84) , "[c]lause B contemplates the location of an additional system in the
- --
same state as the principal system or in adjoining states."(85) Here, Energy
East's principal system (the integrated electric system) will be located in New
York and Maine, and the "additional system" -- the integrated natural gas system
- -- will be located in the same states of New York and Maine and in the adjoining
State of Connecticut. Hence Clause B of the ABC clauses is satisfied.
With respect to Clause C, the continued combination of the gas operations
under Energy East is not so large (considering the state of the art and the area
or region affected) as to impair the advantages of localized management. The
gas operations of the three Companies will continue to be the same as they are
today with some 545,300 customers in three states and confined to a relatively
small area.(86)
As the Commission has recognized elsewhere, the determinative consideration
under this criterion is not size alone or size in the absolute sense, either big
or small, but size in relation to its effect, if any, on localized management,
efficient operation and effective regulation.(87) Management currently is and
will remain geographically close to gas operations, thereby preserving the
advantages of localized management. From the standpoint of regulatory
______________________
83. New Century Energies, Inc., HCAR No. 26749, citing 1995 Report at 71.
-----------------------------
See also WPL Holdings, Inc., HCAR No. 26856 (April 14, 1998), citing 1995 Report
- --- ---- ------------------ ------
at 71.
84. HCAR No. 26856 (April 14, 1998).
85. Id. at n.44.
--
86. The relative sizes of the NYSEG, Southern Connecticut Gas, Maine Gas Co.
and CNGC gas operations are shown on the maps contained in Exhibit E-1.
87. See, e.g., Conectiv, Inc., HCAR No. 26832 (Feb. 25, 1998).
--- ---- ---------------
<PAGE>
effectiveness, each gas operation is organized in a separate corporation by
regulatory jurisdiction thus facilitating state regulation. Finally, as
detailed above, the gas operations of the three Companies will realize
additional economies as a result of the Merger. Far from impairing the
advantages of efficient operation, the continued combination of the gas
operations under Energy East will facilitate and enhance the efficiency of gas
operations.
In summary, the gas operations of Maine Gas Co., which are very limited in
size, currently operate as a single, integrated public utility system in central
Maine, and are currently operated jointly with Energy East pursuant to a Joint
Venture agreement. The Merger will not affect that integrated operation. The
addition of CNGC to the Energy East system in the State of Connecticut, where
Southern Connecticut Gas already serves 158,000 customers and which state
adjoins NYSEG's operations, will add 143,300 natural gas customers in
Connecticut to Energy East's existing base of over 244,000 customers. Such an
addition will bring about the benefits described above. Energy East should
therefore be permitted to retain its existing gas operations (i.e., NYSEG,
---
Southern Connecticut Gas, and Maine Gas Co.) while being allowed to acquire and
retain the natural gas utility assets of CMP Group and CTG Resources.
(c) Gas utility integration standards (Section 10(b)(2))
Section 2(a)(29)(B) defines an "integrated public utility system" as
applied to gas utility companies as:
[A] system consisting of one or more gas utility companies which are
so located and related that substantial economies may be effectuated
by being operated as a single coordinated system confined in its
operation 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: Provided, that gas
utility companies deriving natural gas from a common source of supply
may be deemed to be included in a single area or region.
<PAGE>
Unlike the definition of an "integrated electric utility system" in Section
2(a)(29)(A) of the Act, physical interconnection of the component parts of a gas
utility system is not required. Furthermore, the Commission has not
traditionally required that the pipeline facilities of an integrated system be
interconnected.(88)
The combination of Energy East's gas facilities -- NYSEG and Southern
Connecticut Gas -- with the gas facilities of CMP Group (Maine Gas Co.), and CTG
Resources (CNGC), will satisfy the integration standard set forth in Section
2(a)(29)(B)of the Act for the following reasons:
- All three gas systems will share a "common source of supply" and will
be operated as a "single coordinated system." Indeed, pursuant to a
joint venture agreement, NYSEG's gas division and Maine Gas Co. are
already being jointly operated.
- All three gas systems will be able to achieve "substantial economies"
in gas supply through the increased purchasing power and gas supply
coordination that will result from being part of the larger
combined gas system;
- As the smallest of the combined gas operations, Maine Gas Co. and
its customers will particularly benefit from these efficiencies,
as well as from the expertise of NYSEG, Southern Connecticut Gas
and CNGC in such areas as engineering, construction, training, meter
service, testing, marketing and gas transportation; and
- The area or region served by the three gas systems will not be "so
large as to impair the advantages of localized management, efficient
operation, and the effectiveness of regulation." To the contrary,
the management of CMP Group's and CTG Resources' utility
subsidiaries will largely remain intact after the consummation of the
Merger and the Maine Gas Co. and CNGC gas systems will be independent
of, but coordinated with (in order to promote efficient operation),
______________________
88. See In the Matter of Pennzoil Company, HCAR No. 15963 (1968) (finding an
-------------------------------------
integrated system where respective facilities both connected with an
unaffiliated transmission company but not each other). See also In the Matter
----------------------
of American Natural Gas Co., HCAR No. 15620 (1966) ("it is clear the integrated
- ---------------------------
or coordinated operations of a gas system under the Act may exist in the absence
of [physical] interconnection").
<PAGE>
that of Energy East's current gas system, and will be subject to
effective local regulation by the MPUC and DPUC, respectively.
(i) Section 2(a)(29)(B): "substantial economies may be effectuated
by being operated as a single coordinated system"
The three gas departments will be operated in a coordinated fashion as to
portfolio design and strategy, procurement, storage optimization, price risk
management and contract administration. Energy East, CMP Group and CTG
Resources are in the process of identifying specific components of their gas
portfolios which, through joint management and coordination, will enable the
combined companies to exploit opportunities for savings in the marketplace.(89)
With regard to natural gas service, Energy East, CMP Group and CTG
Resources gas subsidiaries purchase significant amounts of gas from the same
supply basins in Western Canada and Texas/Louisiana, holding capacity on the
Tennessee, Iroquois and Algonquin pipelines, and contract for storage services
in Pennsylvania and New York. These common portfolio resources may bring
long-term benefits to the Companies' customers. Moreover, as the dynamics and
structure of the natural gas industry continue to change, the marketplace will
create even more options for the Companies to create value through coordination
of their respective gas supply portfolios. For example, demand and pricing
differentials now exist and will continue to occur and, through coordinated
management of their portfolios of physical and contractual assets, the Companies
will be better positioned to take advantage of changing market conditions.
(ii) Section 2(a)(29)(B): "a single area or region in one or more
states"
After consummation of the Merger, Energy East's gas operations will be
located in a single region -- the northeastern United States. Although the
Energy East, CNGC and Maine Gas Co. retail gas service areas will be separated
by a distance of several hundred miles and, in the case of Maine Gas Co., are
located in non-contiguous states, such factors by themselves are not
______________________
89. See, e.g., Item 3.C.3 Economics and Efficiencies from the Merger
--- ----
(Section 10(c)(2)) for information concerning Merger economies and efficiencies.
<PAGE>
determinative. The Commission has made clear that systems separated by
intervening territories are in the same region because they procure gas from a
"common source of supply."(90)
Section 2(a)(29)(B) specifically contemplates that "gas utility companies
deriving natural gas from a common source of supply may be deemed to be included
in a single area or region." Moreover, in considering whether an "area or
region" is so large as to impair" the advantages of localized management,
efficient operation, and the effectiveness of regulation," the Commission must
consider the "state of the art" in the industry. Both the Commission's
precedent and the "state of the art" in the natural gas industry lead to the
conclusion that, with the CTG Resources and CMP Group gas systems included,
Energy East's gas utility system will operate as a coordinated system confined
in its operation to a single area or region because all three systems will
derive almost all of their natural gas from a common source of supply.
Neither the Act, the Commission's orders and rulings, nor the Commission
staff's no-action letters provide a definition as to what constitutes a "common
source of supply." Historically, in determining whether two gas companies share
a "common source of supply," the Commission has looked to such issues as from
whom the distribution companies within the system receive a significant portion
of their gas supply.(91) The Commission has also considered both purchases of
gas from a common pipeline(92) as well as from different pipelines when the gas
______________________
90. See, e.g., NIPSCO, HCAR No. 26975 (Feb. 10, 1999) (authorizing holding
--- ---- ------
company with operating company in Indiana to acquire a gas utility in
Massachusetts where the gas utilities in each state received significant amounts
of gas from the same supply basin).
91. See, e.g., In the Matter of Philadelphia Company and Standard Power and
--- ---- ------------------------------------------------------------
Light Co., HCAR No. 8242 (1948) ("most of the gas used by these companies in
- ---------
their operations is obtained from common sources of supply"); Consolidated
------------
Natural Gas Co., HCAR No. 25040 (1990) (finding integrated system where each
- -----------------
company derived natural gas from two transmission companies, although one such
company also received gas from other sources).
92. In the Matter of the North American Co., HCAR No. 10320 (1950) (finding
---------------------------------------
Panhandle Eastern pipeline to be a common source of supply).
<PAGE>
originates from the same gas field.(93) Since the time of most of these
decisions, the state of the art in the industry has developed to allow efficient
operation of systems whose gas supplies derive from many sources.
Following consummation of the Merger, all three gas systems will derive
substantially all of their gas from a common source of supply under Section
2(a)(29)(B). NYSEG receives approximately 63 percent of its gas supply from the
Texas and Louisiana Basins and approximately 28.5 percent of its gas supply from
the Western Canadian Sedimentary Basin, which together account for over 91
percent of NYSEG's gas supply. In addition, over 36 percent of NYSEG's total
transportation capacity requirements are carried on the Tennessee, Iroquois,
Algonquin and Texas Eastern pipelines. Southern Connecticut Gas receives
approximately 64 percent of its gas supply from the Texas and Louisiana Basins
and approximately 35 percent of its gas supply from the Western Canadian
Sedimentary Basin, which together account for 99 percent of Southern Connecticut
Gas's gas supply. In addition, nearly all of Southern Connecticut Gas's total
______________________
93. See In the Matter of Central Power Company and Northwestern Public
--- -------------------------------------------------------------------
Service Co., HCAR No. 2471 (1941), in which the Commission declared an
-------
integrated system to exist where two entities purchase from different pipeline
----
companies since "both pipelines run out of the Otis field, side by side, and are
interconnected at various points in their transmission system; and that they are
within two miles of each other at Kearney."
<PAGE>
transportation capacity requirements from each of the basins mentioned above are
carried on the Tennessee, Iroquois, Algonquin and Texas Eastern pipelines. With
regard to CTG Resources' gas subsidiary, CNGC, approximately 73 percent of
CNGC's gas supply is received from the Texas and Louisiana basins, and
approximately 26 percent of its gas supply is received from the Western Canadian
Sedimentary Basin, which together account for over 99 percent of CNGC's gas
supply. Approximately 98 percent of CNGC's total transportation capacity
requirements are carried on the Tennessee, Iroquois, Algonquin, and Texas
Eastern pipelines. With regard to Maine Gas Co., approximately 100 percent of
Maine Gas Co.'s gas supply is currently received from the Portland Natural Gas
Transmission System ("PNGTS") pipeline, which is interconnected with the
TransCanada Pipeline, carrying Western Canadian Sedimentary Basin gas. When
fully developed, Maine Gas Co. will continue to receive at least 50 percent of
its gas supply from the Western Canadian Sedimentary Basin through the
TransCanada Pipeline and the PNGTS pipeline.
In addition, Sable Island gas supply from offshore Nova Scotia via the
newly constructed Maritimes & Northeast Pipeline will be available to Maine Gas
Co. and to NYSEG via the Tennessee Gas Pipeline, which connects to the Maritimes
& Northeast Pipeline at Dracut, Massachusetts to provide service to New England,
and to Southern Connecticut Gas and CNGC via the Algonquin Gas Pipeline, which
connects to the Maritimes & Northeast Pipeline at Salem, Massachusetts to
provide service to Massachusetts, New York and Connecticut. It is anticipated
that, as Sable Island is developed, the NYSEG, Southern Connecticut Gas, CNGC
and Maine Gas Co. gas facilities will draw a growing percentage of supplies from
this important new supply basin.
Purchases from and through a common pipeline, as well as purchases from a
common gas field, have been found to satisfy the "common source of supply"
requirement of Section 2(a)(29)(B) of the Act.(94) There is thus substantial
evidence that NYSEG, Southern Connecticut Gas, CNGC and Maine Gas Co. will share
a common source of supply for a significant amount of their respective gas
supplies.
Any determination of the appropriate size of the area or region calls for
consideration of the "state of the art" in the gas industry. In this regard,
the "state of the art" in the gas industry continues to evolve and change,
primarily as a result of decontrol of wellhead prices, the continuing
development of an integrated national gas transportation network, the
______________________
94. See, e.g., NIPSCO, supra.
--- ---- ------ -----
<PAGE>
construction of new pipeline capacity, the emergence of marketers and brokers,
and the "un-bundling" of the commodity and transportation functions of pipelines
and local distribution companies in response to various FERC and state
initiatives.(95) Of particular importance has been the development, evolution
and operation of market centers, trading hubs, and pooling areas. Today,
trading activity conducted at market centers and trading hubs play an
increasingly vital role in the overall management of the assets in a gas
portfolio (supply, transportation and storage).
As a result of these developments, coordination of the operations of two
non-contiguous gas companies is no longer dependent solely upon having
contractual capacity on the same interstate pipelines, so long as the two
companies both have access to one or more common market centers or trading hubs.
Importantly, these developments in the state of the art in the gas industry now
allow gas distribution companies operating in a much larger area or region of
the country to realize operating economies and efficiencies from coordinated
operation that were once thought to be achievable only by contiguous or nearly
contiguous gas companies supplied by the same interstate pipelines.(96)
As indicated above, because NYSEG, Southern Connecticut Gas, CNGC and Maine
Gas Co. will potentially share access through their respective pipeline
transporters to industry-recognized market and supply area hubs, they will have
the enhanced ability to physically coordinate and manage their portfolios of
supply, transportation and storage and to support, if necessary, the underlying
physical side of various financial derivatives as a means of managing price
volatility.
(iii) Section 2(a)(29)(B): System size from perspective of
"the advantages of local management, efficient
operation and the effectiveness of regulation."
The integrated gas system to be formed by the combination of NYSEG,
Southern Connecticut Gas, CNGC and Maine Gas Co. will not be "so large as to
impair (considering the state of the art and the area or region affected) the
______________________
95. See, e.g., NIPSCO; 1995 Report at 29-31.
--- ---- ------
96. See, e.g., New Century Energies, Inc., supra.
--- ---- ----------------------------- ------
<PAGE>
advantages of localized management, efficient operation and the effectiveness of
regulation." Although the CNGC and Maine Gas Co. gas supply personnel will
report to an officer of Energy East, and the Maine Gas Co. supply personnel will
report to an officer of EE Enterprises, CNGC will retain gas supply personnel in
Connecticut and Maine Gas Co. will retain gas supply personnel in Maine.
Further, the affiliation of these three gas companies is expected to result in
economies and efficiencies, as discussed in more detail below.
Finally, the Merger will not have an adverse effect upon effective
regulation. Following the Merger, each utility will remain subject to
regulation by its current state regulator(s). Accordingly, the Commission
should find that the size requirements of Section 2(a)(29)(B) of the Act are
satisfied.
For all of the above reasons, the combined gas operations and Energy East,
CTG Resources and CMP Group will constitute a single integrated gas utility
system.
4. Economies and Efficiencies from the Merger (Section 10(c)(2))
--------------------------------------------
As discussed above, Section 10(c)(2) requires that the Commission approve a
proposed transaction if it will serve the public interest by tending toward the
economical and efficient development of an integrated public utility system.
Through the Merger, the Companies will create an entity that is well situated to
compete effectively in an increasingly active market. The efficiencies and
economies brought about through the Merger, and described in more detail below,
thereby serve the public interest, as required by Section 10(c)(2) of the Act.
Although many of the anticipated economies and efficiencies will be fully
realizable only in the longer term, they are properly considered in determining
whether the standards of Section 10(c)(2) have been met.(97) Some potential
benefits cannot be precisely estimated; nevertheless they should be
considered.(98) In addition, Section 10(c)(2) of the Act does not require that
______________________
97. See American Electric Power Co., 46 SEC 1299, 1320-1321 (1978).
--- -----------------------------
98. "[S]pecific 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., HCAR No. 24073 (April
----------------------
29, 1986) (citation omitted); see also In Re Consolidated Edison, Inc., HCAR No.
--- ---- -------------------------------
2702 (May 13, 1999).
<PAGE>
the future savings be large in relation to the gross revenues of the companies
involved.(99)
The Companies believe that the Merger will provide significant financial
and organizational advantages and, as a result, the potential for substantial
economies and efficiencies should be found to meet the standard of Section
10(c)(2) of the Act. Although the parties to the Merger have not quantified the
value of the resulting economies and efficiencies, they have identified specific
aspects of their respective businesses, which through joint management and
coordination, should enable the three companies to achieve savings.
The geographical locations of the respective electric energy service
territories of NYSEG and CMP, which operate in contiguous ISOs, provide an
opportunity to integrate their electric utility operations efficiently. The
combined system can be operated as a single, larger cohesive system, with
virtually no modification needed with respect to existing transmission
facilities. As the structure of the electric utility industry continues to
evolve, the marketplace will create additional opportunities for the Companies
to create value through integrated operations and increased efficiencies.
The Companies believe that their combination offers significant strategic
and financial benefits to each company and shareholders, as well as to their
respective employees and customers. These benefits include, among others: (i)
maintenance of competitive rates that will improve the combined entity's ability
to meet the challenges of the increasingly competitive environment in both the
electric and gas utility industry, (ii) over time a reduction in operating costs
and expenditures resulting from integration of corporate and administrative
functions, including limiting duplicative capital expenditures for
______________________
99. See American Natural Gas Co., 43 S.E.C. 203 at 208 (1966).
--------------------------------
<PAGE>
administrative and customer service programs and information systems, and
savings in areas such as outside legal, audit and consulting fees, (iii) greater
purchasing power for gas supply and for items such as transportation services
and operational goods and services, (iv) enhanced opportunities for expansion
into non-utility businesses, (v) expanded management resources and ability to
select leadership from a larger and more diverse management pool, and (vi) a
financially stronger company that, through the use of the combined capital,
management, and technical expertise of each company, will be able to achieve
greater financial stability and strength and greater opportunities for earnings
growth, reduction of operating costs, efficiencies of operation, better use of
facilities for the benefit of customers, improved ability to use new
technologies, greater retail and industrial sales diversity, improved capability
to compete in wholesale power markets and joint management and optimization of
their respective portfolios of gas supply, transportation and storage assets.
The Applicants believe that over time the Merger will generate efficiencies and
economies which would not be available to the separate companies absent the
Merger and which will enable post-Merger Energy East to continue to be a
low-cost competitor in the marketplace.
The Companies are in the process of identifying additional opportunities
for the merged Company to achieve administrative savings in such areas as
accounting, tax, purchasing, legal, planning, human resources (including
employee benefits plan management), information services, financial services,
and regulatory relations.
(a) Corporate Operations
The Companies anticipate Merger-related savings in areas where costs are
relatively fixed and do not vary with an increase or decrease in the number of
customers served. These areas include legal services, finance, sales, support
services, transmission and distribution, customer service, accounting, human
resources and information services.
(b) Administration
Savings will be realized through cost avoidance in those areas where Energy
East, CMP Group and CTG Resources incur many costs for items which relate to the
operation of each company, but which are not directly attributable to customers.
Eleven such areas have been identified: administrative and general overhead;
benefits administration; insurance; shareholder services; advertising;
<PAGE>
association dues; directors' fees; and vehicles. Achieving cost savings through
greater efficiencies will permit each of the operating utilities to offer more
competitively-priced electric service and energy-related products and services
than would otherwise be possible.
(c) Non-Gas Supply Purchasing Economies
Savings will be realized through increased order quantities and the
enhanced utilization of inventory for materials and supplies. Currently, Energy
East, CMP Group and CTG Resources independently maintain separate purchasing
departments responsible for maintaining materials and supplies used by employees
at various locations. In addition, all three companies procure contract
services independently. As a direct result of the combination, savings can be
realized through the procurement of both materials and services, as well as in
costs associated with the maintenance of inventory levels.
(d) Gas Supply
Savings will be realized through the bundling of natural gas purchases in
the form of larger quantities or volumes. It is anticipated that post-Merger
Energy East will be able to take advantage of commodity savings based on higher
total volumes of natural gas acquisition. This results in competitive market
prices for all three Companies.
Savings from these sources will be offset by the costs that must be
incurred for activities essential to achieving the savings. The Companies have
formed a Transition Steering Team, which will diligently pursue ways in which to
avoid or minimize such offsetting costs.
(e) Additional Expected Benefits
In addition to the benefits described above, there are other benefits
which, while presently difficult to quantify, are nonetheless substantial.
These other benefits include:
- - Increased Scale-- As competition intensifies within the gas and electric
industry, the Companies believe scale will be one dimension that will
contribute to overall business success. Scale has importance in many areas,
including utility operations, product development, advertising and
corporate services. The
<PAGE>
Merger is expected to improve the profitability of the combined company by
adding approximately 834,300 customers to Energy East's existing customer base
and providing increased economies of scale in all of these areas.
- - Competitive Prices and Services-- Sales to industrial, large commercial and
wholesale customers are considered to be at greatest near-term risk as a
result of increased competition in the electric utility industry. The
Merger will enable Energy East to meet the challenges of the increased
competition and will create operating efficiencies through which Energy
East will be able to provide more competitive prices to customers.
- - More Balanced Customer Base-- The Merger will create a larger company with
a more diverse customer base. This should reduce post-Merger Energy East's
exposure to adverse changes in any sector's economic and competitive
conditions.
- - Financial Flexibility-- By creating a company with a larger market
capitalization than had been previously experienced by any of the Companies
considered on an individual basis, the Merger should improve Energy East's
overall credit quality and liquidity of the securities and therefore
improve Energy East's ability to fund continued growth.
- - Regional Platform for Growth-- The combination of Energy East, CMP Group
and CTG Resources will create a regional platform for growth in the
northeastern United States. Energy East plans to expand relationships with
existing customers and to develop relationships with new customers in the
region. Energy East will use its combined distribution channels to market a
portfolio of energy-related products throughout the region and will follow
regional relationships to other geographical areas.
For the above stated reasons, the Commission should find that the
integration criteria are satisfied and approve the proposed Merger.
<PAGE>
5. Retention of Non-Utility Businesses
--------------------------------------
As a result of the Merger, the non-utility businesses and interests of CMP
Group and CTG Resources will become businesses and interests of Energy East.
Additionally, as a result of the Merger, non-utility assets held by Energy East,
currently an exempt holding company, will become businesses and interests of
post-Merger Energy East, a registered holding company. The total assets of all
non-utility investments of Energy East, CMP Group and CTG Resources as of June
30, 1999 totaled $320 million. Energy East also had $1 billion of cash and
temporary investment proceeds from the sale of its coal-fired generation assets,
that will be used to complete the mergers and continued common stock
repurchases.
Corporate charts showing the subsidiaries, including non-utility
subsidiaries, of Energy East, CMP Group and CTG Resources are filed as Exhibits
E-2 through E-4. A corporate chart showing the projected arrangement of these
subsidiaries under post-merger Energy East immediately after consummation of the
Merger is filed as Exhibit E-5.
Section 11(b)(1) generally limits a registered holding company to retain
"such other businesses as are reasonably incidental, or economically necessary
or appropriate, to the operations of [an] integrated public utility system."
Although the Commission has traditionally interpreted this provision to require
an operating or "functional" relationship between the non-utility activity and
the system's core non-utility business, in its recent release promulgating Rule
58,(100) the Commission stated that it "has sought to respond to developments in
the industry by expanding its concept of a functional relationship." The
Commission added "that various considerations, including developments in the
industry, the Commission's familiarity with the particular non-utility
______________________
100. Exemption of Acquisition by Registered Public-Utility Holding Companies
of Securities of Non-utility Companies Engaged in Certain Energy-related and
Gas-related Activities, HCAR No. 26667 (Feb. 14, 1997) ("Rule 58 Release").
<PAGE>
activities at issue, the absence of significant risks inherent in the particular
venture, the specific protections provided for consumers and the absence of
objections by the relevant state regulators, made it unnecessary to adhere
rigidly to the types of administrative measures" used in the past. Furthermore,
in the 1995 Report, the SEC Staff recommended that the Commission replace the
use of bright-line limitations with a more flexible standard that would take
into account the risks inherent in the particular venture and the specific
protections provided for consumers.(101) The non-utility business interests
that post-Merger Energy East will directly or indirectly hold all meet the
Commission's standards for retention.
Many of the existing direct and indirect non-utility business interests of
Energy East, CMP Group and CTG Resources fall within the ambit of newly adopted
Rule 58 or are "exempt telecommunications companies" within the meaning of
Section 34 of the Act.
The Companies will file by amendment a comprehensive listing of, and
justification for, all non-utility subsidiaries.
Consistent with the Commission's recent decisions in New Century Energies,
---------------------
Inc.,(102) and Conectiv, Inc.,(103) investments made by Energy East, CMP Group
--------------
and CTG Resources prior to the effective date of the Merger should not count in
the calculation of the 15 percent limit for purposes of Rule 58. All additional
investments made by Energy East in energy-related companies subsequent to the
effective date of the Merger would, of course, be included in the 15 percent
test.
D. 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 to 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.
______________________
101. 1995 Report at 81-87, 91-92.
102. New Century Energies, Inc., HCAR No. 26748 (Aug. 1, 1997).
-----------------------------
103. Conectiv, Inc., HCAR No. 26832 (Feb. 25, 1998).
---------------
<PAGE>
As described in Item 4 of this Application/Declaration, and as evidenced by the
applications before the DPUC and MPUC relating to the Merger, Energy East
intends to comply with all applicable state laws related to the proposed
transaction.
ITEM 4. REGULATORY APPROVALS
Set forth below is a summary of the regulatory approvals that Energy East
has obtained or expects to obtain in connection with the Merger.
A. ANTITRUST
The HSR Act and the rules and regulations thereunder provide that certain
transactions (including the Merger) may not be consummated until certain
information has been submitted to the DOJ and FTC and specified HSR Act waiting
period requirements have been satisfied. Energy East, CTG Resources and CMP
Group will submit Notification and Report Forms and all required information to
the DOJ and FTC and the Merger will not be consummated unless the applicable
waiting period has expired or has been terminated. The expiration of the HSR
Act waiting period does not preclude the DOJ or the FTC from challenging the
Merger on antitrust grounds; however, Energy East believes that the Merger will
not violate Federal antitrust laws. If the Merger is not consummated within
twelve months after the expiration or earlier termination of the initial HSR Act
waiting period, Energy East, CTG Resources and CMP Group would be required to
submit new information to the DOJ and the FTC, and a new HSR Act waiting period
would have to expire or be earlier terminated before the Merger could be
consummated.
B. FEDERAL POWER ACT
Section 203 of the Federal Power Act as amended provides that no public
utility shall sell or otherwise dispose of its jurisdictional facilities or
directly or indirectly merge or consolidate such facilities with those of any
other person or acquire any security of any other public utility, without first
having obtained authorization from the FERC. Energy East and CMP Group
<PAGE>
submitted a joint application for approval of the CMP Group Merger to the FERC
on October 1, 1999. See Exhibit D-1.
C. ATOMIC ENERGY ACT
Central Maine Power holds an NRC non-operating license with respect to its
2.5% ownership interests in the Millstone No. 3 nuclear unit in Waterford,
Connecticut. The Atomic Energy Act currently provides that a license may not be
transferred or in any manner disposed of, directly or indirectly, to any person
unless the NRC finds that such transfer is in accordance with the Atomic Energy
Act and consents to the transfer. Pursuant to the Atomic Energy Act, Central
Maine Power submitted an application on October 6, 1999 for the consent of the
NRC. See Exhibit D-9.
D. TELECOMMUNICATIONS
Central Maine Power and MEPCo, public utility subsidiaries of CMP Group,
have filed with the FCC for approval of the transfers of certain radio and
microwave licenses. CNGC, the public utility subsidiary of CTG Resources, holds
radio station licenses from the FCC with respect to its dispatch center and
certain of its communications equipment and devices. CNGC will apply to the FCC
to approve transfer of the indirect holder of the licenses as a result of the
Merger. The radio license applications previously filed by Central Maine Power
and MEPCo are included as Exhibit D-11. The radio license transfer applications
filed by CNGC will be filed by amendment.
E. STATE PUBLIC UTILITY REGULATION
Connecticut: The DPUC has jurisdiction over CNGC and over Central Maine
Power. CNGC is a public service company under Connecticut law because it is a
gas company distributing gas for heat or power within Connecticut. Central
Maine Power is a "public service company" under Connecticut law as a result of
its 2.5 percent Milestone Unit No. 3 ownership interest. Energy East and CTG
Resources have filed a joint application with the DPUC. See Exhibit D-7.
Central Maine Power will file an application with the DPUC, a copy of which will
be submitted to this Commission as Exhibit D-5.
<PAGE>
Maine: Under Maine law, the MPUC has jurisdiction over the indirect
transfer of control of Central Maine Power and of CMP Group's other utility
subsidiaries resulting from the CMP Group Merger under a standard that requires
a finding that the merger is consistent with the interests of customers and
shareholders. CMP Group filed with the MPUC for approval of its merger with
Energy East on July 1, 1999. See Exhibit D-3. Under Maine law, the MPUC must
act definitively within 180 days of the date of filing.
ITEM 5. PROCEDURE
The Commission is respectfully requested to issue and publish the requisite
notice under Rule 23 with respect to the filing of this Application as soon as
possible, but in any event not later than December 1, 1999.
It is submitted that a recommended decision by a hearing or other
responsible officer of the Commission is not needed for approval of the proposed
Merger. The Division of Investment Management 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 6. EXHIBITS AND FINANCIAL STATEMENTS
A. EXHIBITS
A-1 Restated Certificate of Incorporation of Energy East filed in the
Office of the Secretary of State of the State of New York on April 23,
1998 (filed as Exhibit 4.1 to Energy East's Post-effective Amendment
No. 1 to Registration No. 033-54155, and incorporated herein by
reference).
A-2 Certificate of Amendment of the Certificate of Incorporation of Energy
East filed in the Office of the Secretary of State of the State of New
York on April 26, 1999 (filed as Exhibit 3.3 to Energy East's Form
10-Q for the quarter ended March 31, 1999, File No. 1-14766 and
incorporated herein by reference).
A-3 By-Laws of Energy East as amended April 23, 1999, (filed as Exhibit
3.4 to Energy East's Form 10-Q for the quarter ended March 31, 1999,
File No. 1-14766, and incorporated herein by reference).
<PAGE>
A-4 Amended and Restated Certificate of Incorporation of CTG Resources
(filed as Exhibit 3.2 to the Registration Statement on Form S-4
Registration No. 333-16297 and incorporated herein by reference).
A-5 Restated Certificate and Articles of Incorporation of CMP Group (filed
in the office of the Secretary of State of the State of Maine on June
11, 1999. File No. 199811590D, and filed herewith on Form S-E).
B-1 Agreement and Plan of Merger between Energy East and CTG Resources
(filed as Exhibit 2.1 to the Registration Statement on Form S-4,
Registration No. 333-85333 and incorporated herein by reference.)
B-2 Agreement and Plan of Merger between Energy East and CMP Group (filed
as Appendix A to CMP Group's definitive Proxy Statement dated August
30, 1999, filed with the Commission on September 1, 1999, and
incorporated herein by reference.)
C-1 Registration Statement of Energy East on Form S-4, including Proxy
Statement of CTG Resources and Prospectus of Energy East (filed on
August 16, 1999, Registration No. 333-85333 and incorporated herein by
reference).
C-2 Definitive Proxy Statement of CMP Group dated August 30, 1999 (filed
with the Commission on September 1, 1999 and incorporated herein by
reference.)
D-1 Application of Energy East Corporation and CMP Group to the FERC under
Section 203 of the FPA, Docket No. EC00-001, dated October 1, 1999
(filed herewith; includes affidavits, but not exhibits to
application).
D-2 Order of the FERC in Docket No. EC00-001 (to be filed by amendment).
D-3 Application of CMP Group, Inc. to the MPUC, Docket No. 99-411 (filed
herewith).
D-4 MPUC Order in Docket No. 99-411 (to be filed by amendment).
D-5 Application of CMP Group, Inc. to DPUC (to be filed by amendment).
D-6 DPUC Order (to be filed by amendment).
D-7 Joint Application of Energy East and CTG Resources to the DPUC, Docket
No. 99-08 (filed herewith).
D-8 DPUC Order in Docket No. 99-08 (to be filed by amendment).
D-9 Application of Central Maine Power to the NRC (filed herewith).
D-10 NRC Order (to be filed by amendment).
<PAGE>
D-11 Applications of Central Maine Power and MEPCo (public utility
subsidiaries of CMP Group) to the FCC for indirect transfer of radio
and microwave licenses relating to certain communications equipment.
(Filed on Form S-E.)
D-12 Application of CNGC (CTG Resources' public utility subsidiary) to the
FCC for transfer of radio licenses (to be filed by amendment).
D-13 FCC Order(s) relating to transfer of radio and microwave licenses (to
be filed by amendment).
E-1 Maps for Energy East, CMP Group and CTG Resources: Franchise Areas of
Major Utilities in the Northeast; Energy East Electric Franchise Areas
(post-merger); and Energy East Natural Gas Franchise Areas
(post-Merger). (Filed on Form S-E.)
E-2 Energy East corporate chart. (Filed on Form S-E.)
E-3 CMP Group corporate chart. (Filed on Form S-E.)
E-4 CTG Resources corporate chart. (Filed on Form S-E.)
E-5 Energy East (post-Merger) corporate chart. (Filed on Form S-E.)
F-1 Preliminary Opinion of Huber Lawrence & Abell, counsel to Energy East
(to be filed by amendment).
F-2 Past-tense opinion of Huber Lawrence & Abell, counsel to Energy East
(to be filed by amendment).
G-1 Opinion of Warburg Dillon Read (filed as Appendix B to CMP Group's
Definitive Proxy Statement dated August 30, 1999, and incorporated
herein by reference).
G-2 Opinion of PaineWebber Incorporated (filed as Appendix B to Proxy
Statement/Prospectus included in Registration No. 333-05333, and
incorporated herein by reference).
G-3 Financial Data Schedule (filed herewith and titled "Exhibit 27").
H-5 Retention of Non-Utility Subsidiaries (to be filed by amendment).
I-1 Proposed Form of Notice (filed herewith).
J-1 Analysis of the Economic Impact of a Divestiture of the Gas Operations
of Energy East (filed herewith).
<PAGE>
B. FINANCIAL STATEMENTS
FS-1 Pre-Merger and pro forma combined condensed balance sheet of Energy
East as of June 30, 1999, and pre-Merger and pro forma combined
condensed statement of income and statement of retained earnings of
Energy East for the twelve months ended June 30, 1999 (filed
herewith).
FS-2 Balance sheet of CMP Group as of June 30, 1999, and statement of
income and statement of retained earnings of CMP Group for the twelve
months ended June 30, 1999, included in the balance sheet, statement
of income and statement of retained earnings of Energy East (filed
herewith as FS 1).
FS-3 Balance sheet of CTG Resources as of June 30, 1999, and statement of
income and statement of retained earnings of CTG Resources for the
twelve months ended June 30, 1999, included in the balance sheet,
statement of income and statement of retained earnings of Energy East
(filed herewith as FS 1).
FS-4 Statements of income and surplus of CMP Group for the fiscal year
ended December 31, 1998, 1997 and 1996 (included in CMP Group's Form
10-K for the year ended December 31, 1998, File No. 01-0519429 and
incorporated herein by reference).
FS-5 Statements of income and surplus of CTG Resources for the fiscal years
ended September 30, 1998, 1997 and 1996 (included in CTG Resources
Form 10-K for the year ended September 30, 1998, File No. 1-12859 and
incorporated herein by reference).
ITEM 7. INFORMATION AS TO ENVIRONMENTAL EFFECTS
The Merger neither involves a "major federal action" nor "significantly
affect[s] 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. 4321
et seq. The only federal actions related to the Merger pertain to the
- -------
Commission's declaration of the effectiveness of CMP Group's Proxy Statement and
Energy East's Registration Statement on Form S-4, the expiration of the
applicable waiting period under the HSR Act, approval of the application filed
by Energy East and CMP Group with the FERC under the Federal Power Act, approval
of the application filed by Central Maine Power with the NRC under the Atomic
Energy Act, approval of the applications filed by Central Maine Power and MEPCo
with the FCC, approval of the application with the FCC to be filed by CTGC and
<PAGE>
this Commission's approval of this Application/Declaration. Consummation of the
Merger will not result in changes in the operations of the Companies that would
have any impact on the environment. No federal agency is preparing an
environmental impact statement with respect to this matter.
SIGNATURE
Pursuant to the requirements of the Public Utility Holding Company Act of
1935, the undersigned companies have duly caused this Form U-1
Application/Declaration to be signed on their behalf by the undersigned
thereunto duly authorized.
<PAGE>
Energy East Corporation
Date:, 1999 By: /S/ Kenneth M. Jasinski
------------------------------------------------
Kenneth M. Jasinski
Executive Vice President and General Counsel
CMP Group, Inc.
Date:, 1999 By: /S/ Arthur W. Adelberg
------------------------------------------------
Arthur W. Adelberg
Executive Vice President
CTG Resources
Date:, 1999 By: /S/ Arthur C. Marquardt
------------------------------------------------
Arthur C. Marquardt
Chairman, President and Chief Executive Officer
<PAGE>
<TABLE> <S> <C>
<ARTICLE> OPUR1
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S COMBINED CONDENSED FINANCIAL STATEMENTS FOR THE TWELVE MONTHS ENDED
JUNE 30, 1999 INCLUDED IN ITS FORM U-1 FILING AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS
</LEGEND>
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<PERIOD-TYPE> 12-MOS 12-MOS
<FISCAL-YEAR-END> DEC-31-1999 DEC-31-1999
<PERIOD-END> JUN-30-1999 JUN-30-1999
<BOOK-VALUE> PER-BOOK PRO-FORMA
<TOTAL-NET-UTILITY-PLANT> 2,432,364 3,567,119
<OTHER-PROPERTY-AND-INVEST> 109,170 193,727
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<TOTAL-ASSETS> 4,624,926 7,397,645
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25,000 43,910
10,131 46,538
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<GROSS-OPERATING-REVENUE> 2,706,279 3,983,107
<INCOME-TAX-EXPENSE> 231,764 289,061
<OTHER-OPERATING-EXPENSES> 405,341 692,828
<TOTAL-OPERATING-EXPENSES> 2,087,574 3,187,014
<OPERATING-INCOME-LOSS> 618,705 796,093
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<INCOME-BEFORE-INTEREST-EXPEN> 0 0
<TOTAL-INTEREST-EXPENSE> 142,974 254,584
<NET-INCOME> 245,668 292,444
5,775 9,512
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</TABLE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ENERGY EAST CORPORATION )
)
AND ) DOCKET NO. EC99-___-000
)
CMP GROUP, INC. )
JOINT APPLICATION OF ENERGY EAST CORPORATION AND CMP GROUP, INC. FOR
AUTHORIZATION AND APPROVAL OF THEIR PROPOSED MERGER AND THE RESULTING
DISPOSITION OF JURISDICTIONAL FACILITIES
Energy East Corporation ("Energy East") and CMP Group, Inc. ("CMP Group"),
on behalf of their jurisdictional subsidiaries (collectively, "the Applicants"),
submit this Joint Application under Section 203 of the Federal Power Act ("FPA")
and Part 33 of the Commission's regulations, requesting authorization and
approval of the proposed merger between Energy East and CMP Group and the
resulting disposition of jurisdictional facilities. The principal
jurisdictional subsidiary of Energy East is New York State Electric & Gas
Corporation ("NYSEG"), a public utility operating in New York. In addition,
Energy East has several jurisdictional subsidiaries that are not traditional
public utilities, but which have market-based rate authority from this
Commission. The sole jurisdictional, wholly-owned subsidiary of CMP Group is
Central Maine Power Company ("Central Maine" or "CMP"), a public utility
operating in Maine. The Applicants request that the Commission act
expeditiously on this Application and approve the proposed merger without a
hearing.
I.
INTRODUCTION
This Application and the accompanying affidavits and exhibits demonstrate
that the proposed merger is consistent with the public interest. The proposed
merger will have no adverse impact on competition, rates or regulation. NYSEG
and CMP have divested and/or relinquished control over virtually all of their
<PAGE>
generation assets and purchase power contracts. Thus, both companies are
properly viewed as transmission and distribution utilities rather than as
traditional, vertically integrated utilities. Each company also has
transferred, or committed to transfer, control and operation of its transmission
facilities to an Independent System Operator ("ISO")(1) , and each company is
today primarily in the business of providing energy delivery services to retail
customers. Thus, neither of these utilities has the ability or the incentive to
exercise generation or transmission market power.
Approval of the proposed merger will join two companies with similar
management approaches and similar business objectives. The public utility
subsidiaries of Energy East and CMP Group, NYSEG and CMP, respectively, operate
in comparable service territories and each is subject to state regulatory
commissions that have been restructuring utility operations and aggressively
pursuing retail competition policies for the past several years. Retail access
is available today on NYSEG's electric and gas systems. Retail access will be
available on CMP's electric distribution system on March 1, 2000. Both NYSEG
and CMP have divested generation assets and, pursuant to state policies, are in
the process of implementing retail choice. Both have a strong commitment to
customer service and both are focused on the delivery business, rather than
commodity sales, as their core lines of business. Approval of the proposed
merger will allow the two companies to combine into a larger, financially
stronger company that will have the combined resources, experience and talent to
focus on providing high quality and cost-efficient energy delivery, products and
services to customers in the Northeast. The merger not only will have no
anticompetitive effects, but, by creating a stronger transmission and
distribution company, it will have pro-competitive effects in the northeast
United States.
____________________
1 CMP has retained control of its "non-PTF" facilities which, for CMP,
generally are facilities that operate at a voltage of 34.5 kV or less.
2
<PAGE>
II.
DESCRIPTION OF THE APPLICANTS
A. ENERGY EAST
Energy East is an exempt public utility holding company, with its principal
office in Stamford, Connecticut. It was formed in 1997 and became the parent
of NYSEG on May 1, 1998. Energy East, through its subsidiaries, is an energy
delivery, products and services company with operations in New York,
Massachusetts, Maine, New Hampshire, Vermont and New Jersey. As a result of the
proposed merger with CMP Group, Energy East anticipates that it will become a
registered public utility holding company under the Public Utility Holding
Company Act of 1935 ("PUHCA").
1. NYSEG
NYSEG is a combination electric and gas utility serving 826,000 electric
customers and 244,000 natural gas customers in upstate New York. NYSEG has
divested substantially all of its generating assets. It retains certain
hydroelectric facilities, non-utility generation ("NUG") contracts and contracts
pursuant to which the New York Power Authority ("NYPA") sells power to NYSEG, as
well as an 18 percent ownership interest in the Nine Mile Point Unit 2 Nuclear
Plant ("NM2").(2)
After the sale of its interest in NM2, NYSEG will be engaged almost
entirely in the transmission and distribution of electricity and the
____________________
2 NYSEG has contracted to sell its 18 percent interest in NM2 to Amergen Inc.
Approval of that sale is pending before the New York Public Service Commission.
A Section 203 application for authorization to transfer associated
jurisdictional facilities is pending before the Commission in Docket No.
EC99-98-000.
3
<PAGE>
distribution of natural gas. As of December 31, 1998, NYSEG's electric
transmission system consisted of approximately 4,482 circuit miles of line.
NYSEG's electric distribution system consisted of 35,967 miles of line. NYSEG,
which is a member of the New York Power Pool ("NYPP"), has committed to transfer
control of its transmission system to the New York ISO.(3)
NYSEG has received market-based rate authority from the Commission.(4)
2. OTHER JURISDICTIONAL SUBSIDIARIES
Energy East has four other subsidiaries that have received market-based
rate authority from the Commission, but none of these subsidiaries is a
traditional public utility, i.e., none has franchise territories or captive
----
customers. These companies are: XENERGY, Inc., an energy services and
consulting firm; Carthage Energy, LLC ("Carthage"), an exempt wholesale
generator ("EWG"); South Glens Falls, LLC ("South Glens Falls"), an EWG; and
NYSEG Solutions, Inc., a supplier of electric and natural gas commodity
services.(5)XENERGY, Inc., 79 FERC 61,303 (1997); Carthage Energy, LLC, 87
FERC 62,313 (1999); Energy East South Glens Falls, LLC, 86 FERC 61,254
(1999); and NYSEG Solutions, Inc., 85 FERC 61,342 (1998).
Of these four subsidiaries, only Carthage and South Glens Falls operate or
control generating capacity (126 MW, collectively).
3. SIGNIFICANT NON-JURISDICTIONAL SUBSIDIARIES
Another subsidiary of Energy East, Energy East Enterprises, Inc. ("EE
Enterprises") owns natural gas and propane air distribution companies in
Vermont, New Hampshire and Maine. One of EE Enterprises ' subsidiaries is CMP
Natural Gas, LLC, which is a joint venture with CMP to build a natural gas
distribution system in Maine.
Energy East has reached an agreement to acquire Connecticut Energy
Corporation ("Connecticut Energy"), an exempt public utility holding company
that owns The Southern Connecticut Gas Company ("Southern Connecticut").
Southern Connecticut is a local gas distribution company serving approximately
____________________
3 Central Hudson Gas & Electric Corp., et al., 87 FERC 61,135 (1999). The
New York ISO is expected to begin operations on October 12, 1999.
4 NYSEG Solutions, Inc., 85 FERC 61,342 (1998).
5 XENERGY, Inc., 79 FERC 61,303 (1997); Carthage Energy, LLC, 87 FERC
62,313 (1999); Energy East South Glens Falls, LLC, 86 FERC 61,254 (1999); and
NYSEG Solutions, Inc., 85 FERC 61,342 (1998).
4
<PAGE>
158,000 customers in Connecticut. The proposed acquisition of Connecticut
Energy is subject to the approval of the Connecticut Department of Public
Utility Control ("CDPUC") and the Securities and Exchange Commission ("SEC").
Energy East also has reached an agreement to acquire CTG Resources, Inc.
("CTG Resources"), an exempt public utility holding company that owns
Connecticut Natural Gas Corporation ("CNG"). CNG is a local gas distribution
company that serves approximately 142,000 customers in Connecticut. It is
contemplated that both Connecticut Energy and CTG Resources will become
wholly-owned subsidiaries of Energy East. The proposed acquisition is also
subject to CDPUC and SEC approval.
B. CMP GROUP
CMP Group is an exempt public utility holding company headquartered in
Augusta, Maine. It became the holding company parent of Central Maine Power on
September 1, 1998.
1. CMP
CMP Group's principal subsidiary is CMP, Maine's largest electric utility,
which serves approximately 533,000 customers in central and southern Maine. CMP
has divested and/or relinquished control over substantially all of its
generating assets and purchase power contracts, and now functions as an electric
transmission and distribution utility.
CMP has sold its hydroelectric, fossil and biomass generating assets.
While CMP will retain ownership of its nuclear and NUG capacity, it is selling
its entitlement to purchase capacity and energy under the NUG contracts, as well
as its entitlements in two nuclear power plants (Millstone 3 and Vermont
Yankee), and its entitlement in a firm energy contract with Hydro Quebec,
pursuant to Maine electric utility restructuring legislation and the Maine
5
<PAGE>
Public Utilities Commission ("MPUC") Rules and Regulations.(6) As of March 1,
2000, CMP will not control any generation resources.
Also on March 1, 2000, all retail electric consumers in Maine will choose
their electric supplier. Since under Maine law, CMP would be able to serve only
a limited number of retail customers and would not be the supplier of last
resort, CMP has elected not to continue as a retail electric supplier. In the
future, CMP will be a "wires" only transmission and distribution utility.
As of December 31, 1998, CMP's delivery system comprised 2,293 miles of
overhead transmission lines, 19,438 pole-miles of distribution lines and 1,434
miles of underground submarine cable. CMP has high-voltage connections with
other electric systems at the New Hampshire and New Brunswick borders. CMP is a
member of the New England Power Pool ("NEPOOL") and has transferred control over
its pool transmission facilities ("PTF") system to ISO New England Inc.
("ISO-NE").(7)
CMP has market-based rate authority from the Commission.(8)
2. OTHER JURISDICTIONAL SUBSIDIARIES
Maine Electric Power Company, Inc. ("MEPCo") owns and operates a 345-kV
transmission interconnection between Wiscasset, Maine and the Maine-New
Brunswick international border at Orington, Maine, where its lines connect with
the portion of the interconnection constructed in the province of New Brunswick,
Canada, by The New Brunswick Power Corporation. CMP owns 78.3% of MEPCo's
common stock. The remaining voting stock of MEPCo is owned by two other Maine
electric utilities, Bangor Hydro Electric Company and Maine Public Service
Company. MEPCo provides service over its facilities pursuant to a
____________________
6 35-A M.R.S.A. 3204; and Chapt. 307 MPUC Rules and Regulations.
7 New England Power Pool, 79 FERC 61,374 (1997).
8 Central Maine Power Co., 80 FERC 61,246 (1997).
6
<PAGE>
non-discriminatory open access transmission tariff. Long-term transmission
capacity on MEPCo's facilities is fully reserved.
III.
DESCRIPTION OF THE PROPOSED MERGER
The terms of the proposed merger are set forth in the Merger Agreement,
which is included in Exhibit H of this Application. The Boards of Directors of
Energy East and CMP Group have approved the Merger Agreement. Pursuant to the
Merger Agreement, CMP Group is to become a wholly-owned subsidiary of Energy
East via a merger of a wholly-owned subsidiary of Energy East ("EE Merger
Corp.") with and into CMP Group. With minor exceptions, CMP Group will maintain
its current downstream corporate structure.
The proposed merger will be a stock purchase transaction. Subject to
regulatory and shareholder approvals, Energy East will purchase all common
shares of CMP Group for $29.50 per share, for a total cash value of $957
million. Energy East also will assume approximately $271 million of CMP Group
preferred stock and long-term debt.
The post-merger company will have total assets of approximately $6.4
billion and will serve approximately 1.6 million electric and gas customers at
the retail level.(9) NYSEG and CMP will continue to be headquartered in their
existing locations and operate under their existing names. Energy East will
establish a new corporate office in Portland, Maine.
IV.
THE PROPOSED MERGER IS CONSISTENT
WITH THE PUBLIC INTEREST
Section 203 of the FPA requires the Commission to approve a public
utility's disposition of jurisdictional facilities valued in excess of $50,000
if the Commission finds that the proposed disposition is consistent with the
____________________
9 These statistics do not include Energy East's proposed acquisition of
Connecticut Energy or CTG Resources.
7
<PAGE>
public interest.(10) The Commission has found that a proposed merger between
public utility holding companies results in the disposition of downstream
jurisdictional facilities when there is a direct or indirect transfer of control
over any of those facilities.(11) In the proposed merger, there will be no
direct or indirect transfer of control over the jurisdictional facilities of any
Energy East subsidiary. The proposed merger between Energy East and CMP Group,
however, will involve the indirect transfer of control over the jurisdictional
facilities of CMP and MEPCo. Accordingly, the proposed merger invokes the
Commission's jurisdiction under Section 203 over the disposition of the
jurisdictional facilities of CMP and MEPCo.
The Commission's approval of a proposed merger under Section 203 requires a
finding that the transaction "will be consistent with the public interest."(12)
In its Merger Policy Statement, the Commission identified three primary factors
for evaluating the public interest standard under Section 203: (1) the effect
of the proposed merger on competition; (2) the effect of the proposed merger on
rates; and (3) the effect of the proposed merger on regulation.(13) The
proposed merger is consistent with the public interest because it satisfies each
of the three primary factors identified by the Commission in its Merger Policy
Statement. The proposed merger will have no adverse effect on competition,
rates or regulation.
____________________
10 16 U.S.C. 824b(a) (1994) ( "No public utility shall sell, lease, or
otherwise dispose of the whole of its facilities subject to the jurisdiction of
the Commission, or any part thereof of a value in excess of $50,000, 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 soAfter 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.").
11 Enova Corp. and Pacific Enterprises, 79 FERC 61,107, at 61,494 (1997).
12 16 U.S.C. 824b(a) (1994).
13 Inquiry Concerning Commission's Merger Policy Under the Federal Power Act:
Policy Statement, III FERC Stats. and Regs. 31,044 at 30,111-12 (1996)
("Merger Policy Statement").
8
<PAGE>
A. THE PROPOSED MERGER WILL NOT ADVERSELY AFFECT COMPETITION
Attached to this Application as Attachment A is an affidavit from J.
Stephen Henderson, an economist and Vice President of PHB Hagler Bailly. Mr.
Henderson reviews the competitive effects of the proposed merger consistent with
the guidelines of the Merger Policy Statement and the pending Merger NOPR.(14)
Mr. Henderson's analysis reviews both the horizontal and the vertical effects of
the proposed merger, and he concludes from his analysis that the proposed merger
will have no adverse impact on the competitiveness of electricity markets.
1. HORIZONTAL MARKET POWER
Mr. Henderson defines the relevant geographic market for the proposed
merger as the combined NYISO and ISO-NE control areas because this is the
smallest area that contains a potential horizontal overlap in the electricity
generation market.(15) Mr. Henderson defines the relevant product markets as
energy and short-term capacity, which he refers to collectively as the "energy
product,"(16) and he uses the installed capacity measure to analyze the
competitive effects of the proposed merger in the relevant markets.
Specifically, Mr. Henderson analyzes installed capacity market shares and
concentration levels in four periods: 1998-1999 Winter; 1999 Summer; 1999-2000
Winter; and 2000 Summer. The first period (1998-1999 Winter) represents a
period prior to the Applicants' divestiture activities and prior to the merger.
The analysis of this hypothetical past period shows that the Herfindahl
Hirschman Index ("HHI") levels and changes in HHIs are below the safe harbor
____________________
14 Revised Filing Requirements Under Part 33 of the Commission's Regulations,
IV FERC Stats. and Regs. 32,528 (1998) ("Merger NOPR").
15 Henderson Affidavit at 12.
16 Id. at 10.
9
<PAGE>
thresholds identified in the Merger Policy Statement. Thus, a consolidation of
the generation assets of the two companies even before they had divested their
generation assets would have had an insignificant effect on competition.(17)
Mr. Henderson's analysis of subsequent time periods indicates that the
proposed merger will have no adverse impact on competition. The 1999 Summer
period represents a hypothetical current period following consummation of the
merger but prior to CMP's divestiture of all generation assets (which will occur
no later than March 2000). The HHI screening results of this analysis are still
below the safe harbor thresholds.(18) The 1999-2000 Winter period represents a
hypothetical interim period between consummation of the merger and CMP's
completion of divestiture.(19) The 2000 Summer period is the most representative
period for viewing the effects of the proposed merger. Because CMP's
divestiture must be completed by March 2000, the merger, for all practical
purposes, will not combine generation assets. CMP will not control any
generation resources and the merger produces no change in market shares for the
Applicants and no change in HHIs.(20) Thus, the proposed merger would have no
effect on competition after March 1, 2000.
Mr. Henderson concludes from his horizontal market power analysis that the
proposed merger would have no significant impact on any horizontal electric
generation market even during the interim period before CMP completes its
divestiture activity.(21)
_____________________
17 Id. at 14. (The post-merger HHI for this hypothetical past period is 836
and the change in HHIs is 35.)
18 Id. (The post-merger HHI is 618 and the change in HHIs is 31.)
19 Id. at 15. This hypothetical period would represent a real situation only
if the merger is consummated prior to CMP's completion of divestiture. (The
post merger HHI is 529 and the change is HHIs is approximately 28.)
20 Id. (The post-merger HHI is 513 and the change in HHIs is 0.)
21 Id.
10
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2. VERTICAL MARKET POWER
In his vertical market power analysis, Mr. Henderson follows the three-step
analytical approach described in the Merger NOPR by: (1) describing the
relevant product and geographic markets in the upstream and downstream markets;
(2) evaluating the competitive conditions in the upstream market and the effect
of the proposed merger; and (3) evaluating the competitive conditions in the
downstream market and the effect of the proposed merger.
Mr. Henderson defines the upstream product market as delivered natural gas,
which consists of delivering gas supplies from gas-producing regions and remote
storage facilities into the market area. He defines the upstream geographic
market as one that coincides with the downstream geographic markets defined in
the horizontal market power analysis.(22) Energy East, through its affiliates,
operates upstream natural gas local distribution companies ("LDCs") and related
natural gas operations in New York and New England, but these businesses do not
include any interstate natural gas transportation assets.(23) The electric
generating capacity associated with natural gas delivered and sold to generators
in New York and New England by Energy East's LDC affiliates totals 1,712 MW. In
his vertical market power analysis, Mr. Henderson assigns this capacity to the
Applicants.
Although CMP does not have any upstream natural gas operations, it does
participate in a joint venture with Energy East to build a natural gas delivery
______________________
22 Id. at 19.
23 For analytical purposes, Mr. Henderson treats Connecticut Energy
Corporation and CTG Resources, Inc. as if they were current subsidiaries of
Energy East. Thus, the gas operations of these companies are accounted for in
the vertical market power analysis.
11
<PAGE>
system in Maine. The joint venture anticipates serving an 540 MW generator in
the Summer of 2000. Mr. Henderson assigns this capacity to the Applicants, as
well.(24)
Mr. Henderson does not conduct a detailed analysis of the competitive
conditions in the upstream market for delivered gas in the New York and New
England area because his analysis of the competitive conditions in the
downstream market demonstrates that there is no concern about raising rivals'
costs. Moreover, the merger does not increase the vertical market integration
of any market and no downstream generator will become affiliated with its gas
transportation provider as a result of the merger.(25) Because CMP will have no
downstream generation assets after March 1, 2000 that could potentially benefit
from raising the production costs of rival gas-fired generators (even assuming
that the Applicants had the ability to raise such costs), Mr. Henderson
concludes that there is no possibility that the merger would result in vertical
market power that could benefit CMP.(26)
Mr. Henderson also concludes that the Applicants would be unable to
exercise vertical market power to benefit NYSEG in the downstream market, even
though his analysis includes a number of very conservative assumptions. For
example, he attributes to the Applicants all of the 2,252 MW of downstream
generating capacity associated with gas-fired generation or dual-fired
______________________
24 Id. at 22. Thus, the total amount of rival generating capacity assigned to
the Applicants is 2,252 MW (1,712 MW plus 540 MW).
25 Mr. Henderson notes that the merger will combine the holdings of the LDC
segment of the upstream market by an insignificant amount and that the firm
transportation rights on interstate natural gas pipelines held by the
Applicants' LDC operations are a small portion of the total firm pipeline
capacity available in the relevant market. Thus, the Applicants' LDCs could not
manipulate the price of delivered natural gas. Id. at 20-21.
26 Id. at 22.
12
<PAGE>
generators that are served by LDCs affiliated with the Applicants, even though
the LDCs would appear to have little or no ability to raise fuel costs to these
generators.(27) Moreover, these rival generators are located in New England,
while NYSEG's generation is located in Western New York. Energy East affiliates
supply gas to only a few generating plants in New England, principally in
Connecticut, and it is unlikely that the affiliated LDCs could affect downstream
electricity prices in New England or Western New York.(28) Moreover, due to
NYSEG's divestiture of generation and the nature of its remaining native load
commitments, NYSEG would receive little, if any, benefit from higher electricity
prices in New England or Western New York (even assuming that the affiliated
LDCs could affect prices).(29)
Mr. Henderson nevertheless calculates HHIs for the downstream market in his
vertical market power analysis for the four time periods defined earlier. The
results in all four periods are below the safe harbor thresholds and indicate
that the downstream market is unconcentrated in all four time periods.(30)
3. BARRIERS TO ENTRY
Finally, Mr. Henderson finds that the proposed merger would not create
entry barriers. The merger does not augment the control of upstream inputs to
the production of electricity in the relevant market and new entrants can choose
locations to build new power plants that are served by any gas pipeline in the
region.(31)
______________________
27 Id. at 22-24.
28 Id. at 24.
29 Id. at 26-27.
30 Id. at 28-29.
31 Id at 30.
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B. THE PROPOSED MERGER WILL NOT HAVE AN ADVERSE EFFECT ON RATES
The Merger Policy Statement identifies ratepayer protection as an important
factor in the Commission's evaluation of a proposed merger's consistency with
the public interest.(32) The concern is with any potential for an increase in
rates resulting from a proposed merger. Thus, the focus is on jurisdictional
ratepayers of the merging public utilities that pay rates based on costs. The
Commission has stated that it does not have ratepayer protection concerns with
respect to entities, such as power marketers, that make sales only under
market-based rate schedules.(33)
NYSEG, CMP and MEPCo are the only public utility subsidiaries of Energy
East and CMP Group that will provide service under cost-based rate
schedules.(34) Neither CMP nor MEPCo has any wholesale requirements power sales
customers. NYSEG has no full wholesale requirements customers, but does make
power sales to three small wholesale customers under cost-based rate schedules.
These include: sales to Burlington Electric Department (approximately 7 MW);
Vermont Public Power Supply Authority (approximately 7 MW); and Massena Electric
Department (approximately 15 MW). None of these customers is located on, or
interconnected to, NYSEG's electric system, or is otherwise
transmission-dependent upon NYSEG. The rates for all three customers were
negotiated at arm's length and will be completely unaffected by the merger.
The Applicants commit to hold wholesale customers harmless from the effects
of the merger by excluding all merger transaction-related costs, including the
acquisition premium, from rates for transmission service and wholesale power
sales. Thus, the merger will have no effect on rates.(35)
______________________
32 Merger Policy Statement at 30,123.
33 Enron Corp., et al., 78 FERC 61,179 (1997) (Enron).
34 MEPCo is a partially-owned subsidiary of CMP.
35 New England Power Co., et al., 87 FERC 61,287 at 62,146 (1999); and
PacifiCorp, 87 FERC 62,152 (1999).
14
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C. THE PROPOSED MERGER WILL NOT IMPAIR EFFECTIVE REGULATION
In its Merger Policy Statement, the Commission stated that, in the context
of mergers that involve registered public utility holding companies, it will
require applicants either to abide by the Commission's policies on intra-system
transactions or the Commission will set the issue of the effect of the merger on
regulation for hearing.(36) The Commission was concerned with its potential
loss of authority to review costs incurred by intra-system, non-power transfers
within registered holding companies under Ohio Power Company v. FERC, 954 F.2d
779, 782-86 (D.C. Cir. 1992), cert denied, 498 U.S. 73 (1992). Energy East
expects to become a registered public utility holding company under PUHCA as a
result of its proposed merger with CMP Group. In accordance with the
Commission's Merger Policy Statement, the Applicants commit that, if Energy East
becomes a registered holding company, it will abide by the Commission's policies
regarding intra-system transactions.
D. THE PROPOSED ACCOUNTING TREATMENT IS REASONABLE
The proposed merger will be accounted for as an acquisition of CMP Group by
Energy East under the purchase method of accounting in accordance with generally
accepted accounting principles. The amount of goodwill recorded will reflect
the excess of the $957 million purchase price over the estimated net fair value
of assets and liabilities of CMP Group's utility and nonutility businesses at
the time of closing, plus Energy East's estimated transaction costs related to
the merger. The assets of CMP Group's unregulated subsidiaries will be revalued
to fair value, including an allocation of goodwill to the subsidiaries, if
appropriate. The remaining acquisition premium will be allocated to CMP and
will be recorded as an acquisition adjustment on CMP's books, in Account 114,
Electric Plant Acquisition Adjustments, consistent with the Uniform System of
Accounts.
______________________
36 Merger Policy Statement at 30,125.
15
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V.
THE APPLICANTS COMMIT TO ELIMINATE MULTIPLE CHARGES WITHIN THEIR CONTROL FOR
TRANSACTIONS OVER BOTH OF THEIR SYSTEMS
The Commission has often required merger applicants to file single system
transmission tariffs for non-discriminatory access over the merged transmission
system.(37) As discussed previously, CMP has transferred operational control of
its transmission facilities to the ISO-NE and NYSEG has committed to transfer
operational control of its transmission facilities to the New York ISO. Because
control of these facilities is no longer in the hands of the Applicants, the
Applicants are not in a position to commit to offering service over their
combined transmission facilities under a single system transmission tariff.
Although NYSEG and CMP are not directly interconnected, the New York ISO and the
ISO-NE are directly interconnected, and trade across the two systems is
significant. The two ISOs also coordinate many of their activities to ensure
reliable interregional operations and to encourage robust competitive markets by
simplifying interregional transactions. It would not be in the public interest
for NYSEG and CMP to withdraw their facilities from the operational control of
their respective ISOs in order to combine those facilities under a NYSEG/CMP
single system tariff, particularly since the interregional activities of the two
ISOs effectively integrates transmission service. Moreover, withdrawal of the
transmission facilities of NYSEG and CMP from the control and operation of their
respective ISOs would be inconsistent with the Commission's policy goal of
promoting independent regional transmission organizations.
______________________
37 E.g., Consolidated Edison, et al., 86 FERC 61,242 (1999). The Commission
has not imposed such a requirement on merging utilities that are neither
directly interconnected nor have plans to become directly interconnected.
Sierra Pacific Power Co. and Nevada Power Co., 87 FERC 61,077 (1999); and WPS
Resources, 83 FERC 61,196 (1998). NYSEG and CMP are not directly
interconnected nor have plans to become directly interconnected.
16
<PAGE>
The Applicants have developed a proposal that will, in effect, further
integrate their two transmission systems without disrupting the current
operations of the New York ISO and ISO-NE or the carefully constructed ISO
tariff mechanisms that are in place. To the extent that NYSEG and CMP are able
to assess charges for transactions that use both of their transmission systems,
the Applicants will eliminate the effects of one of the two system charges. By
ensuring that customers who use both the NYSEG and CMP transmission systems are
not required to pay these multiple transmission charges, the Applicants proposal
will serve the purpose behind the Commission's policy of requiring merger
applicants to file single system tariffs, but it will do so without disturbing
current regional ISO operations or tariffs.
The joint affidavit of Messrs. Steven S. Garwood, Managing Director of
Transmission Operations for CMP, and Jeffrey L. McKinney, Manager of
Transmission Services & Policies in the Energy Department of NYSEG, included as
Attachment B to this Application, describes the transmission operations of each
utility, including operations that are under the direct control of their
respective ISOs. The joint affidavit describes the Applicants' proposal to
ensure that transmission customers using both the NYSEG and CMP transmission
systems are not assessed multiple charges by the Applicants.
Operational control of all New England utilities' Pool Transmission
Facilities ("PTF"), including those of CMP, are under the operational control of
ISO-NE, and service over those facilities can be obtained pursuant to the NEPOOL
Open Access Transmission Tariff ("OATT"). New England utilities, including CMP,
directly provide transmission service over their non-transferred facilities,
i.e., their non-PTF system, under the terms of their individual OATTs. CMP's
17
<PAGE>
OATT provides for Regional Network Service and Local Point-to-Point Service
("Local PTP").(38)
Unlike New England utilities, New York utilities will not offer any new
transmission service under their individual OATTs once the New York ISO becomes
operational.(39) Transmission service within the NYISO control area will be
subject to a single zonal rate equal to the Transmission Service Charge ("TSC")
of the utility on whose system the energy is withdrawn or on whose system the
energy is wheeled out of or exported from the NYISO control area. Thus,
wheeling to loads within NYSEG's service territory will be subject to NYSEG's
TSC. Transmission service for exports of power out of the NYISO control area or
wheels through the NYISO control area will be subject to the non-pancaked TSC of
each system at which the energy exists the NYISO control area in accordance with
the NYISO's determination of power flows over each transmission owners'
facilities that comprise the interface where the power is exported. NYSEG does
not own any of the tie lines that comprise the New York-to-New England
interface. NYSEG does own a portion of the NYISO-to-PJM interface. Thus, NYSEG
will receive a portion of the revenues associated with exports from NYISO to
PJM, but will not receive any revenues associated with exports from NYISO to
ISO-NE.(40)
Messrs. Garwood and McKinney identify three situations in which a wheeling
transaction originating from a generator located on CMP's non-PTF system could
be assessed charges by both NYSEG and CMP: first, if the generator were to
wheel power to a wholesale load located on NYSEG's system; second, if the
generator were to wheel power to a retail load located in NYSEG's service
territory; and third, if the generator were to wheel power through NYSEG's
system to PJM. Under each of these scenarios, the generator would be assessed
______________________
38 Garwood/McKinney Affidavit at 3-4.
39 The NYISO is expected to become operational this month.
40 Id. at 4-5.
18
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CMP's Local PTP charge, as well as NYSEG's TSC. As explained in the joint
affidavit, the Applicants commit that, upon consummation of the merger, they
will eliminate the applicable CMP Local PTP charge either by direct waiver of
that charge under the CMP Local OATT or by implementing a billing credit such
that NYSEG will charge no more than its full TSC less an amount equal to the
Local PTP charge applicable under the CMP OATT.(41) There are no other
transactions that would be assessed both a CMP Local PTP charge and a NYSEG TSC.
For transactions from NYSEG subtransmission facilities (i.e., NYSEG facilities
----
that are not operationally controlled by the New York ISO) to CMP non-PTF
facilities, no modification are required because transmission customers will not
have to pay a NYSEG transmission service charge.(42)
VI.
INFORMATION REQUIRED BY PART 33
In support of this Application, the Applicants submit the following
information required by Section 33.2 of the Commission's regulations.
A. THE EXACT NAME AND ADDRESS OF THE PRINCIPAL BUSINESS OFFICES.
(SECTION 33.2(A))
Energy East Corporation CMP Group, Inc.
1 Canterbury Green, 4th Floor 83 Edison Dr.
Stamford, CT 06901 Augusta, ME 04336
______________________
41 Id. at 6.
42 Pursuant to the New York ISO Tariff, transmission through or from the New
York ISO control area is subject to the TSC of the transmission provider(s) on
whose system(s) the energy exits the control area. Because NYSEG does not own
or control any transmission facilities that are part of an interface with the
ISO-NE control area, NYSEG's TSC would not be applicable to transactions from
NYSEG's subtransmission facilities to CMP non-PTF facilities. Id. at 7.
19
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B. NAME AND ADDRESS OF PERSONS AUTHORIZED TO RECEIVE NOTICE AND
COMMUNICATIONS WITH RESPECT TO THE APPLICATION. (SECTION 33.2(B))
1. ENERGY EAST
Kenneth M. Jasinski, Esq. Adam Wenner, Esq.
Executive Vice President Becky Bruner, Esq.
Energy East Corp. Vinson & Elkins, LLP
1 Canterbury Green, 4th Floor 1455 Pennsylvania Ave., N.W.
Stamford, CT 06901 Washington, D.C. 20004
607-762-4315 (phone) 202-639-6533 (phone)
607-762-4345 (fax) 202-639-6604 (fax)
[email protected] [email protected]
[email protected]
Stuart Caplan, Esq.
Huber Lawrence & Abell
605 3rd Avenue, 27th Floor
New York, New York 10158
(212) 455-5505 (phone)
(212) 661-5759 (fax)
[email protected]
2. CMP GROUP
Arthur W. Adelberg, Esq. Richard M. Lorenzo, Esq.
Executive Vice President Huber Lawrence & Abell
CMP Group, Inc. 1001 G Street, N.W.
83 Edison, Dr. Washington, D.C. 20001
Augusta, ME 04336 202-737-3880 (phone)
(207) 621-3954 (phone) 202-737-6008 (fax)
(207) 621-4526 (fax) [email protected]
[email protected]
C. DESIGNATION OF THE TERRITORIES SERVED BY COUNTIES AND STATE.
(SECTION 33.2 (C))
The counties and states, or portions thereof, which are served by NYSEG and
CMP are listed in Attachment C to this Application.
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. (SECTION 33.2(D))
This information is contained in Section II of this Application.
20
<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.
(SECTION 33.2(E))
This information is contained in Section III of 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 OF THE OPERATING
FACILITIES OF THE PARTIES TO THE TRANSACTION. (SECTION 33.2 (F))
As explained in Section IV of this Application, the proposed merger between
Energy East and CMP constitutes a disposition of the jurisdictional facilities
of CMP and MEPCo. Following the consummation of the proposed merger, all
jurisdictional facilities shall be operated in substantially the same manner as
they are operated currently.
G. A STATEMENT 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 COSTS 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. (SECTION 33.2 (G))
The jurisdictional facilities of Energy East and CMP Group are and will
continue to be accounted for pursuant to the Commission's Uniform System of
Accounts. Original cost is the basis for the valuation of the utility plant in
service. Further detail is provided in the financial statements included in
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. (SECTION
33.2 (H))
The proposed merger is not expected to have any material effect on any
contract for the purchase, sale or interchange of electric energy. The
Applicants' commitment to ratepayers is discussed in Section IV.B. of this
Application.
21
<PAGE>
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. (SECTION 33.2(I))
The proposed merger is subject to the following regulatory approvals and
consents:
- - Approval by the Securities and Exchange Commission under PUHCA.
- - Consent by the Nuclear Regulatory Commission under the Atomic Energy Act
- - Filings with the Federal Trade Commission and the Antitrust Division of
the Department of Justice-under the Hart-Scott Rodino Antitrust Improvements Act
of 1976, as amended, and the expiration or early termination of the waiting
periods thereunder.
- - Approval by the Federal Communications Commission in regard to CMP's
ownership of microwave facilities.
- - Approval by the Maine Public Utilities Commission.
- - Approval by the Connecticut Department of Public Utility Control.
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. (SECTION 33.2 (J))
The facts relied upon to show that the proposed merger is consistent with
the public interest are set forth in this Application.
K. A BRIEF STATEMENT OF FRANCHISES HELD, SHOWING DATE OF EXPIRATION IF NOT
PERPETUAL. (SECTION 33.2(K))
The municipal franchises of NYSEG and CMP are set forth in Attachment D to this
Application.
L. A FORM OF NOTICE SUITABLE FOR PUBLICATION IN THE FEDERAL REGISTER, AS
WELL AS THE COPY OF THE SAME NOTICE IN ELECTRONIC FORMAT. (SECTION 33.2(K)).
A form of notice suitable for publication in the Federal Register is
contained in Attachment E to this Application and is also included in electronic
format on a 3 " diskette in WordPerfect 5.1 format.
22
<PAGE>
VII.
REQUIRED EXHIBITS UNDER PART 33
The exhibits required under Part 33 of the Commission's regulations are
attached as Exhibits A through I.
VIII.
PROCEDURAL MATTERS
Applicants respectfully request that the Commission approve the proposed
merger without hearing on the basis of the facts and analyses set forth in this
Application. This Application demonstrates that the proposed merger will not
have an adverse impact on competition, rates or regulation. The Applicants
intend to close the merger transaction by the end of June 2000.
IX.
CONCLUSION
For the reasons set forth in this Application, including all accompanying
testimony and exhibits, the Applicants respectfully request that the Commission:
(1) find that the proposed merger will not have an adverse effect on
competition, rates or regulation, and that this filing satisfies all applicable
requirements for authorization of the proposed merger under Section 203 of the
FPA and Part 33 of the Commission's regulations;
(2) approve the proposed merger and grant any and all other authorizations
or approvals incidental thereto that may be required;
(3) issue such approvals and related authorizations based on the information
set forth in this Application and pleadings, without hearing; and
23
<PAGE>
(4) waive any filing requirement or other regulation as the Commission may
find necessary or appropriate to allow this Application to be accepted for
filing and granted.
Respectfully submitted,
____________________________ _____________________________
Richard Lorenzo Adam Wenner
Huber Lawrence & Abell Becky Bruner
605 3rd Avenue, 27th Fl. Vinson & Elkins L.L.P.
New York, NY 10158 1455 Pennsylvania Avenue, N.W.
Washington, D.C. 20004-1008
Attorney for CMP Group, Inc.
Stuart Caplan
Huber Lawrence & Abell
605 3rd Avenue, 27th Fl.
New York, NY 10158
Attorneys for Energy East Corporation
October 1, 1999
24
<PAGE>
TABLE OF CONTENTS
VOLUME I: APPLICATION AND ATTACHMENTS PAGE
- ----------------------------------------- ----
I. INTRODUCTION 1
II. DESCRIPTION OF THE APPLICANTS 3
A. Energy East 3
1. NYSEG 3
2. Other Jurisdictional Subsidiaries 4
3. Significant Non-Jurisdictional Subsidiaries 4
B. CMP Group 5
1. CMP 5
2. Other Jurisdictional Subsidiaries 6
III. DESCRIPTION OF THE PROPOSED MERGER 7
IV. THE PROPOSED MERGER IS CONSISTENT WITH THE PUBLIC INTEREST 7
A. The Proposed Merger Will Not Adversely Affect Competition 9
1. Horizontal Market Power 9
2. Vertical Market Power 11
3. Barriers To Entry 13
B. The Proposed Merger Will Not Have An Adverse Effect On Rates 14
C. The Proposed Merger Will Not Impair Effective Regulation 15
D. The Proposed Accounting Treatment Is Reasonable 15
V. THE APPLICANTS COMMIT TO ELIMINATE MULTIPLE CHARGES WITHIN THEIR
CONTROL FOR TRANSACTIONS OVER BOTH OF THEIR SYSTEMS 16
VI. INFORMATION REQUIRED BY PART 33 19
VII. REQUIRED EXHIBITS UNDER PART 33 23
VIII. PROCEDURAL MATTERS 23
25
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IX. CONCLUSION 24
ATTACHMENT A: Affidavit of J. Stephen Henderson
ATTACHMENT B: Joint Affidavit of Steven S. Garwood and Jeffrey L.
McKinney
ATTACHMENT C: Territories Served
ATTACHMENT D: Municipal Franchises
ATTACHMENT E: Form of Notice
EXHIBIT A: Corporate Resolutions Authorizing Transaction
EXHIBIT B: Statements of Measure of Control or Ownership
EXHIBIT C: Balance Sheets and Supporting Plant Schedules
EXHIBIT D: Statements of Contingent Liabilities
EXHIBIT E: Income Statements
EXHIBIT F: Statements of Retained Earnings
VOLUME II: REQUIRED EXHIBITS UNDER PART 33
- ------------------------------------------------
EXHIBIT G: State and Federal Applications
EXHIBIT H: Agreement and Plan of Merger
EXHIBIT I: Maps of Interconnections and Areas Served
26
<PAGE>
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ENERGY EAST CORPORATION )
AND ) DOCKET NO. EC99-____-000
CMP GROUP, INC. )
AFFIDAVIT OF J. STEPHEN HENDERSON
INTRODUCTION
1. I am an economist and Vice President of PHB Hagler Bailly, Inc. ("PHB").
PHB, a subsidiary of Hagler Bailly, Inc., is an economics and management
consulting firm with U.S. offices in Cambridge, Massachusetts; Washington, D.C.;
Los Angeles, California; Palo Alto, California; and Boulder, Colorado.
Analyzing competition and pricing issues in regulated industries has been an
important focus of my professional experience. A more complete description of my
qualifications is included as Exhibit No. ___(JSH-1).
2. Energy East Corporation ("Energy East") and CMP Group, Inc. ("CMP
Group"), collectively the Applicants, announced their intention to merge on June
15, 1999. Energy East, through its subsidiary, New York State Electric & Gas
Corporation ("NYSEG"), provides energy services to electric and gas customers in
upstate New York. CMP Group, through its subsidiary, Central Maine Power
Company ("CMP"), serves electric customers in central and southern Maine.
3. The Applicants have asked me to analyze two principal issues. First,
does the proposed merger confer horizontal market power in any electricity
generation market? Second, does the proposed merger allow the combined firm to
exercise vertical market power from the upstream gas market to the downstream
electricity markets? My analysis of these issues is based on guidelines set
forth in the Commission's Merger Policy Statement, the Commission's Notice of
27
<PAGE>
Proposed Rulemaking on merger policy ("Merger Policy NOPR")(43) and recent
Commission orders addressing market power issues.
SUMMARY OF CONCLUSIONS
4. The proposed merger will not have any adverse impact on the
competitiveness of electricity markets. Neither the horizontal nor the vertical
effects of the merger will create any competitive concern in any electricity
market. Using appropriate measures of the Applicants' degree of vertical
control, the merger will have an insignificant impact on market concentration.
5. Energy East owns generation that is located in the control area operated
by the New York Independent System Operator ("NYISO"). It has gas distribution
assets in New York and New England. CMP currently owns generation in the
control area operated by the Independent System Operator of New England
("ISO-NE"); however, it will own or control no generation facilities after March
1, 2000 when its divestiture activity is completed. After that date, the
smallest geographic market containing either a horizontal or vertical effect of
the merger would be the combined area consisting of the NYISO and the ISO-NE,
which I have used as the relevant geographic market for this case.
HORIZONTAL EFFECTS
6. Exhibit __ (JSH-2) summarizes the competitive analysis for both the
horizontal and vertical issues in this case. Defining the relevant geographic
market as the region consisting of the NYISO and ISO-NE control areas, both
Applicants currently own or control only a small share of the generation assets.
After March 1, 2000, CMP will not own or control any generation assets and
Energy East will have only a small market share. Consequently, it is evident
that the merger will have no horizontal competitive effects at all after March
1, 2000, when the CMP generation divestiture has been completed. If the merger
______________________
43 Inquiry Concerning Commission's Merger Policy Under the Federal Power Act:
Policy Statement, III FERC Stats. and Regs. 31,044 (1996). ("Merger Policy
Statement"); and Revised Filing Requirements Under Part 33 of the Commission's
Regulations, IV FERC Stats. and Regs. 32,528 (1998) ("Merger NOPR").
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is consummated before then, there would be a short interim period between the
effective date of the merger and March 1, 2000 during which the merger would
result in a small consolidation of generation assets. For completeness, I have
examined the effect of the merger during this interim period. If such a period
were to occur, both Applicants together would have an 8.1 percent market share
(combining Energy East's 5.6 percent share with CMP's 2.5 percent share) and the
increase in the Herfindahl-Hirshman Index ("HHI")(44) due to the merger would be
insignificant, about 28 points. Accordingly, I conclude that the merger would
have no adverse effect on the competitiveness of any horizontal generation
market.
VERTICAL EFFECTS
7. I also examined the vertical effects of consolidating the Applicants'
upstream natural gas assets with their combined generating assets in the
downstream market. The issue is whether this vertical consolidation would
provide both the incentive and the ability for the merged firm to exercise
market power in the downstream electric generation market. In undertaking this
analysis, I have followed the guidance furnished by the Commission in its
reported decisions and the Merger Policy NOPR. Under this guidance, for
purposes of a vertical market power screening analysis, downstream market
concentration statistics should be calculated after assigning electric
generating capacity to each Applicant based on the upstream inputs supplied to
each unit.
______________________
44 HHIs are computed by calculating the market share of each firm in the
relevant market, squaring these market shares and summing them. A post-merger
HHI below 1000 represents a diluted market, and, regardless of the change in
HHI, the merger is deemed unlikely to have adverse competitive effects. A
post-merger HHI between 1000 and 1800 represents a moderately concentrated
market, and if the change in HHI is greater than 100, the merger potentially
raises significant competitive concerns. A post-merger HHI above 1800
represents a highly concentrated market, and if the change in HHI is greater
than 50, the merger potentially raises significant competitive concerns; if the
change in HHI exceeds 100, the merger is deemed likely to create or enhance
market power.
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8. Energy East, through its affiliates, has some upstream gas operations in
New York and New England. After March 1, 2000, CMP will have no downstream
generation assets that potentially could benefit from a strategy of raising
rivals' costs through higher delivered gas prices. Consequently, even assuming
that the Energy East affiliates with interests in gas operations had the ability
to raise upstream prices for generators in CMP's market, CMP could not benefit
from it because it will not own any generation after March 1, 2000.
9. CMP has no upstream gas facilities, although Energy East and CMP have
formed a joint venture, CMP Natural Gas ("CMPNG"), to provide natural gas
distribution service in Maine. Energy East has a 77 percent interest in the
joint venture, while CMP owns the remaining 23 percent. The joint venture
predates the announcement of the merger and is not a combination of the two
companies that results from the merger. That is, the joining together of these
two parties to provide gas distribution service in Maine is not a merger related
consolidation. But for the joint venture, it is clear that the merger of Energy
East and CMP would not augment either the ability or the incentive to exercise
vertical market power after March 1, 2000 because CMP, which will have no
downstream electric generation facilities after that time, would have no
interests in upstream gas delivery facilities. Consequently, any vertical
market power issues that could arise in this case are confined to two matters:
the interim period, if any, between the merger and March 1, 2000, and the
appropriate treatment of the joint venture in conjunction with the merger. As
discussed below, both of these matters have an insignificant impact on vertical
market power.
10. My analysis accounts for any potential vertical effects of the merger
during the interim period arising from the combination of the NYSEG and CMP
generation assets along with the downstream generation assets of rivals that
could be attributed to the Applicants due to the gas service provided by Energy
East subsidiaries. The vertical screening analysis proposed by the Commission
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demonstrates that the merger would not have any significant effect on vertical
market power during this interim period. The downstream market is competitive
and is not conducive to the exercise of market power. This conclusion is not
changed by attributing downstream capacity controlled by rivals to the
Applicants in instances where the Applicants provide upstream gas delivery
services.(45)
11. The analysis addresses the joint venture by attributing its downstream
generation similarly. It is currently anticipated that this joint venture will
serve the Westbrook facility (540 MW), scheduled to be in service the Summer of
2000. The attribution of this generation capacity to the Applicants, although
unrelated to the merger, has no material effect on the competitiveness of the
downstream market, which remains unconcentrated (HHI less than 1,000) after
accounting for the upstream service provided to Westbrook.(46)
DESCRIPTION OF FIRMS
12. Energy East is a holding company whose affiliates are energy delivery,
products and services companies providing services in New York, New Jersey,
Massachusetts, New Hampshire and Connecticut. Energy East affiliates deliver
electricity and natural gas to retail and wholesale customers in the Northeast.
Energy East's electric subsidiaries include NYSEG, an electric and gas
distribution company in New York. Earlier this year, NYSEG divested all of the
fossil-fired electric generating stations it owned (approximately 2,366 MW of
capacity) and entered into a contract to sell its 18 percent interest in Nine
Mile Point Unit 2 (205 MW) to AmerGen. NYSEG retains ownership in hydroelectric
facilities, non-utility generation ("NUG") contracts and contracts pursuant to
which the New York Power Authority ("NYPA") sells power to NYSEG. NYSEG owns
electric transmission facilities, is a member of the New York Power Pool
("NYPP") and has committed to transfer operational control of its transmission
facilities to the NYISO. The Commission conditionally approved the formation of
the NYISO on July 30, 1998. On January 27, 1999 the Commission conditionally
accepted the NYISO's proposed tariff, market rules and market-based rates. The
NYISO is expected to commence operation in October 1999. NYSEG, itself, has
market-based rate authority.
_________________________
45 The increase in the HHI of the imputed downstream market is less than 50
points in an unconcentrated market, which is below the threshold used by the
Commission as an indicator for further review.
46 The HHI of the imputed downstream market increases by 4 points in an
unconcentrated market. This is an insignificant competitive effect that does
not warrant further review under the Commission's guidelines.
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13. Energy East Solutions ("EES") formed South Jersey Energy Solutions, LLC,
a joint venture with South Jersey Industries, Inc, that markets electricity and
natural gas throughout the Mid-Atlantic to retail and wholesale customers.
Energy East has four affiliates with Commission-approved, market-based rate
authority: 1) XENERGY, Inc., which provides energy services, information
systems, and energy consulting services, which does not own, operate or control
any electric power generation, transmission or distribution facilities and does
not have any requirements customers; 2) Carthage Energy, LLC, a single asset,
exempt wholesale generator ("EWG"); 3) South Glens Falls, LLC, also a single
asset EWG; and 4) NYSEG Solutions, Inc., a natural gas and energy services
company, which does not own or control any generation or transmission
facilities. The two EWGs, Carthage and South Glens Falls, own and operate an
aggregate of 126 MW (winter rating) of generating capacity. The Commission has
determined that neither NYSEG nor its affiliates have generation market power.
14. Energy East's natural gas subsidiaries (other than NYSEG and EES)
include CMP Natural Gas ("CMPNG"), a joint venture with CMP. CMPNG is building
a natural gas distribution system to serve customers in Maine. In May 1999,
CMPNG began service in Windham, Maine, the first of 35 cities that the joint
venture is planning to serve. CMPNG is tapping two new natural gas pipelines
that run through Maine. (47) New Hampshire Gas, a subsidiary of Energy East,
operates a propane distribution system in Keene, New Hampshire. Energy East
anticipates that in the future, New Hampshire Gas will provide natural gas to
customers in New Hampshire.
15. Energy East recently entered into an agreement to acquire CTG Resources
("CTG"), the parent of Connecticut Natural Gas Corporation. CTG provides
natural gas and energy-related products and services in Connecticut. Energy
East also recently entered into an agreement to acquire Connecticut Energy
Corporation, parent of Southern Connecticut Gas Company, which provides natural
gas service in southern Connecticut. Seneca Lake Storage, Inc. ("SLSI"), a
subsidiary of Energy East, operates a high deliverability natural gas storage
facility in Watkins Glen, New York. The SLSI facility has a deliverability of
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465,000 Mcf/day and is connected to Consolidated Natural Gas Transmission
Company. SLSI is developing another high deliverability natural gas facility in
New York, capable of delivering 75,000 Mcf/day. This new facility will be
connected to Columbia Gas Transmission System.
16. CMP Group is a holding company whose principal business is CMP. CMP
serves electric customers in central and southern Maine. CMP owns transmission
facilities and is a member of the ISO-NE, which took over responsibility for the
operation of the New England Power Pool on July 1, 1997. In April, CMP sold its
hydroelectric, fossil and biomass generating assets to National Energy Holdings,
Inc. ("NEHI"). By March 2000, CMP will not own or control any generation
resources. Other CMP holdings include several real estate companies, Cumberland
Securities Corporation and Central Securities Corporation; NORVARCO, a joint
venture that owns a static var compensator facility; CNEX, a firm that provides
consulting services and related products worldwide; MaineCom Services, which
provides a range of telecommunications services to retail, wholesale and carrier
customers; and Union Water-Power Company, which provides energy-related
consulting services, utility construction, real estate development, and
underground locating services. CMP owns a 78.3 percent interest in Maine
Electric Power Company ("MEPCO"), which owns and operates a 700 MW transmission
line between NEPOOL and New Brunswick. CMP also owns 2.5 and 4.0 percent
interests in the Millstone 3 and Vermont Yankee nuclear plants,
respectively.(48)
DEREGULATION IN NEW ENGLAND AND NEW YORK
17. In late 1996, the New York Public Service Commission ("NYPSC") issued
its decision to restructure the state's electric industry with the goal of
achieving a competitive wholesale market by 1997 and a competitive retail market
by 1998. Electric utilities in New York submitted restructuring plans, many of
which provided for divestiture of generation assets. In addition to NYSEG, four
other utilities have announced plans to divest generation or have completed
transfers of some of their generation (ConEd, Niagara Mohawk, Orange & Rockland
and Central Hudson Gas and Electric). Long Island Lighting Company sold its
______________________
47 Portland Pipeline and Maritimes & Northeast, Phase I.
48 The entitlement to the energy from these nuclear facilities will be
auctioned by CMP as part of the state of Maine restructuring requirements and
therefore, it is reasonable to conclude that this generation will not be
controlled by CMP after March 1, 2000.
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transmission and distribution assets to LIPA and merged into Keyspan, thereby
separating its transmission and generation assets.
18. The Maine legislature adopted an electricity restructuring plan on May
29, 1997 that provides for customer choice of power supplier beginning March 1,
2000. Under this law, all Maine electric utilities are required to divest their
generation resources by March 1, 2000.(49)
MARKET POWER ANALYSIS -- INTRODUCTION
19. Market power refers to the ability of a firm, or a group of firms, to
profitably increase prices by a small, but not insignificant, amount above the
competitive level in a sustained manner. In assessing the potential for an
applicant to exercise market power, it is appropriate to review the
concentration in relevant markets and to assess whether entry barriers exist
that could prevent or hinder firms from entering the market.
20. Horizontal market power refers to the ability to sustain a price
increase above the prevailing level on the part of a single firm or group of
firms at the same level of production (i.e., firms with a horizontal
relationship to one another). Horizontal market power generally arises in
situations where a firm, or a group of firms, is able to withhold supply and
thereby increase the market price.
21. Vertical market power refers to the ability of an integrated firm, i.e.,
one with a position in both an upstream and downstream market, to take actions
at one level of the production chain to adversely affect prices or output at
another level. For example, a potential action that would raise the costs of
downstream rivals in obtaining supplies of inputs from upstream markets could
raise a vertical market power concern.
______________________
49 Elsewhere in New England, full customer choice began in Massachusetts on
March 1, 1998; several Massachusetts utilities have divested generation assets.
In Connecticut, as of January 1, 2000, up to 35 percent of peak load of each
rate class in certain municipalities may choose their electric suppliers; there
will be full customer choice in Connecticut by July 1, 2000. In New Hampshire,
government officials expect to begin customer choice in early 2000. In Rhode
Island, customer choice will occur within three months after retail access
becomes available to 40 percent of customers (measured by energy sales) in New
England. Vermont has not yet adopted customer choice.
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22. Market power can only be exercised successfully if competition from
alternative suppliers is limited, including competition from potential suppliers
that could otherwise enter the market in response to a significant increase in
the market price. Only under these conditions would an attempt to raise the
market price be sustainable. In a vertical context, firms that have the ability
to exercise market power may not have an incentive to do so since they may face
a trade-off between the costs and benefits of a market power strategy. For
example, a firm attempting to exercise vertical market power could suffer
financial losses in its upstream natural gas supply operations if it attempted
to increase the price of gas in order to profit from higher electricity prices
that would accrue to its downstream generating asset.
HORIZONTAL MARKET POWER
23. There are five steps involved in assessing horizontal market power: (1)
identify the relevant product market; (2) identify the relevant geographic
market; (3) identify potential suppliers of each product in the relevant
geographic market; (4) assess market concentration, and (5) assess competitive
effects, including future entry conditions.(50)
24. In mergers involving significant amounts of generation, the Commission
requires a market analysis based on the guidelines in Appendix A of the Merger
Policy Statement. If the merger involves a de minimis overlap of generation
operations, the Commission has indicated that Applicants need not file a full
Appendix A study, but rather can provide an analysis showing that the merger
would have only insignificant competitive effects.(51) As shown below, the
proposed merger has de minimis effects in all electricity markets. Although, I
______________________
50 In the Merger Policy Statement, the FERC adopted the DOJ/FTC Merger
Guidelines for measuring market concentration levels by the Herfindahl-Hirschman
Index ("HHI").
51 Merger Policy NOPR, at 33,375.
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do not provide a "full" Appendix A analysis, my study covers all five steps
required to assess the effects on competition in electric power markets.
RELEVANT PRODUCT MARKETS
25. Under the Merger Policy Statement, the Commission is primarily concerned
with two measures of capacity -- economic capacity and available economic
capacity. These capacity measures are analyzed within the framework of a
delivered price test as set forth in Appendix A. From the facts of this case,
it is clear that there are no adverse competitive effects of the proposed merger
after March 1, 2000 because CMP will not own or control any generation
facilities after that date. Given that the only potential merger effects, if
any, would occur during the interim period between the effective date of the
merger and March 1, 2000, I have not conducted a "full" Appendix A study, but
rather have analyzed the competitive effects using an installed capacity
analysis. I believe this approach is adequate for demonstrating to the
Commission that the proposed merger would have no adverse competitive effects
even during the interim period.
26. Under the installed capacity approach, the Commission generally has been
concerned with two relevant products--energy and short-term capacity (one year
or less).(52) A market analysis of these two products generally is based on two
specific measures--installed capacity and uncommitted capacity. Installed
capacity has been used to measure a supplier's market share in the energy
product market on the grounds that all of a unit's capacity could be used to
produce energy, especially during off-peak periods. The uncommitted capacity
measure has been associated with the short-term capacity market shares on the
grounds that year-round capacity could be sold only from the uncommitted portion
______________________
52 The energy product has typically been described as energy and shorter-term
capacity, where shorter-term capacity has meant products such as weekly or
monthly capacity. This is shortened here to simply the energy product.
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of a unit's capacity. Long-term capacity is not addressed because the
Commission has concluded as a general matter that the potential for entry
ensures that the long-term capacity market is competitive.(53)
27. According to the Commission's recent approach to markets being
deregulated and in transition, the relevant product to be addressed in cases
involving electricity firms seeking market-based rates is installed capacity.
In EME Homer City, the Commission stated:
----------------
The Commission typically evaluates uncommitted capacity (the difference between
installed capacity and native load obligations, measured at the annual system
peak) as a separate product. Currently, all of Homer City's capacity is
uncommitted, while virtually all of the capacity owned by its competitors is
committed. However, retail competition programs in the PJM and New York markets
are premised on the release of native load obligations and the concomitant
release of capacity from committed to uncommitted. As retail access becomes a
reality, any capacity currently committed to serve the released retail loads
will become uncommitted as soon as the customer decides to switch. Rather, we
conclude that, in these circumstances (i.e., when the underlying market that is
being evaluated is transitioning to retail competition, and the applicant is
purchasing a divested generating unit that is currently used to serve native
loads), the installed capacity figure (discussed above) provides the more
relevant information about generation dominance. EME Homer City Generation,
--------------------------
L.P., 86 FERC 61,016 at 61,038-30 (1999).
-
28. The New York and New England markets fit the circumstances discussed by
the Commission in EME Homer City. These markets are in transition and it is
---------------
speculative to attribute uncommitted market shares to the market participants.
Therefore, in accordance with the Commission's guidance, my analysis of the
horizontal effects of this merger on energy and short-term capacity markets
focuses on the installed capacity measure, and does not address the market
details associated with the uncommitted capacity measure. I discuss the
uncommitted capacity implications in the geographic market studied by reference
to the detailed study of installed capacity. This approach is adequate to show
that the merger would have even smaller impacts on the short-term generation
capacity market (as measured by uncommitted capacity) than it would on the
energy market (as measured by total capacity).
______________________
53 Promoting Wholesale Competition Through Open Access Non-Discriminatory
Transmission Services by Public Utilities; Recovery of Stranded Costs by
Public Utilities and Transmitting Utilities, Order No. 888, FERC Statutes and
Regulations 31,036 at 31,657 (1996). ("Order No. 888").
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29. The Commission has concluded as a general matter that, in the absence of
control over sites and fuel delivery, the potential for entry ensures that the
long-term capacity market is competitive.(54) The Applicants do not control
generation sites that could be used to exclude competitors. Moreover, my
analysis of vertical issues indicates that the Applicants do not control the
delivery of natural gas in any way that would impact the competitiveness of
downstream electricity markets. Accordingly, I do not address long-term
capacity.
RELEVANT GEOGRAPHIC MARKET
30. To examine geographic markets, the Commission has focused on the
utilities that are directly interconnected with the Applicants. Each utility
directly interconnected to the Applicants is considered a destination market.
This destination market approach is reflected in the Merger Policy Statement and
in the Merger NOPR. Additionally, the Commission has suggested that utilities
that historically have been customers of the Applicants are also potential
destination markets.
31. In this case, NYSEG is a member of the NYISO and CMP is a member of
ISO-NE. The NYISO and ISO-NE are directly interconnected. All generation owned
or controlled by Energy East affiliates is in the NYISO control area. All
generation owned or controlled by CMP is within the ISO-NE control area. Since
the smallest area covering the generation assets of both NYSEG and CMP is the
combination of the NYISO and ISO-NE, I have used this area as the relevant
geographic market.
ASSESSING MARKET CONCENTRATION ANALYSIS IN ELECTRIC GENERATION MARKETS
32. The smallest geographic region that contains a potential horizontal
overlap in the electricity generation market is the combined NYISO and ISO-NE
______________________
54 Ibid.
-----
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area. In this market, neither Applicant currently has a significant amount of
generating capacities. NYSEG has recently divested 2,366 MW of its generation
to affiliates of the AES Company ("AES") and Edison Mission Energy ("EME").
NYSEG will purchase 1,424 MW of installed capacity back from AES through April
2001 and has the option of purchasing through April 2001 varying amounts of
installed capacity from EME, with the maximum that it can purchase tied to its
remaining native load obligations.(55) It has recently entered into an agreement
to sell its 18 percent share of Nine Mile Point Unit 2 nuclear facility (205 MW)
to AmerGen. Energy East affiliates recently purchased the Carthage and South
Glens Falls generating facilities in New York, consisting of a total of 126 MW
(winter rating). In summary, NYSEG and its affiliates own or control no more
than 3,504 MW of generating capacity in 1999 Summer and 3,631 MW of generating
capacity in 1999-2000 Winter. In the installed capacity analysis, I have
combined the generation owned by NYSEG and its affiliates along with the
transition contracts associated with the divested generation. Irrespective of
whether the sale of NYSEG's interest in Nine Mile Point Unit 2 occurs during the
periods analyzed, NYSEG's associated capacity remains unchanged because I have
attributed NYSEG's share of the plant's capacity to NYSEG based on the
transition contract. This information is summarized in Exhibit ___ (JSH-3).
33. CMP sold its 1,070 MW of hydroelectric, fossil and biomass generating
assets to NEHI, a wholly owned indirect subsidiary of FPL Group, Inc., on April
7, 1999. The sale was pursuant to a Maine law that mandated full divestiture of
generation assets and retail competition in electricity supply beginning on
March 1, 2000. At that point, CMP will not control any generation assets and it
will operate as a transmission and distribution company. CMP will purchase back
the output of these generation resources, but only through February 2000. In
summary, CMP controls 1,753 MW in the 1999 Summer period; 1,660 MW in the
______________________
55 NYSEG can purchase enough capacity from EME to serve half of its residual
load requirements (residual load minus NYSEG's total retained generation
resources).
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1999-2000 Winter period; and, it will control no generation in the 2000 Summer
period (after March 1, 2000). This information is summarized in Exhibit ___
(JSH-4).
34. Both NYSEG and CMP are winter peaking utilities. I cover four periods
in the installed capacity analysis--1998-1999 Winter, 1999 Summer, 1999-2000
Winter and 2000 Summer.(56) Exhibit No. __ (JSH-5) presents the market
concentration data for the 1998-1999 Winter period, which is prior to the
divestiture transaction closings of both NYSEG and CMP. This historical
information is presented for informational purposes only. It provides a useful
benchmark for comparing the effects of the merger against the actual divestiture
activity that has and will occur in the future. In this past period, the market
share of Energy East was about 6 percent, while CMP had a 3 percent share.
Their combined market share would have been 9 percent if the merger had been
completed during this time. In this period, the HHI was 801 with the two
companies as separate entities, and a merger during this time would have
increased the HHI to 836, which would have been a change of 35 points.
Consequently, a consolidation of the generation assets of these two companies
would have had an insignificant effect on market concentration even before the
generation divestiture had been completed.
35. Exhibit No. __ (JSH-6) presents the generation concentration data for
the 1999 Summer period, which is representative of current market conditions.
The analysis of this period reflects not only the generation asset divestitures
of both companies, but also the transition capacity purchase contracts. In this
period, Energy East's market share is about 6 percent, while CMP has a 3 percent
share. The combined entities would have a 9 percent share after the merger. In
the 1999 Summer period, the HHI is 587 prior to the merger, and 618 post-merger,
or a change of 31 points. I conclude from this analysis that the proposed
merger would not have a significant effect on the competitiveness of the
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relevant market since the increase in the HHI screening statistic is less than
the Commission's threshold for additional review.
36. Exhibit No. __ (JSH-7) presents the generation concentration data for
the 1999-2000 Winter period. This is the analysis that would be pertinent to
the interim period, if such a period exists, between the effective date of the
merger and March 1, 2000 when CMP's generation asset divestiture will be
completed. In this period, Energy East's market share of installed capacity is
5.6 percent, while CMP's share is 2.5 percent. The HHI during this period is
500 pre-merger and 529 post-merger, a change of over 28 points. Under the
Commission's guidelines, the proposed merger would not have a significant effect
on the competitiveness of the relevant generation market. The change in the HHI
is smaller than the lowest threshold used by the Commission to indicate a need
for further review. Moreover, the market itself is unconcentrated (the HHI is
less than 1,000) and the Commission ordinarily would not need additional review
in such circumstances.
37. For completeness, Exhibit No. __ (JSH-8) presents the generation
concentration data for the 2000 Summer period. Importantly, after March 1, 2000
CMP will not own or control any generation resources. As a result, the merger
will not result in any consolidation of generation assets after that time.
Consequently, the merged company's market share is the same as that of Energy
East by itself. In this period, Energy East's market share is 5.7 percent.
The HHI during this period is 513, indicating that the market in not
concentrated. Of course the merger does not have any impact on market
concentration in light of CMP's complete divestiture at that time. I conclude
from this analysis that the proposed merger would have no effect on the
competitiveness of any relevant generation market.
______________________
56 Winter is from November 1 to April 30; Summer is from May 1 to October 31.
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38. In summary, the proposed merger clearly has only a de minimis impact on
the horizontal market concentration of electric generation markets even during
the interim period before CMP and energy East complete their respective
divestiture activities. The increase in the HHI statistic is less than the
50-point standard used by the antitrust authorities as the smallest threshold to
determine whether additional review is needed. Moreover, the relevant market
itself is unconcentrated (the HHI is less than 1,000) in which case the
Commission ordinarily would not need further review even if the change in the
HHI were much larger. I conclude that the merger has no significant competitive
impact on any horizontal electric generation market.
39. This conclusion would not change materially if an Appendix A analysis
were conducted for the pre-March 2000 period. The most important matter that a
delivered price analysis would address differently than an installed capacity
analysis is the effect of transmission rates and limits on the definition of the
geographic market. To the extent that transmission limits the trade between New
York and New England, an Appendix A analysis most likely would find a smaller
merger effect than the installed capacity analysis I conducted.
VERTICAL MARKET POWER
40. The Commission has noted three potential competitive concerns regarding
vertical combinations: (1) Foreclosure / Raising Rivals' Costs; (2) Facilitating
Anticompetitive Coordination; and (3) Regulatory Evasion. The Commission also
has recognized that firms may have sound business reasons to vertically
integrate, including reduced transaction costs and other production cost
efficiencies. The Commission's competitive concerns, raising rivals' costs,
facilitating anticompetitive coordination and regulatory evasion, are addressed
as part of the analysis presented in this section.
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VERTICAL FORECLOSURE AND COORDINATION - ANALYTICAL METHODOLOGY
41. Foreclosure or raising rivals' costs refers to the situation in which a
vertically integrated firm withholds inputs that are produced by the upstream
portion of the firm from rivals in the downstream market. The goal of this
strategy is to increase the production costs of the downstream rivals so as to
increase downstream market prices and create an opportunity for increased
profits for the downstream portion of the firm.(57)
42. If the upstream supplier were to exercise market power in the upstream
input market after the merger, either unilaterally or in a coordinated manner,
the costs to the firm's rivals in the downstream market could be increased. Any
attempt to exercise vertical market power could not have anticompetitive
effects, however, if competitors in the downstream market have adequate
alternative sources of the input product. Moreover, such an attempt to raise
rivals' costs can be successful only if the upstream market is susceptible to
market power.
43. Concerns regarding the facilitation of anticompetitive coordination
arise if the combination of the merging parties either creates the ability of
the competing firms to agree to raise prices (or restrict output) or decreases
the incentive for firms to compete aggressively on price or service.(58) As
with foreclosure, whether this is an issue depends upon the competitive
conditions in both the relevant upstream and downstream markets.
44. The Commission has set forth an analytical framework for assessing the
potential for vertical market power arising from a gas/electric combination in
the Enova/Pacific Enterprises merger and in its recent Merger Policy NOPR. These
guidelines require a three-step analysis:
- - For the upstream market, describe the relevant products and geographic
markets, and for the downstream electricity market, define the relevant products
traded by the merging firms and the relevant geographic markets in which these
products are traded.
______________________
57 The Commission has indicated that an upstream firm can exclude competitors
in a number of ways, including pricing, marketing, and other operational
actions. (Merger Policy NOPR at 33,376).
58 Id, at 33,376-77.
--
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- - Evaluate the current competitive conditions in the upstream market and the
effect of the contemplated merger on that market.
- - Evaluate the competitive circumstances in the downstream market and the
effect of the contemplated merger on that market.
45. As part of this third step, the Commission proposed a methodology to
analyze competitive conditions in the downstream electricity market, based on
the Commission's horizontal market power analysis discussed earlier. To perform
this analysis, a standard horizontal market power test is done; however, it is
assumed that a portion of the downstream electricity capacity is attributed to
the upstream input supplier. That is, applicants are instructed to conduct an
analysis assuming that whoever provides the fuel supply to a generation unit
potentially may control the unit, or otherwise be able to raise its fuel costs.
The resulting concentration statistics, measured using the HHI, should reflect
this upstream-to-downstream attribution.(59)
46. Moreover, applicants are to consider whether the proposed combination of
gas assets, operations and transactional activities could affect the price and
availability of downstream products. In doing so, the applicants must address
whether the merger would provide both the ability and the incentive to affect
the price or availability of gas to electric generators.
47. The Commission has emphasized that a strategy to raise rivals' costs
would be plausible only if both the upstream and downstream markets are
conducive to the exercise of market power.(60) That is, if either the upstream
______________________
59 In San Diego Gas & Electric Company,et al., 79 FERC 61,372 at 62,562
-------------------------------------------
(1997), the Commission referenced this methodology, stating that "[a]n indicator
of the ability of wholesale power purchasers to turn to capacity not served by
SoCalGas would be a statistic analogous to an HHI. Ideally, such a statistic
would be calculated on the basis of economic capacity served by SoCalGas and
economic capacity not served by SoCalGas." The Commission further describes
this methodology in its Merger NOPR at 33,380.
60 San Diego Gas and Electric Company, et al., 79 FERC at 62,561.
-------------------------------------------------
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or downstream market is competitive, rivals' costs most likely cannot be raised,
regardless of the competitive conditions in the other market.(61)
48. If the screening analysis suggests that both the upstream and downstream
markets are conducive to the exercise of market power, the Commission's
guidelines state that applicants can: (1) demonstrate that it would be
difficult to actually raise rivals' costs; (2) directly evaluate whether
customers of the upstream input supplier can readily switch to alternative
suppliers or inputs in response to any actions taken by the applicants' upstream
supplier; or (3) show that a strategy of raising rivals' costs would not be
profitable.(62)
49. Finally, if after considering all of these factors the merger still
raises competitive concerns, the Commission suggests applicants propose specific
mitigation measures, such as a code of conduct or restrictions on affiliate
transactions.
OVERVIEW OF THE ANALYSIS OF POTENTIAL VERTICAL MARKET POWER EFFECTS
50. In assessing potential vertical market power issues, it is important to
consider whether the Applicants have both electric generating assets that can
benefit from higher electric prices and natural gas resources that could be used
as part of the exercise of market power. That is, the merging companies must
have both the ability to raise rivals' costs (by controlling upstream gas
operations) and the incentive to do so (by owning downstream units that can
receive the higher prices).
THE COMMISSION'S ANALYTICAL FRAMEWORK
51. I have followed the Commission's three-step analytical approach
described above in conducting my study. For expositional purposes, the
following discussion is organized by discussing the analytical steps first for
the upstream market, and then for the downstream market.
______________________
61 For example, see Destec Energy, Inc. and NGC Corporation, FERC 61,373 at
---------------------------------------
62, 574 (1997).
62 Merger Policy NOPR at 33,381.
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COMPETITIVE CONDITIONS IN THE UPSTREAM MARKET
52. The relevant upstream product market is delivered gas, which consists of
delivering gas supplies from gas-producing regions and remote storage facilities
into the market area. This is the product used in prior Commission
decisions.(63) The relevant geographic regions coincide with the downstream
geographic markets discussed below. Energy East, through its affiliates, has
some upstream gas operations in New York and New England, although these do not
include any interstate natural gas transportation assets. It provides gas
delivery service within New York and it purchases natural gas under long-term,
short-term and spot contracts for sales to wholesale and retail customers. As
shown on Exhibit No. __ (JSH-9), Energy East affiliates deliver and sell natural
gas to electric generators in New York and New England. The capacity associated
with these generators total 1,712 MW. By comparison, CMP does not have any
upstream natural gas facilities or operations. However, the CMPNG joint venture
anticipates serving a 540 MW generator located at Westbrook, Maine in the Summer
of 2000. In my analysis of the downstream market, I have assigned this capacity
to each of the Applicants in proportion to their percentage interests in the
joint venture.
53. I have not conducted a detailed analysis of the competitive conditions
of the upstream market for delivered gas in the New York and New England area.
Such an analysis is not needed in order for the Commission to determine that the
merger would not increase the likelihood that the Applicants would exercise
vertical market power in either of the two ways discussed above (raising rivals
costs or facilitating anticompetitive coordination). My analysis of the
competitive conditions in the downstream market demonstrates that there is no
concern about raising rivals' costs. Similarly, the merger does not increase
the likelihood of anticompetitive coordination since the merger does not
increase the vertical integration in any market.
______________________
63 San Diego Gas & Electric Company,et al., 79 FERC at 62,561; and, NorAm
------------------------------------------- -----
Energy Services, Inc., 80 FERC 61,120 at 61,381 (1997).
- -----------------------
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54. Although I have not fully assessed the competitiveness of the upstream
market, a few facts about the upstream market are important to consider. First,
the merger itself clearly does not affect the interstate pipeline portion of the
upstream market in any important way since the Applicants do not own such
assets. The Applicants own Local Distribution Companies (LDCs) in New York and
New England. The merger will combine the holdings of the LDC segment of the
upstream market by only an insignificant amount. With the exception of CMPNG,
all of the LDCs are either currently owned or will be owned in the future by
Energy East. Even assuming that the merger results in a consolidation of CMP's
23 percent interest in CMPNG with the remainder of Energy East, this is a very
minor competitive effect. While these facts do not address the competitiveness
of the upstream market as an initial matter, they strongly support the
conclusion that the merger would not reduce competition.
55. Second, I have examined the firm transportation ("FT") rights on
interstate pipelines held by each of these LDCs as part of my review of this
merger. Currently, CMP does not hold FT on any interstate pipeline. The FT
rights held by each LDC are listed in Exhibit __(JSH-10). The amounts held are
a relatively small portion of the total firm capacity available in New York and
New England, which is shown in Exhibit No. ___(JSH-11). NYSEG holds about 6.5
percent of the firm transportation capacity available to supply New York.
Southern Connecticut Gas holds about 8.2 percent of the firm transportation
capacity available to supply New England. Connecticut Natural Gas Company holds
about 9.1 percent of the firm transportation capacity available to supply New
England. Collectively, these LDCs do not control a large enough share of the
New York and New England FT capacity to be able to manipulate the price of
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delivered gas. Moreover, the holdings of each LDC are consistent with what
would be expected from the size of their respective business. Exhibit No.
___(JSH-10) shows the peak demand for each of the three LDCs in relation to
their holdings of firm transportation rights.(64) Under such conditions, it
would be difficult for the Applicants to benefit from an upstream withholding of
FT rights on interstate pipelines because these FT rights are needed to support
the LDC's aggregate commitment to supply its end users.(65)
COMPETITIVE CONDITIONS IN THE DOWNSTREAM MARKET
1. RAISING RIVALS' COST STRATEGY - ABILITY ISSUES
56. After March 1, 2000, CMP will have no downstream generation assets that
potentially could benefit from higher delivered gas prices, even assuming that
Energy East affiliates had the ability to raise such prices. Accordingly, there
is no possibility that the merger would combine an upstream ability on the part
of Energy East to exercise vertical market power with a benefit to CMP from the
resulting higher price of delivered gas.
57. Energy East and CMP have formed a joint venture to provide natural gas
distribution service in Maine. The joint venture does not currently serve any
generation stations. However, as noted above, by Summer of 2000, CMPNG will
provide gas transportation to a 540 MW generator. It is highly unlikely that
the joint venture could be used to exercise vertical market power. Even
assuming that the joint venture provided the ability to raise rivals costs, the
Applicants will have no downstream power plants in New England that could profit
from such a strategy. Such a strategy would have been somewhat more plausible
before CMP had divested its generation assets, but certainly is not feasible in
the absence of any downstream assets in a relevant market.
LITTLE ABILITY TO FORECLOSE DOWNSTREAM RIVALS
______________________
64 Energy East has FT rights in excess of its peak demand because some of the
FT is used to access its storage facility and because last year's peak was lower
than expected due to an unusually warm winter.
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58. In the subsequent analysis that attributes downstream generation
capacity of rivals, I have attributed 2,252 MW to the Applicants on the grounds
that affiliated LDCs provide transportation service. This attribution
implicitly assumes that the Applicants could foreclose gas service to these
rivals or otherwise raise their delivered gas costs. In reality, the
attribution of 2,252 MW substantially overstates any ability of Energy East to
raise delivered gas costs to the particular rivals at issue here. A brief
review of the four largest current rivals (accounting for 1,548 MW out of the
total of 2,252 MW served) shows why:
- - Bridgeport (520 MW): This plant is served by Southern Connecticut Gas
("SCG") through an 11-mile lateral extension of its distribution system from the
Iroquois Pipeline. Although the gas flows through SCG's city gate, SCG would
have limited ability, if any, to affect service conditions to the plant along
such a direct connection. The plant's gas delivery is not limited by the
lateral extension itself, which has been sized to the plant's needs as an
initial matter. Gas pressure on the Iroquois Pipeline would affect deliveries
to the plant, but pressure on the SCG system could only indirectly affect the
plant through the Iroquois system.
- - Devon (401 MW): This plant is served by SCG through a short lateral
extension from the Iroquois Pipeline. The conclusion is similar - SCG would
have a limited ability, if any, to affect service conditions because of the
direct connection from Iroquois Pipeline to the plant. Moreover, the plant is
dual-fired and can burn fuel oil as well as natural gas, further limiting SCG's
ability to raise its fuel costs.
- - New Haven Harbor (466 MW): This plant is served by SCG through its system.
This plant is dual-fired and burns fuel oil as well as gas. The maximum
gas-fired output of the plant is about 186 MW, or about 40 percent of its
______________________
65 While such a behavior cannot be ruled out entirely, it is relevant to note
that state regulation would provide substantial protection against this and
other strategies that could be used to raise rivals' costs, such as cost
shifting.
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capacity. While SCG theoretically would have a greater ability to affect gas
deliveries to the New Haven Harbor facility than to the other two plants just
discussed, the amount of capacity at risk is significantly less than the plant's
total capacity, and even this capacity is dual-fired. These factors indicate
that SCG would have limited ability, if any, to raise fuel costs of the New
Haven Harbor facility.
- - Greenidge (161 MW): This plant is served by NYSEG. Greenidge is a
coal-fired plant that burns gas, especially at night, so as to reduce its NOx
emissions. Accordingly, it is not clear that the Greenidge plant should be
attributed to the Applicants as a gas-fired rival, since the plant's use of gas
is not as its primary source of fuel. The foreclosure of gas supply in this
instance might have the effect of reducing the plant's power output during the
night, which is an off-peak period in which competition is unlikely to be
limited by transmission constraints. Accordingly, prices in the downstream
electricity market would be largely unaffected by such a hypothetical
foreclosure of gas supply, even if such an action would be effective when used
against a coal-fired rival.
LITTLE ABILITY TO RAISE DOWNSTREAM PRICES SO AS TO BENEFIT NYSEG GENERATION
59. Even assuming that downstream rivals could be foreclosed, such a
strategy is not likely to succeed in raising downstream electricity prices that
could benefit the Applicants. This is because downstream electricity prices in
Western New York (where NYSEG has generation assets) would need to be increased
by actions of Energy East to raise rivals costs in New England, especially
Connecticut. A number of considerations argue against such a conclusion.
Importantly, gas is not currently an important source of fuel for electricity
production in New England. Moreover, the Energy East affiliates supply gas to
only a few power plants in New England and it is unlikely that they could affect
downstream electricity prices in New England.
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<PAGE>
60. Even if Energy East could raise delivered gas prices in New England,
such an action is not likely to raise downstream electricity prices in a
location that could benefit NYSEG's downstream assets in New York. This is
because of the West-to-East direction of the power flows at times when
transmission capacity is limited between New England and New York. With the
exception of its 62.5 MW South Glens Falls affiliate, all of NYSEG's downstream
assets are located in New York to the West of the Total East interface, which is
an interface within New York stretching from the Albany area to New York City.
This interface is regularly constrained from West to East, especially during
peak periods, reflecting the cheaper power available in Western New York.(66)
The three large rivals served by Southern Connecticut Gas (listed in Exhibit
__(JSH-9)), are located to the East of the New York-New England interface, which
itself is located to the East of the Total East interface. During peak periods,
NYSEG's downstream assets located in Western New York could not benefit from a
strategy of raising the costs of Connecticut rivals. This is because
transmission constraints would prevent the relatively low Western New York
electricity price from increasing in response to an increase in the higher New
England electricity price, even assuming that the New England price could be
raised in the first place. The Western New York price would be separated from
New England by two important transmission interfaces, both of which are likely
to be constrained during peak periods.(67)
______________________
66 While New York and New England are highly integrated with regular traffic
between the two control areas, transmission constraints will occur in New York
in peak load conditions. Even large utilities with a single operations center
occasionally must dispatch generation plants so as to relieve internal
transmission constraints.
67 The South Glens Falls facility would be separated from New England by the
New York-New England transmission interface only.
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61. The addition of a rival generating plant in Maine that will receive gas
service from CMPNG does not change these market dynamics in any material way.
Any increase in the price of electricity due to a strategy of raising rivals'
costs in Maine is not likely to propagate to Western New York during peak
periods for the reasons given above relating to the Total East interface and the
New York-New England interface.
62. At non-peak times when transmission capacity is available between
Western New York to New England, it is possible that an increase in the New
England electricity price would induce an increase in the Western New York
electricity price. In these circumstances, however, competition from New York
generators would help to defeat any attempt to raise New England electricity
prices, making a strategy of raising the costs of New England rivals implausible
in the first instance. Moreover, the gas-fired rivals in New England may not be
in the market in non-peak periods, further limiting the Applicants' ability to
raise rivals' costs at all.
2. RAISING RIVALS' COST STRATEGY - BENEFIT ISSUES
63. In order to assess whether a strategy of raising rivals' costs in New
England is a concern even in the narrow circumstances outlined above, I have
examined the potential benefit that NYSEG could receive from such a strategy in
accordance with the Commission's proposed guidelines.
64. NYSEG's divestiture of its generation assets and the nature of its
remaining native load commitments mean that NYSEG would receive little, if any,
benefit from higher electricity prices in New England and Western New York.
Exhibit __ (JSH-12) shows how NYSEG's owned capacity and long-term purchases
(2000 Summer) are divided among five categories. The exhibit indicates the
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<PAGE>
extent to which assets in each category potentially would benefit from higher
electricity prices. The only assets that potentially could benefit in both peak
and non-peak periods are 60 MW of hydro facilities and the 205 MW interest in
the Nine Mile Point Unit 2 nuclear plant.(68)
65. In peak periods, somewhat more of NYSEG's capacity potentially could
benefit from higher electricity prices including 60 MW of hydro power, 205 MW of
Nine Mile Point Unit 2, 99 MW of entitlement of the Gilboa pumped storage
facility, 117 MW (summer rating) of affiliate-owned peaking capacity, and 561
MW of NUG contracts(69), or a total of 1,042 MW that potentially could benefit
from higher electricity prices. This is a small amount of capacity remaining
under the control of a utility that had about 3,900 MWs prior to the New York
restructuring. Even this capacity most likely could not benefit from a strategy
of raising the costs of New England rivals because, as previously discussed,
higher prices in New England during peak conditions would not influence Western
New York prices due to transmission constraints.
66. Moreover, NYSEG currently cannot benefit from increased electricity
prices because a retail rate cap has been imposed by the NYPSC in connection
with the state restructuring plan. During the price cap period, retail customer
rates cannot be increased to recover increased supply costs.(70) Also during
this period, NYSEG's remaining native load commitment will be larger than the
total of its remaining generation and purchases. That is, NYSEG is a net buyer
during the transition.(71) As the Commission has recognized in other
______________________
68 The transition contracts with AES and EME covering 2,024 MW are for the
installed capacity product only and do not provide NYSEG with any claim for
energy. Hence, NYSEG cannot benefit from higher electricity energy prices. Of
course, the price of the installed capacity product itself cannot be manipulated
by the withholding of any upstream fuel supply since the installed capacity of a
plant does not depend on fuel availability under the New York ISO rules (or
those in other electricity markets to my knowledge).
69 These NUG (mostly Qualifying Facilities) purchase contracts have relatively
high prices. The three largest contracts, accounting for 83 percent of the
purchases have the following contract prices: 240 MW at 10.76 /kWh on-peak,
6.34 /kWh off-peak; 180 MW at 8.61 /kWh; and 50 MW at 6.0 /kWh.
70 If NYSEG's rate of return on equity drops below the floor of 9 percent, it
may petition the NYPSC for relief under the terms of its restructuring
settlement.
71 NYSEG's net load is forecast to be 2,238 MW in 2000 Summer. NYSEG will
have to purchase about 30 percent of requirements from the market. A strategy
to raise energy prices would not be profitable in such circumstances.
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proceedings, the incentives for a net buyer are reversed from those of a net
seller.(72) NYSEG potentially might have an incentive to lower electricity
prices, but as a net buyer it would have no incentive to raise them.
3. RAISING RIVALS' COST STRATEGY - ASSESSING THE COMPETITIVENESS OF THE
DOWNSTREAM MARKET
67. I have assessed the competitiveness of the downstream market in
accordance with the Commission's proposed guidelines. In doing so, I have
analyzed the potential vertical effects of the merger during the interim period
between the effective date of the merger and March 1, 2000, as well as the
period afterwards, represented by the Summer of 2000. My analysis accounts for
the downstream generation facilities receiving upstream gas service from Energy
East affiliates and the joint venture. It also includes the downstream
generation assets owned by NYSEG, and those owned by CMP during the interim
period. This analysis is conservative and overstates any potential effect due
to the merger for the reasons discussed above.
68. The results of this analysis are summarized in Exhibit No. __ (JSH-13),
which shows the imputed market shares and the imputed HHIs based upon owned and
assigned downstream capacity for each of the four periods used in the horizontal
analysis. The geographic market is defined as the control areas of the NYISO
and ISO-NE.
69. For the historical 1998-1999 Winter period, a period analyzed for
comparison purposes only, Exhibit ___(JSH-13) shows the details of the vertical
analysis. The imputed market share of Energy East was about 9 percent, and that
of CMP was about 3 percent. The imputed HHI for the overall market is 822. A
merger during this period would have resulted in a combined market share of 12
percent, and a HHI of 872. Given that the market is unconcentrated and the HHI
change is quite modest, no further review would have been warranted during this
period, even before the remaining divestitures.
______________________
72 Pacific Gas and Electric Company, et. al., 81 FERC 61,122 (1997).
-----------------------------------------------
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70. For the 1999 Summer period, Exhibit ___(JSH-14) shows the imputed market
share of both Applicants is somewhat smaller. Energy East's share is about 8
percent, while CMP has a 3 percent share. The imputed HHI is 609, which is
lower than the prior period due to divestiture activity of several owners of
generation in New York and New England. The merger of the Applicants, if it had
been completed during this period, would have resulted in a market share of
about 11 percent and the post-merger HHI would have been 655.(73) This analysis
reflects the increased competitive market structure that results from the
Applicants' divestiture activity and the fact that the Applicants' shares have
been reduced accordingly.
71. The 1999-2000 Winter period represents the interim period, if any,
between the merger and March 1, 2000. The results, in Exhibit ___(JSH-15), are
quite similar to those of the Summer 1999 period because only a small amount of
additional generation capacity will be divested during this time. The overall
market remains unconcentrated, with a post-merger HHI of 564.(74)
72. The 2000 Summer period incorporates two changes by comparison to the
previous period. The Summer of 2000 analysis reflects the completion of CMP's
divestiture of its generation assets, and assumes that CMPNG is serving the 540
MW Westbrook plant. The Westbrook capacity is assigned to the two Applicants in
this analysis according to their ownership shares in the CMPNG joint venture (77
percent for Energy East and 23 percent for CMP). As a result, Energy East's
imputed market share is about 9 percent, while that of CMP is less than 1
percent. The Applicants combined share is about 9 percent, and the post-merger
HHI is 551.(75) This imputed HHI indicates that the downstream market is
competitive and is not conducive to the exercise of market power. Under the
______________________
73 The merger would have increased the HHI by about 46 points during this time
frame, which is insignificant when compared to the thresholds in the
Commission's merger guidelines that are used to indicate a need for further
review.
74 The merger would have increased the HHI by about 41 points during this time
frame, which is insignificant when compared to the thresholds in the
Commission's merger guidelines that are used to indicate a need for further
review.
75 The merger would increase the HHI by about 4 points during this time frame,
which is insignificant when compared to the thresholds in the Commission's
merger guidelines that are used to indicate a need for further review. If the
CMPNG joint venture were omitted from the analysis, the change in the HHI due to
the merger would be zero since CMP would have a zero market share in the imputed
downstream market. This emphasizes that it is only the joint venture that has
created the appearance of a merger-related vertical effect in this case.
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Commission's guidelines, the Applicants are unlikely to be able to exert
vertical market power by raising rivals costs.
FACILITATING ANTICOMPETITIVE COORDINATION - VERTICAL INTEGRATION ISSUES
73. As the Commission has noted in its proposed guidelines for vertical
analyses, the issue of whether or not a merger increases the likelihood that the
parties would engage in anticompetitive coordination is addressed by assessing
the competitiveness of the upstream and downstream markets. If either the
upstream or the downstream market is sufficiently competitive so that it is not
conducive to the exercise of market power, the issue of anticompetitive
coordination does not need additional review. In this case, the downstream
market is clearly competitive, as indicated by the fact that the HHIs are less
than 1,000 in all time periods studied. Accordingly, the issue of
anticompetitive coordination does not require further review.
74. Moreover, the principle way in which a merger would raise the
anticompetitive coordination issue would be by creating vertical relationships
in a relevant market that did not exist prior to the merger, and which could be
used to coordinate behavior in ways not previously possible. In this case, the
proposed merger will not create any new vertical lines of business. That is,
there is no downstream electricity plant that will become affiliated with its
provider of gas transportation as a result of the merger. The vertical issue
arises in this case only because the Applicants provide upstream gas
transportation service to non-affiliated downstream rivals, a set of fuel supply
relationships that do not change as a result of the merger. Accordingly, there
is no additional degree of vertical integration between providers of gas
transportation service (in this case, LDCs) and individual electric power
plants. As such, the merger creates no mechanism for the Applicants to
facilitate anticompetitive coordination.
56
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CONCLUSION OF VERTICAL ANALYSIS
75. I conclude from this vertical market analysis that the proposed merger
does not raise any vertical market power issues in New York and New England.
The downstream market in the New York/New England area is competitive and is not
conducive to the exercise of vertical market power either through foreclosure or
anticompetitive coordination. All of the analytic screens produce changes in
the attributed market concentration that are less than the thresholds used by
the Commission to indicate the need for further review. In particular, the
imputed downstream market is unconcentrated after the merger confirming that a
strategy of raising rivals' costs through an exercise of vertical market power
in the New England/New York market would be difficult to implement in the first
instance. Moreover, a review of the location of the downstream rival power
plants in relation to those controlled by the Applicants indicates that it would
be difficult to implement a successful foreclosure strategy in New England that
could benefit NYSEG's assets in Western New York. Finally, while NYSEG controls
about 3,400 MW of capacity for the purpose of supplying its native load, only
about 1,042 MW potentially could benefit from higher electricity energy prices
during peak periods in the absence of a retail price cap. The reality of the
state-regulated retail price cap means that NYSEG cannot benefit at all from
higher prices.
76. Overall, each element of my review leads to the same conclusion. The
merger does not increase either the ability or the incentive for the Applicants
to exercise vertical market power.
THE MERGER DOES NOT CREATE ENTRY BARRIERS
77. It is also appropriate to consider the potential exercise of vertical
market power through the creation of entry barriers. New entrants to the
electricity generation market would not be disadvantaged by the proposed merger
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for three reasons. First, the merger does not augment the control of upstream
inputs to the production of electricity in the relevant market, as shown by my
analysis.
78. Second, new entrants can choose locations to build new power plants that
are served by any gas pipeline in the region and potentially sell power anywhere
in the region if electricity transmission service is available at reasonable
terms and rates.
79. Third, it is my understanding that the Applicants do not control
generation sites that could be used to exclude potential rivals.
CONCLUSION
80. Based on my analysis of horizontal electricity issues and vertical
issues between upstream gas supply and downstream electricity markets, I
conclude that the proposed merger would not have any adverse competitive effect
in any electricity market. Neither of the Applicants owns significant
generating resources in the relevant market. After March 1, 2000, CMP will own
or control no generation assets. Therefore, I conclude that there are no
horizontal market power concerns with this merger after this date. Likewise,
any generation combination that may occur during the interim period would be
short-lived and would not increase market concentration to a point needing
further review in any case.
81. The gas distribution assets of Energy East affiliates and those of the
joint venture CMPNG do not provide the means for the Applicants to exercise
vertical market power. The increased ability to exercise vertical market power,
if any, that results from the merger occurs within the New England region where
the Applicants have no downstream generation that could benefit. The generation
assets that could potentially benefit from a vertical market power strategy are
located primarily in Western New York, where the Applicants serve only a small
amount of rivals' generation capacity with upstream gas services. This
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separation of upstream and downstream assets between New England and New York
substantially reduces the possibility that a vertical market power strategy
could be successful. An analysis of owned and attributed downstream capacity in
both regions confirms that the merger would have no significant impact on the
downstream electricity market. On this basis, I conclude that the merger raises
no vertical market power concerns.
59
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UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ENERGY EAST CORPORATION )
AND ) DOCKET NO. EC99-____-000
CMP GROUP, INC. )
VERIFICATION PURSUANT TO 18 C.F.R. 33.7
DISTRICT OF COLUMBIA )
CITY OF WASHINGTON ) SS
NOW, BEFORE ME, the undersigned authority, personally came and appeared, J.
Stephen Henderson, who, after first being duly sworn by me, did depose and say:
That the contents of the foregoing Affidavit on behalf of Energy East
Corporation and CMP Group, Inc. are true, correct, accurate and complete to the
best of his knowledge, information and belief.
___________________________
J. Stephen Henderson
Subscribed and sworn to before me, this ___ of August 1999.
___________________________
Notary Public
My Commission Expires: _________________
County of Residence: ___________________
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ATTACHMENT B
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ENERGY EAST CORPORATION )
)
AND ) DOCKET NO. EC99- -000
)
CMP GROUP, INC. )
JOINT AFFIDAVIT OF STEVEN S. GARWOOD AND JEFFREY L. MCKINNEY
INTRODUCTION
1. My name is Steven S. Garwood. I am the Managing Director of
Transmission Operations for Central Maine Power Company ("Central Maine" or
"CMP"). My primary responsibility is to provide management oversight and
direction to the areas of Transmission Planning, Transmission Services,
Interconnection Agreement Administration, and CMP's Control/Dispatch Center.
During my career at CMP, which began in June 1985, I have worked in various
capacities in the areas of Engineering, Licensing, Cost of Service, and Rate
Design. I participated extensively in the restructuring of the New England
Power Pool ("NEPOOL") as part of the NEPOOL Regional Transmission Group
negotiating team and in my current capacity as Chair of the Regional
Transmission Operations Committee. I serve as CMP's primary representative on
the NEPOOL Participant's Committee (formerly the NEPOOL Executive Committee).
2. My name is Jeffrey L. McKinney. I am Manager of Transmission
Services & Policies in the Energy Operating Services Department of New York
State Electric & Gas Corporation ("NYSEG"). I am responsible for directing and
aiding the work of the Transmission Services & Policies Section with the primary
goals of providing transmission contractual services and formulating strategies
and policies related to transmission issues. I coordinate and have ultimate
responsibility for filings before the Federal Energy Regulatory Commission
("FERC") related to transmission services and contracts and manage the
day-to-day administrative matters of the Section. I have been a member of
several New York Power Pool ("NYPP") and Northeast Power Coordinating Council
("NPCC") system study working groups and am familiar with transmission pricing
under the New York Independent System Operator tariff described below.
3. The purpose of this joint affidavit is to support the merger of
Energy East Corp. and CMP Group, Inc. In particular, we explain how Central
Maine and NYSEG intend to integrate their Open-Access Transmission Tariffs
("OATTs") so that, with respect to transmission facilities over which CMP or
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NYSEG have retained some operational or administrative control, customers who
use both transmission systems are not required to pay both companies' embedded
cost transmission charges.
4. I, Mr. Garwood, will describe CMP's transmission system, as well as
transmission services within NEPOOL and CMP.
5. I, Mr. McKinney, will describe NYSEG's transmission services, as
well as transmission services within NYPP and NYSEG.
DESCRIPTION OF CENTRAL MAINE'S TRANSMISSION SYSTEM
6. Central Maine's transmission system serves approximately 533,000
native load retail customers within an 11,000 square mile territory in southern,
central, and western Maine. CMP's transmission system consists of 208 miles of
345 kV lines, 1065 miles of 115 kV lines and 1021 miles of 34.5 kV lines. CMP
is a member of NEPOOL. As such, all of its qualifying 345 kV and 115 kV
transmission facilities are classified as Pool Transmission Facilities ("PTF")
and are under the operational control of the independent system operator for New
England ("ISO-NE"). The remainder of CMP's transmission system, consisting of
its 34.5 kV transmission lines, and certain 345 and 115 kV facilities, are
classified as non-PTF. Central Maine has retained operational control only over
its non-PTF facilities. CMP does not own or control any of the tie lines that
comprise the New England to New York interface. These lines on the New England
side of the interface are owned by other New England utilities, are within
NEPOOL and are under the operational control of the ISO-NE.
DESCRIPTION OF NYSEG'S TRANSMISSION SYSTEM
7. NYSEG is a combination electric and gas utility serving
approximately 826,000 retail electric customers and 244,000 gas customers in
upstate New York. NYSEG's electric transmission system consists of
approximately 4,482 circuit miles of line. NYSEG's electric distribution system
consists of 35,967 miles of line. NYSEG, which is a member of the New York
Power Pool ("NYPP"), has committed to transfer control of its transmission
system to the independent system operator for New York ("NYISO").(76), 79 FERC
61,374 (1997). As is the case with CMP, NYSEG does not own or control any of
the transmission lines that comprise the New York to New England interface. All
these lines are owned by others and will be under the operational control of the
NYISO. The NYISO expects to commence operations in October 1999.
TRANSMISSION SERVICES WITHIN NEPOOL AND CMP
8. Within NEPOOL, transmission service over PTF is governed by the
NEPOOL OATT, which is administered by ISO-NE.(77) ISO-NE has operational
control of all New England utilities' PTF, including CMP's PTF. The provision
of open access transmission service over these facilities is provided under the
terms of the Restated NEPOOL Agreement and the NEPOOL Open Access Transmission
Tariff ("OATT"). The NEPOOL OATT provides for Regional Network Service,
Internal Point to Point Service, and service through and exports from NEPOOL
("Through and Out Service") at non-pancaked rates.
9. Under the NEPOOL OATT, New England load pays for Regional Network
Service over PTF. As a result, generators, power marketers, and other power
suppliers do not pay for transmission service to serve load in New England,
unless they purchase Internal Point to Point Service. The NEPOOL OATT provides
for zonal rates for Regional Network Service and Internal Point to Point
______________________
76 New England Power Pool, 79 FERC 61,374 (1997).
77 The Restated NEPOOL Agreement and NEPOOL OATT became effective on March 1,
1997. ISO-NE took over management and administration of the NEPOOL PTF on July
1, 1998.
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Service, which will ultimately be replaced with a system-wide, postage-stamp
rate equal to the NEPOOL PTF Rate. Transmission service over the PTF of all
NEPOOL member-utilities is subject to NEPOOL OATT charges only and not company
specific charges. Through and Out Service (transmission service to wheel power
through or export power out of NEPOOL to another control area, such as NYPP), is
provided at the NEPOOL PTF Rate. The NEPOOL PTF Rate is a postage stamp rate;
thus, a wheel from a generator anywhere on PTF to another control area, such as
NYPP, is subject only to a single NEPOOL transmission charge under the NEPOOL
OATT, irrespective of how many individual transmission systems are used. A New
England power marketer or generator that desires to wheel power through or out
of NEPOOL must arrange and pay for NEPOOL Through and Out Service.
10. Central Maine administers transmission service over its non-PTF
system under the terms of its Local OATT. This tariff provides for Local
Network Service to network transmission customers connected to CMP's, non-PTF
transmission system. The CMP Local OATT also provides for Local Point to Point
Service to customers, such as generators, connected to CMP's non-PTF system. A
generator, for example, could use Local Point to Point Service to transmit power
from CMP's local network to the NEPOOL PTF. Thus, a generator located on CMP's
local network that wishes to serve load in New England under NEPOOL Regional
Network Service would pay only a CMP Local Point to Point Service rate, and New
England load would pay for the Regional Network Service. If such a generator
wishes to serve load in New York, it must pay for NEPOOL Through and Out
Service, in addition to CMP Local Point to Point Service.
TRANSMISSION SERVICES WITHIN NYPP AND NYSEG
11. The NYISO is scheduled to become operational in October 1999.(78)
Under the NYISO tariff, all transmission services, with the exception of certain
grandfathered contracts, will be administered by the NYISO and offered under the
terms of the NYISO OATT. Transmission service within the NYISO control area
will be subject to a single zonal rate equal to the transmission service charge
("TSC") of the transmission owner on whose system the load withdraws the energy
or on whose system the energy is wheeled out of or exported from the NYISO
control area (the NYISO OATT equivalent of ISO-NE's Through and Out Service).
Accordingly, wheels to loads within NYSEG's service territory will be subject to
NYSEG's TSC. After the NYISO goes into operation, New York utilities will not
offer any new transmission service under their individual OATTs. The NYISO will
administer all transmission services across all eight transmission systems.
12. Transmission service associated with exports of power from a
generator in the NYISO control area out of the NYISO control area (Exports) or
Wheels Through (transmission of energy from another control area, such as
NEPOOL, through the NYISO control area to another control area, such as PJM(79))
will be subject to the non-pancaked TSC of each system at which the energy exits
the NYISO control area. The NYISO will calculate "generator shift factors" to
determine the megawatt flow that is transmitted on each of the transmission
owners' facilities that comprise the interface with the control area to which
the energy is exported. These distribution factors will be used in determining
each utility's billing units for application of its TSC, but only one TSC shall
apply to each MWH of Export or Wheel Through.
______________________
78 Currently, transmission service within NYPP is offered under the individual
OATTs of the eight New York utilities. Thus, transmission service within or
through NYSEG's service territory is governed by the NYSEG OATT and multiple
transmission service charges apply for wheeling through multiple utility systems
within NYPP.
79 The Pennsylvania-New Jersey-Maryland Interconnection.
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13. While NYSEG owns some of the tie lines that comprise the
NYISO-to-PJM interface, it does not own any of the tie lines that comprise the
NYISO-to-NEPOOL interface. NYSEG will apply its TSC to Wheels Through and
Exports to PJM in accordance with the shift factors. NYSEG will not apply its
TSC to Wheels Through and Exports to NEPOOL because it does not own the lines
comprising the interface between the NYISO control area and NEPOOL, and thus is
not allocated a shift factor for use of these facilities. NYSEG will receive
revenues for wheeling to loads located on or within its service territory.
NYSEG AND CMP TRANSMISSION CHARGES POST-MERGER
14. Following the merger, there will be only three types of
transactions that, absent a tariff modification or change in billing procedures,
could result in a charge under both CMP's Local OATT and the NYSEG TSC under the
NYISO OATT: wheels from a generator on CMP's non-PTF System (a) to wholesale
load on NYSEG's system, such as a municipal utility; (b) to a retail load within
NYSEG's service territory; or (c) through NYSEG's system to a buyer or
transmitter in PJM. In order to avoid that result, NYSEG and CMP commit that,
upon approval of the merger, they will waive or reduce the otherwise applicable
charges such that transmission customers in these three types of transactions
will not have to pay more than the equivalent of one transmission service
charge(80) to NYSEG and CMP for transmission.
15. Without the CMP OATT protocol (described in Paragraph 17 below), a
generator located on CMP's non-PTF system wheeling power to a load located on
NYSEG's system or in NYSEG's service territory would have to pay both a CMP
Local Point to Point Service charge(81) and a NYSEG TSC pursuant to NYSEG's
retail access tariff or the NYISO Tariff.
16. Without a posted NYSEG TSC billing credit (described in Paragraph
18 below), a generator located on CMP's non-PTF system wheeling power through
NYSEG to a buyer or transmitter in PJM may have to pay both CMP's Local Point to
Point Service charge under the CMP OATT and the full NYSEG TSC under the NYISO
OATT to the extent the NYISO determines that the transaction uses NYSEG's tie
lines interconnecting the NYISO control area with PJM. The NYISO OATT permits
such adjustments for Export and Wheel Through transactions. See Attachment H,
---
Section 8.0 of the NYISO OATT on file with the Commission.
17. CMP commits to adopt a protocol under CMP's Local OATT, to be
effective upon consummation of the merger, to waive CMP's otherwise applicable
Local Point to Point Service transmission service charge in the first two types
of transactions described in Paragraph 14, above [(a) and (b)].
18. For the third type of transaction described in Paragraph 14, above
[(c)], NYSEG similarly commits to implement a TSC billing credit such that NYSEG
will charge no more than its FERC-accepted or approved TSC less an amount
equivalent to the applicable Local Point to Point Transmission Service charge
under the CMP OATT.(82) If NYSEG does not bill TSC charges in excess of this
______________________
80 As discussed in this affidavit, the "transmission service charge" under
either the CMP OATT or the NYISO OATT does not include ancillary service
charges, congestion charges or losses, the application of which will remain
unchanged by the rate treatment discussed in this affidavit.
81 CMP's Local Point to Point Service rate is currently $2.87 per MWH.
82 NYSEG's TSC as filed in the NYISO Docket is $7.99 per MWH, subject to the
outcome of the NYISO proceeding. The equivalent amount of the billing credit
associated with the CMP OATT rate is currently $2.87 per MWH. NYSEG would issue
a TSC credit on its TSC bills to be consistent with the hourly TSC ceiling
described above.
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amount as described, the customers will pay in the aggregate no more than the
NYSEG TSC or the equivalent of only a single system rate for use of both Central
Maine's non-PTF system and NYSEG's system. The effect of this posted TSC
billing credit is that transmission customers in such transactions will not be
charged the equivalent of both CMP's Local OATT rate for Local Point to Point
Service and the full NYSEG TSC.
19. While the NYISO OATT contemplates a discount applicable to all
customers delivering across a particular interconnection, the more specific
application of a billing credit to only those customers that pay CMP Local Point
to Point Transmission Service charges satisfies the Commission's policy in
mergers. The billing credit places customers using both CMP's and NYSEG's
systems, and subject to both companies' charges in the same position they would
have realized had CMP waived its Local Point to Point Transmission Service
charge and NYSEG charged its full TSC. This stated billing credit practice,
which the Commission can approve as a condition of the merger authorization
sought in this application, is not discretionary, thereby avoiding completely
concerns that might otherwise arise in a discounting context. By proposing the
equivalent of only one rate for use of both CMP's non-PTF system and NYSEG's
system, through a combination of waiving the CMP Local OATT TSC in some
transactions and a NYSEG TSC billing credit in others, the applicants will
spread any revenue impacts and benefits associated with the rate treatment
across both systems.
20. In transactions from a generator on the NYSEG system or another
control area, such as PJM, through NYSEG to a load on the CMP non-PTF system,
there would be no duplicate NYSEG/CMP transmission charges. Under the NYISO
OATT, the transmission owners at the point of withdrawal of the energy apply
their TSCs. Accordingly, NYSEG would not collect a TSC for transactions out of
NYISO control area to NEPOOL because NYSEG does not own any of the tie lines
comprising the NYISO control area to NEPOOL interface. Similarly, NYSEG would
not collect a TSC for transactions into NYISO control area from PJM. In these
transactions, the only CMP/NYSEG transmission charge imposed would be CMP's
charge under its Local OATT. Therefore, no tariff amendments or changes in
billing practice are required.(83)
21. The companies can achieve the proposed mechanisms for eliminating
application of both a CMP OATT embedded cost transmission charge and a NYSEG TSC
under the NYISO OATT through the CMP protocol under its Local OATT and NYSEG's
billing credit protocol described above. Neither the NYISO OATT nor the NEPOOL
OATT requires amendment to achieve this result. In this way, implementation of
the rate treatment specified in this application is simplified.
SUMMARY AND CONCLUSIONS
22. By the time the merger of Energy East and CMP Group is completed,
NYSEG and CMP will have relinquished operational control of their transmission
systems to their respective ISOs consistent with FERC-approved tariffs and
agreements. Services over the intervening NEPOOL and NYISO transmission systems
will be offered under the non-discriminatory terms of the NEPOOL OATT and the
NYISO OATT. CMP and NYSEG commit to eliminate the potential effects of
multiple transmission charges that would otherwise result from application of
______________________
83 While there are other transactions between or through the CMP and NYSEG
transmission systems, no other transactions would be assessed both a NYSEG TSC
and a transmission charge under the CMP Local OATT. For instance, a generator
located on CMP's PTF system serving load in either NYSEG's service territory or
in PJM would not pay a CMP Local OATT charge.
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CMP's Local OATT and the NYSEG TSC under the NYISO OATT. By lowering the
otherwise applicable transaction costs, these proposed measures will encourage
additional competitive economic transactions between the two companies' systems.
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Exhibit D-3
STATE OF MAINE DOCKET NO. 99-411
PUBLIC UTILITIES COMMISSION
July 1, 1999
CMP GROUP, INC., CENTRAL MAINE POWER )
COMPANY, MAINECOM SERVICES, MAINE )
ELECTRIC POWER COMPANY, INC., NORVARCO, )
CHESTER SVC PARTNERSHIP, MAINE YANKEE )
ATOMIC POWER COMPANY, AND )
CMP NATURAL GAS, L.L.C., )
)
PETITION FOR APPROVAL OF REORGANIZATIONS )
AND AFFILIATED INTEREST TRANSACTIONS
INTRODUCTION
------------
Petitioners CMP Group, Inc., Central Maine Power Company ("CMP"), MaineCom
Services ("MaineCom"), Maine Electric Power Company, Inc. ("MEPCO"), NORVARCO,
Chester SVC Partnership, Maine Yankee Atomic Power Company ("Maine Yankee") and
CMP Natural Gas, L.L.C. ("CMP Natural Gas") request regulatory approval under
Title 35-A of the Maine Revised Statutes Annotated, including Sections 707 and
708, of the merger of EE Merger Corp., a wholly-owned subsidiary of Energy East
Corporation ("Energy East"), a utility holding company headquartered in Albany,
New York, with and into CMP Group. Under the terms and conditions of a merger
Agreement(1) executed June 14, 1999, CMP Group will become a wholly-owned
subsidiary of Energy East. Petitioners also seek (i) approval of the
reorganization of CMP Natural Gas by which it will become a wholly-owned
subsidiary of an existing Energy East natural gas subsidiary and of the
assignment to the reorganized CMP Natural Gas of services agreements(2) with
various affiliates and (ii) modification of certain conditions associated with
the formation of CMP Group.
- -------------------------------
1. Agreement and Plan of Merger by and among CMP Group, Inc., Energy East
Corporation and EE Merger Corp. (hereinafter referred to as the "Merger
Agreement"). A complete copy of the Merger Agreement, including schedules and
attachments, is attached hereto as Appendix 1.
2. These services agreements have been filed with the Commission in Docket No.
99-397. Services agreements between CMP and various affiliates that have
previously been approved by the Commission will remain in place after the merger
until such time as new services agreements may be approved under Section 707 of
Title 35-A M.R.S.A.
<PAGE>
THE PARTIES
-----------
1. Petitioner CMP Group is the holding company whose formation the
Commission approved on May 1, 1998 in Docket No. 97-930. Its holdings include
100 percent of the common stock of CMP, MaineCom and New England Gas Development
Corporation ("New England Gas"), and other interests, all as shown in Appendix
2.
2. Petitioner CMP is Maine's largest electric utility, serving approximately
530,000 customers. In accordance with 35-A M.R.S.A. S3204 and the Commission's
December 24, 1997 and January 14, 1998 Orders in Docket No. 97-523, CMP has
divested substantially all of its generating assets and is predominantly an
electric transmission and distribution utility.
3. Petitioner MaineCom is a telephone utility under the terms of the
Commission's February 19, 1997 Order in Docket No. 96-421. It provides
telecommunications services, including point-to-point connections, private
networking, consulting, private voice and data transport, carrier services and
long-haul transport.
4. Petitioner MEPCO, in which CMP holds a 78.3 percent voting interest (with
the remaining interests held by Bangor Hydro-Electric Company and Maine Public
Service Company), owns and operates a 345 kV interconnection between New
Brunswick, Canada and Wiscasset, Maine, and also owns and operates related
facilities. MEPCO transmits power under its Open Access Transmission Tariff
approved by the Federal Energy Regulatory Commission ("FERC").
<PAGE>
5. Petitioner NORVARCO is a wholly-owned subsidiary of CMP. NORVARCO is a
general partner with a 50 percent interest in Chester SVC Partnership, which
owns a static var compensator ("SVC") facility in Chester, Maine. The SVC
facility provides transmission system reinforcement that allows the Hydro-Quebec
Phase II transmission line in New Hampshire and the MEPCO line to operate at
full capability simultaneously.
6. Petitioner Maine Yankee, in which CMP has a 38 percent voting interest,
owns a nuclear electric generating facility in Wiscasset, Maine, that has been
permanently shut down since August 6, 1997 and that is currently being
decommissioned.
7. Petitioner CMP Natural Gas is engaged in the business of the sale and
local distribution of natural gas in Windham, Maine, and has authority to sell
and distribute gas in 34 other Maine cities and towns.
ACQUIRING ENTITY
----------------
8. Like CMP Group, Energy East is an exempt holding company under the Public
Utility Holding Company Act of 1935, as amended ("PUHCA"). It was formed on May
1, 1998, through the exchange of all of the issued and outstanding common stock
of New York State Electric & Gas Corporation ("NYSEG"), now its principal
subsidiary, in connection with the restructuring of the electric utility
industry in the State of New York. NYSEG is a combination electric and gas
utility serving approximately 817,000 electric and 243,000 gas customers in
upstate New York. All of NYSEG's common stock is owned by Energy East. Like
CMP, NYSEG has divested substantially all of its generating assets. NYSEG is
now predominantly engaged in the transmission and distribution of electricity
and the distribution of natural gas.
9. Another subsidiary of Energy East, Energy East Enterprises, Inc. ("EE
Enterprises"), owns gas interests in Vermont, New Hampshire and, through its
interest in CMP Natural Gas, in Maine. EE Merger Corp., another wholly-owned
subsidiary of Energy East, exists solely as a means to consummate the merger
under Maine law. After it merges with and into CMP Group, EE Merger Corp. will
cease to exist.
<PAGE>
10. Energy East recently announced that it has entered into an agreement,
subject to regulatory approval, to acquire Connecticut Energy Corporation, a
public utility holding company that owns The Southern Connecticut Gas Company, a
local gas distribution company serving approximately 160,000 customers in
Connecticut. It is contemplated that Connecticut Energy will become a directly
owned subsidiary of Energy East. On June 30, 1999, Energy East also announced a
proposed merger with CTG Resources, Inc. of Connecticut, the parent company of
Connecticut Natural Gas Corporation and The Energy Network, Inc. Connecticut
Natural Gas sells and distributes natural gas to approximately 142,000 customers
principally in greater Hartford and Greenwich, Connecticut, and The Energy
Network provides energy-related products and services, including providing
through a subsidiary steam and chilled water to buildings in Hartford. It is
intended that CTG Resources will become a wholly owned subsidiary of Energy
East. A proposed organizational chart showing the structure of Energy East
assuming consummation of the merger is attached as Appendix 3.
DESCRIPTION OF THE MERGER AGREEMENT
-----------------------------------
11. The Merger Agreement addresses the following matters: (3)
a. Article I specifies the process by which an Energy East
subsidiary (EE Merger Corp.) will merge with and into CMP Group.
- -------------------------------
3. Petitioners offer what follows as a guide to sections of the Merger
Agreement. This description is not intended in any way to alter or interpret the
Merger Agreement itself, which is attached as Appendix 1.
<PAGE>
In essence, promptly upon receipt of all regulatory approvals, CMP
Group will become a 100 percent-owned subsidiary of Energy East. The Merger
Agreement requires no other changes in the ownership or organization of the
companies in the CMP Group system; except as discussed below with respect to New
England Gas and CMP Natural Gas, CMP Group will continue to own CMP and its
other subsidiaries as it does currently.
b. Article II deals primarily with the consideration for the merger,
which is $29.50 per share of CMP Group common stock (for a total of
approximately $957 million), and the mechanics of exchanging CMP Group shares
for that consideration. It also provides for the termination of outstanding
stock options, with holders receiving consideration based on the difference
between $29.50 and the options' exercise prices.
c. Article III specifies the time and place of closing, following receipt of
regulatory approvals and satisfaction of other conditions enumerated in Article
VII, discussed below.
d. Article IV contains representations and warranties made by CMP Group.
These are essentially standard provisions in corporate mergers and, with respect
to CMP Group and its direct and indirect majority-owned subsidiaries, address
<PAGE>
such issues as organization and qualification to do business; capitalization;
authority to enter into the Merger Agreement; compliance with corporate
governance documents, laws and material agreements; required approvals; accuracy
of reports filed with the Securities and Exchange Commission ("SEC") and of
financial statements; absence of extraordinary business events; litigation; tax
matters; employment and benefits matters; environmental matters; PUHCA
regulation; matters relating to the special meeting of shareholders for approval
of the merger; the fairness opinion of CMP Group's financial advisors; and Year
2000 issues. The Article also incorporates separate schedules, in which CMP
Group enumerates those matters of which it is aware that could constitute risks
to its value, such as threatened litigation or possible environmental
remediation obligations.
e. Article V specifies Energy East's representations and warranties.
Because CMP Group shareholders are not receiving stock of Energy East as
consideration, the need for representations and warranties relating to risks to
Energy East's future operations is narrow, and matters addressed in this Article
are principally focused on Energy East's likely ability to close the
transaction.
f. Article VI addresses covenants of the parties concerning their conduct
both in the period leading up to consummation of the merger and, to some extent,
thereafter. The covenants are designed to:
- - Ensure that CMP Group does not engage in conduct (e.g., incurring
significant new indebtedness, making acquisitions or dispositions of
assets) which could materially diminish its potential value
- - Enable the CMP Group Board of Directors to balance its obligation to seek
in good faith to consummate the merger with Energy East with its fiduciary
duty to CMP Group shareholders to consider subsequent merger proposals
which might be more favorable to them than the Energy East merger
- - Encourage cooperation and diligence in meeting disclosure and regulatory
requirements
- - Ensure that CMP Group moves promptly in securing shareholder approval of
the merger
<PAGE>
- - Ensure continued effectiveness of existing CMP Group collective bargaining
agreements
- - Recognize the right of employees of CMP Group and its subsidiaries to
participate in Energy East benefit plans upon consummation of the merger,
with full credit for length of their employment with CMP Group and its
subsidiaries
- - Provide for continued maintenance of CMP's corporate headquarters in
Augusta, Maine, and the establishment of an Energy East corporate office
in Portland, Maine
- - Provide for the President and CEO of CMP Group and two other current CMP
Group Board members to become members of the Energy East Board
- - Acknowledge employment agreements between Energy East and three senior CMP
Group executives and one senior CMP executive who will continue their
employment in the capacities described in Article VI(3)
- - Provide for the current CMP Board to continue in existence as an Advisory
Board for CMP, and
- - Ensure that Energy East continues CMP's commitment to charitable and
community activities at least at current levels.
g. Article VII specifies the conditions to the parties'
obligations to consummate the merger. Conditions include receipt of CMP Group
shareholder approval and regulatory approvals, and the absence of a court or
regulatory order prohibiting the merger. Regulatory orders must not include any
"terms or conditions which, in the aggregate, would have, or insofar as
reasonably can be foreseen, could have" a material adverse effect. A material
adverse effect is defined, in the case of CMP Group, to be "a material adverse
effect on the business, properties, condition (financial or otherwise) or
results of operations of the
- -------------------------------
4. David T. Flanagan, Arthur W. Adelberg, F. Michael McClain of CMP Group and
Sara J. Burns of CMP.
<PAGE>
Company and its subsidiaries taken as a whole or on the consummation of [the]
Agreement." (Merger Agreement, S 4.1.) The parties must also have honored their
representations, warranties and covenants.
h. Article VIII addresses termination, amendment and waivers.
Termination is permitted for material, uncured breaches of representations,
warranties and covenants. Termination by CMP Group is also permitted if CMP
Group, while honoring its obligations under the Merger Agreement (including the
obligation not to solicit competing merger proposals), nonetheless receives a
superior merger offer which Energy East declines to improve on. Article VIII
also permits termination by either party if non-regulatory conditions of the
Merger Agreement are not satisfied within 12 months, or if regulatory conditions
are not satisfied within 18 months.
Article VIII additionally provides for damages and other payments
for various kinds of breaches and terminations. In general, for a non-willful
breach (such as an unintentional inability to honor a warranty), the party in
breach must pay the other party up to $10 million for its actual out-of-pocket
expenses; if the breach is willful, the non-breaching party may also avail
itself of other legal remedies. If the termination results from CMP Group
having received a superior, competing merger offer, Energy East is entitled to a
"break-up fee" of $33.5 million, which equates to 3.5% percent of the total
consideration for the merger.
i. Article IX, the final section, contains miscellaneous provisions
addressing contract execution, forms of notice, and dispute resolution
procedures.
<PAGE>
REORGANIZATION CONDITIONS
-------------------------
12. By Order dated May 1, 1998, in Docket No. 97-930 (Central Maine Power
Company, Application for Approvals of Reorganizations under Section 708), the
Commission approved the formation of CMP Group as a holding company over CMP,
subject to specified conditions to protect the interests of ratepayers. In
addition, in its Order in Docket No. 98-077, also issued on May 1, 1998, the
Commission approved the creation of entities within the holding company group to
participate in the natural gas distribution business in Maine, subject to
certain conditions.
13. Petitioners believe that it is appropriate to eliminate certain
conditions established in Docket Nos. 97-930 and 98-077 in this proceeding, as
follows:
a. Investment Level in Non-Utility Businesses. The limit of $240
----------------------------------------------
million on investments by CMP Group in non-utility subsidiaries and other
non-utility activities, other than subsidiaries created to participate in the
natural gas distribution business, established in Docket No. 97-930, should be
eliminated.
In its May 1, 1998 Order in Docket No. 97-930, the Commission stated:
We find that a basic advantage of the holding company
organizational structure is that non-utility activities can be more
cleanly separated from utility activities. In particular, the capital
structures of utility entities are separated from non-utility entities
with the holding company form, which better 'insulates' ratepayers
from the activities of the HoldCo's non-utility affiliates.
Nevertheless, some limit on HoldCo's investment in non-utility
activities may provide useful additional protection for utility
ratepayers. As the testimony of Dr. Bower suggested, it is prudent to
limit, at least to some degree, the extent to which HoldCo management
will be distracted from its obligations to CMP by issues arising from
its unregulated activities.
Docket No. 97-930, Order at 4 (May 1, 1998).
<PAGE>
In the proposed merger, Energy East will become the parent holding
company of CMP Group. The non-utility and utility businesses of Energy East,
including the CMP Group system companies, will continue to be operated in
separate entities, each with its own management and board of directors. The CMP
management team will remain essentially intact after the merger is consummated.
In addition, David Flanagan will serve as a board member and President of Energy
East and Chairman of the Board and Chief Executive Officer of CMP Group. CMP's
President, Sara J. Burns, will report directly to Mr. Flanagan. Further, two
outside directors on CMP's existing Board of Directors will serve as directors
of Energy East and, along with other existing CMP Board members, will also
continue to serve as members of the advisory board of CMP. This continuity of
management will promote an identity of interest that will continue to ensure the
protection of ratepayer interests. Moreover, the merger of CMP Group and Energy
East will permit CMP access to the management resources available from Energy
East, a company with significant success in the delivery of electric and natural
gas products and services.
Energy East's significantly larger size as compared to CMP Group, both
in terms of assets and revenues, does not warrant the imposition of an
investment limit. In its Form 10-Q for the quarter ended March 31, 1999, filed
with the SEC, Energy East reported total assets of $5.7 billion as compared to
total assets of $2.2 billion reported by CMP Group for the first quarter of
1999, and total revenues of $654.4 million as compared to $276.6 million of
total revenues reported by CMP Group for the same period. In its January 27,
1998 Order approving the holding company restructuring of NYSEG, the New York
Public Service Commission did not impose any limitation on investment by Energy
East in non-utility or utility businesses or other activities.
<PAGE>
Another key factor also ensures that ratepayers will be protected.
Energy East has noted that it shares with CMP Group a common vision for the
future in that both companies have chosen to focus on their core competencies of
distributing electricity and natural gas. Of the $654.4 million of total
revenues reported by Energy East for the three months ended March 31, 1999,
NYSEG's electric revenues contributed $415.3 million of that amount and gas
revenues contributed an additional $135.4 million, for a total of $550.7
million, or 84 percent. For CMP Group, CMP contributed $270.6 million of the
$276.6 million of revenues reported for that quarter, or over 97 percent of
revenues for the period. The significance of these utility businesses for
Energy East and CMP Group is obvious from this financial information. As CMP
stated in its Petition filed with the Commission on December 8, 1997 in Docket
No. 97-930:
Following the reorganization, the Company's core utility business
will continue to be the principal business focus of the combined
enterprise and of efforts to operate a financially sound and growing
business whose objective will be to provide service effectively and
efficiently. Maintenance and improvement in the quality of the
Company's service will continue to be top priorities. From a business
standpoint, the focus must remain on CMP's business reputation as a
predominant component of the entire corporate group. In addition, the
overwhelming portion of invested capital will continue to be invested
in assets in CMP's service area dedicated to providing service to its
Maine customers. The Company will not compromise its ability to
perform its public service obligation or its relationship with
regulators or risk invested capital by retaining insufficient talent
or resources to manage those assets effectively and efficiently.
Docket No. 97-930, Petition at 4 (Dec. 8, 1997). Both CMP Group and Energy East
reaffirmed their commitment to their core businesses in announcing the proposed
merger.
In addition, both CMP Group and Energy East have a proven track record
in serving their customers and have pledged continued superior service to all
utility customers.
Finally, the Commission should remove the investment limitation
because, if CMP Group is limited in terms of what it can invest in subsidiaries,
it will compromise Energy East's ability to invest in Maine generally since this
can best be accomplished through CMP Group.
<PAGE>
b. Investment Level in and Reorganization of CMP Natural Gas. In its
-----------------------------------------------------------
Order in Docket No. 98-077, in which the Commission approved the creation of
entities to participate in the natural gas distribution business in Maine, the
Commission addressed the level of investment in CMP Natural Gas, a Maine public
utility. In that proceeding, the Commission adopted CMP's proposed initial
investment of $10 million in the natural gas distribution business but directed
CMP to seek approval for any additional investment. The major provision of
the Joint Agreement that we must consider provide[s] that the initial capital
contribution of each member will be $10 million. CMP requests that the
Commission authorize its GasCo subsidiary to invest $10 million in the limited
liability company. No party disputes this $10 million investment.(5) We find
that the investment of $10 million by HoldCo in GasCo is reasonable.
Docket No. 98-077, Order at 8 (May 1, 1998). Petitioners believe that any
investment limit should be eliminated in this proceeding.
CMP Natural Gas is a Maine limited liability company in which New
England Gas and EE Enterprises hold membership interests under a joint venture
agreement approved by the Commission in Docket No. 98-077. As a result of the
merger, Energy East will hold all interests in CMP Natural Gas. For this
reason, Energy East and CMP Group have agreed, subject to Commission and any
other necessary regulatory approvals, to dissolve New England Gas (whose only
asset is its membership interest in CMP Natural Gas), terminate the joint
venture agreement, terminate the limited liability company form of organization
for CMP Natural Gas, and
simultaneously re-establish CMP Natural Gas as a wholly-owned corporate public
utility subsidiary of EE Enterprises. Approval is sought in this proceeding
under 35-A M.R.S.A. S 708 for this reorganization of CMP Natural Gas. Approval
is also sought in this proceeding for the assignment to the reorganized CMP
Natural Gas of services agreements between CMP Natural Gas and various
affiliated entities that may be approved by the Commission in Docket No. 99-397.
- -------------------------------
5. In its Order in Docket No. 98-077, the Commission stated as follows:
The major provision of the Joint Agreement that we must consider
provide[s] that the initial capital contribution of each member will be $10
million. CMP requests that the Commission authorize its GasCo subsidiary
to invest $10 million in the limited liability company. No party disputes
this $10 million investment. We find that the investment of $10 million by
HoldCo in GasCo is reasonable.
Docket No. 98-077, Order at 8 (May 1, 1998).
<PAGE>
As an EE Enterprises subsidiary, CMP Natural Gas will retain its name
(without the "L.L.C." reference) and will continue pursuing the development of a
natural gas distribution business in the Maine cities and towns in which it was
authorized to do business in the Commission's August 17, 1998 Order in Docket
No. 96-786. As the testimony showed in that Docket, the planned construction of
the natural gas distribution system by CMP Natural Gas is expected to cost
approximately $100-135 million over the anticipated six-year build-out of the
system, with a planned financing of project costs through equal amounts of debt
and equity. To provide sufficient funds for this project, which is part of
Energy East's and CMP Group's focus on energy delivery businesses, and for the
additional reasons relating to investment level by CMP Group discussed above,
Petitioners believe that the Commission should remove the $10 million investment
limitation and permit equity investment in CMP Natural Gas to be made by Energy
East and/or EE Enterprises as business needs dictate, consistent with sound
investment policy.
c. CMP Natural Gas Name. CMP Natural Gas is required to pay royalties
---------------------
for use of the CMP name under the terms of a Stipulation approved by the
Commission in Docket No. 98-077 on June 10, 1998. The royalty payment is based
on the presumption set forth in the Commission's Chapter 820 Rules that the
value of the use of a utility's goodwill, including its name, is the lesser of
one percent of the total capitalization of CMP Natural Gas or two percent of its
gross revenues. Legislation signed into law on May 12, 1999, which will become
effective on September 18, 1999, eliminates this presumption for use of goodwill
by regulated affiliates of CMP, such as CMP Natural Gas. Petitioners believe
that the terms of the existing Stipulation should be set aside and CMP Natural
Gas should no longer be required to make royalty payments in light of the
amended law and the more remote connection to CMP under the proposed new
structure.
<PAGE>
d. Issuance of Debt. In its Order in Docket No. 97-930, the Commission
----------------
accepted a condition that CMP Group be permitted to issue debt, whether
long-term or short-term debt, in an amount up to 50 percent of total
capitalization. This limitation should be eliminated in this proceeding. At
the time the merger becomes effective, the capitalization of CMP Group will
change substantially. Currently, CMP Group's capitalization consists of
32,442,552 shares of common stock, $5.00 par value, for a total equity
capitalization of $162,212,760. The Merger Agreement provides that shares of
common stock of CMP Group after the merger will have a par value of $.01 per
share. Although the number of issued and outstanding shares of CMP Group common
stock after the merger is as yet undetermined, since CMP Group will be wholly
owned by Energy East, and its common stock will not share voting power with any
other class of stock, there will be no need to have a large number of issued and
outstanding shares of CMP Group common stock. For this reason, the limitation
on debt issuances established in Docket No. 97-930 will no longer be appropriate
when the merger becomes effective and, therefore, should be eliminated.
Certain other conditions on CMP's holding company restructuring in the
Commission's Order in Docket No. 97-930 will continue to provide protection for
ratepayers. These conditions state:
h. Utilities Securities Issuance. Securities issued by the
-------------------------------
Company i.e., CMP will be done independently of HoldCo.
The proceeds of any securities issued by the Company will
be used exclusively by the Company for its business.
* * *
r. Financial Integrity of T&D Co. To protect and maintain
---------------------------------
the financial integrity of the regulated T&D Company:
* * *
(ii) the debt of the Company will be raised by CMP and
will not be derived from HoldCo.
(iii) The T&D Co. will not make loans to HoldCo or any
of the unregulated subsidiaries and affiliates; guarantee
the obligations of either the HoldCo or any or sic the
---
unregulated subsidiaries and affiliates; or pledge its
assets as security for the indebtedness of HoldCo or any
subsidiary or affiliate.
Docket No. 97-930, Order at 13, 15 (May 1, 1998). Considering these ratepayer
protections, Energy East's financial strength, and the express intention of CMP
Group and Energy East to focus on energy delivery businesses, no limitation on
debt issuances should be imposed in this proceeding. Rather, the issuance of
debt by the holding companies should be guided by the sound financial policy of
the companies.
e. SEC Filings. The Order in Docket No. 97-930 requires CMP Group
------------
to provide copies of periodic reports filed with the SEC to the Commission. As
previously noted, at the time of the effective date of the merger, all of the
issued and outstanding common stock of CMP Group will be held by Energy East,
and the common stock of CMP Group that is currently registered with the SEC and
listed on the New York Stock Exchange will be deregistered and delisted,
respectively. At that time, CMP Group will no longer file reports with the SEC.
As a publicly held company, Energy East will continue to file SEC reports, which
will be publicly available. In addition, for as long as the 6% Preferred Stock
of CMP remains registered with the SEC, CMP will also continue to file periodic
reports with the SEC, which will also be publicly available.
<PAGE>
14. In the event the SEC, whose approval of the merger is also necessary,
does not permit Energy East to maintain CMP Group as an intermediate holding
company under provisions of PUHCA, Energy East would hold CMP and other CMP
Group subsidiaries directly. This Petition also includes a request for approval
of this potential organizational structure under Section 708 of Title 35-A
M.R.S.A. This structure would not result in any changes to the management and
Advisory Board of CMP previously described. Because Energy East is committed to
the core electricity and gas delivery businesses and to excellent customer
service, there would be no detriment to CMP ratepayers if this structure became
necessary as a result of SEC action.
15. In assessing business needs and appropriate means to pursue business
interests at some time after the merger is consummated, Energy East and CMP
Group may determine that a merger, consolidation, spin-off or other form of
reorganization of one or more existing non-utility subsidiaries or other
non-utility affiliates is appropriate. Likewise, to respond effectively to
business opportunities that may present themselves and to enhance the ability to
develop, market and furnish services, a non-utility subsidiary or other
non-utility affiliate of Energy East and CMP Group may explore opportunities for
appropriate affiliations with one or more firms providing similar or
complementary services in the targeted markets. While such affiliations may be
in the nature of contracts or subcontracts, the non-utility subsidiary or
affiliate should have the option of entering into one or more joint ventures,
general partnerships, limited partnerships, membership interests in limited
liability companies, or other affiliations (including without limitation stock
ownership in corporations) with one or more such entities. For these reasons,
this Petition also encompasses a request under Section 708 for approval of one
or more such forms of reorganization through one or more means.
<PAGE>
REGULATORY APPROVALS
--------------------
16. In addition to the approval sought in this Petition, the merger is
subject to the following regulatory approvals:
a. Securities and Exchange Commission ("SEC"). The merger requires the
------------------------------------------
approval of the SEC under Section 9(a)(2) of PUHCA. That Section prohibits the
acquisition of five percent or more of the securities of a public utility by any
person or entity that already owns at least five percent of the securities of
another public utility and also prohibits the acquisition of five percent or
more of two public utilities unless the SEC has approved the acquisition.
Because Energy East already has at least one public utility subsidiary, SEC
approval of its acquisition of CMP and its public utility affiliates (through
the acquisition of CMP Group) is required. Energy East acknowledges in the
Merger Agreement that it will be required to change its status under PUHCA from
that of an "exempt holding company" to a "registered holding company." This
will subject Energy East to PUHCA restrictions on its capital structure,
affiliate transactions, and business activities. In addition, in seeking
approval under PUHCA Section 9(a)(2), Energy East will be required to meet the
requirements of Sections 10 and 11 of PUHCA relating to integration of
operations under a holding company and corporate simplification. Uncertainty as
to the SEC's timetable for acting is a major reason for the provision in Section
8.1(b) of the Merger Agreement allowing up to 18 months for regulatory
approvals.
b. Federal Energy Regulatory Commission ("FERC"). The merger must
-------------------------------------------------
be approved under Section 203 of the Federal Power Act. Section 203 requires
approval of the FERC for the disposition or merger of jurisdictional facilities,
which include facilities used in interstate commerce, such as CMP's transmission
facilities.
c. Nuclear Regulatory Commission ("NRC"). Under Section 184 of the
---------------------------------------
Atomic Energy Act and 10 C.F.R. S 50.80, the NRC must consent to transfers of
control of nuclear assets.
<PAGE>
d. Federal Trade Commission ("FTC"). Under the Hart-Scott-Rodino
-----------------------------------
Act, 15 U.S.C. S 18a, the FTC must approve all mergers above certain size
thresholds (e.g., acquisitions of assets exceeding $10,000,000 by an entity
having assets exceeding $100,000,000), which are easily met in this case.
e. Department of Justice-Antitrust Division ("DOJ"). The same filing
---------------------------------------------------
that is made with the FTC must also be made with the DOJ's Antitrust Division,
which reviews the filing to determine whether there are any anti-competitive
effects of the merger.
f. Connecticut Department of Public Utility Control. Connecticut
-----------------------------------------------------
requires approval of the merger because under Connecticut law, CMP is a "public
service company" as a result of its 2.5 percent Millstone Unit No. 3 ownership
interest.
g. Federal Communications Commission ("FCC"). FCC approval is required
------------------------------------------
due to CMP's ownership of microwave facilities.
SHAREHOLDER APPROVAL
--------------------
17. The merger is subject to approval by CMP Group shareholders, but not by
Energy East shareholders. CMP Group must first obtain SEC clearance for
issuance of a proxy statement. Based on the time needed to prepare the proxy
materials, the SEC's customary review process, and notice requirements for the
special meeting of shareholders, CMP Group expects to put the matter before its
shareholders for a vote in September or October, 1999.
LEGAL STANDARD
--------------
18. The Commission's standard for approval under both Sections 707 and 708
is similar: the transaction or reorganization at issue must not be adverse to
the public interest. See 35-A M.R.S.A. 707 (3) (approval requires finding that
transaction "not adverse to public interest") and S 708 (2)(A) & (2)(A)(9)
(noting that any necessary conditions must ensure, among other things, that
"neither ratepayers nor investors are adversely affected").
<PAGE>
19. The Commission's primary focus here is on Section 708, which requires
determination that the merger is "consistent with the interests of the utility's
ratepayers and investors." 35-A M.R.S.A. S 708(2). The Commission has
consistently applied this standard by balancing the total benefits that will be
achieved by the merger against the potential detriments or risks. See, e.g.,
Public Utilities Comm'n, Investigation of Maine Public Service Co., Docket No.
85-92, Decision at 3 (May 15, 1986) (noting "detriments advanced by merger
opponents either are not cause for concern or are outweighed by the benefits"),
rev'd on other grounds sub nom. Maine Pub. Serv. Co. v. Public Utilities Comm'n,
524 A.2d 1222 (Me. 1987); Greenville Water Co., Millinocket Water Co. &
Skowhegan Water Co., Application for Authorization to Sell Utility Property,
Docket No. 92-250, Order Approving Stipulation at 2-3 (Dec. 15, 1992) (noting
net benefits to customers of merger); New England Tel. & Tel. Co. and NYNEX
Corp., Proposed Joint Petition for Reorganization Intended to Effect the Merger
with Bell Atlantic Corporation, Docket No. 96-388, Order (Part II) at 10 (Feb.
6, 1997) ("NYNEX Part II Order") ("the merger should be approved if the total
benefits flowing from the merger are equal to or greater than the detriment or
risk caused for both ratepayers and shareholders"). This is a "no net harm"
test - that is, the merger should be approved if, on balance, ratepayers and
shareholders will not be harmed. NYNEX Part II Order at 11 ("we must determine
whether these benefits at least equal the detriments of the merger, i.e., that
ratepayers and shareholders will not be harmed").
a. Shareholders. The Commission can satisfy itself that investor
------------
interests are being addressed simply by following the outcome of the shareholder
vote. Cf. Northern Utilities, Inc., Order Approving Request for Approval of
Reorganization - Merger with NIPSCO Stipulation and Merger Industries, Docket
No. 98-216 at 1 (June 12, 1998) (noting approval by a majority of common
shareholders). In addition, because CMP shareholders are not receiving Energy
East stock in exchange for their shares, but are receiving cash, there is no
risk associated with ownership in another entity. (Merger Agreement, Article
II.)
<PAGE>
b. Ratepayers. The Commission's focus with regard to customers is
----------
whether the rates and services they will receive will be adversely affected by
the merger. See NYNEX Part II Order at 10. In the largest merger proceeding
before the Commission to date - the NYNEX/Bell Atlantic merger case - the
Commission applied these principles to find that, despite upfront merger costs
that would likely exceed merger savings for the first several years and despite
allegations concerning the anticompetitive effects of the merger, telephone
ratepayers would nonetheless likely receive benefits because: (1) the new
corporate structure would position NYNEX to respond to competition with rate
reductions; (2) the Commission would be able to examine actual cost savings at
the five-year review of NYNEX's alternative rate plan; and (3) the Commission
could then impute any savings that did not materialize into rates, due to its
reliance on such claimed savings to approve the merger. NYNEX Part II Order at
13. Hence, the Commission approved the merger because the likely benefits from
the new corporate structure outweighed the speculative detriments of unrealized
savings or anticompetitive effects, and because the Commission would be
presented with future opportunities to address the flow-through of any cost
impacts to ratepayers.
20. Like Section 708, the Commission's primary consideration under Section
707 is that ratepayers are not harmed by a utility's transactions with
affiliates. Indeed, one of the considerations guiding the Commission's approval
under Section 708 is the ability of the Commission to review affiliated
transactions arising from a reorganization. 35-A M.R.S.A. S 708 (2)(A)(2). In
the context of a merger approval, the Commission will focus on the protection of
utility ratepayers from potential subsidization of or risks associated with a
utility's involvement with a new entity. Cf. Robert D. Cochrane et. al. v.
Bangor Hydro Electric, Request for Commission Investigation Into Bangor
Hydro-Electric Company's Practice of Installing or Monitoring Security Alarm
Systems, Order at 4, Docket No. 96-053 (Jan. 28, 1997) ("primary focus of
<PAGE>
[Section 707] investigation [is] on establishing the proper procedure to ensure
that utility ratepayers are insulated from any financial risks"). The
Commission has indicated that the "most effective way" to reach the goal of
protecting ratepayers under Section 707 is to require utilities to conduct
activities with the affiliated interest as a separate subsidiary. Id. Here, as
described in Paragraph 10 of this Petition, the Commission has already approved
the corporate structure of CMP Group in Docket No. 97-930. Section 707's goal
of separateness is thus achieved by the very terms of the merger, and the
Commission retains the ability to assure that costs associated with the
transaction are properly allocated.
REASONS TO GRANT THE PETITION
-----------------------------
21. The proposed merger should be approved under Sections 707 and 708
because the interests of ratepayers and investors will not be adversely
affected. To the contrary, the merger ensures the continuation of safe and
reliable service by a larger organization well established in the energy
business. Furthermore, Energy East's experience with open access and
competitive markets will facilitate the implementation of retail access and the
expansion of natural gas in the State and will encourage economic development.
22. As in the NYNEX case, the Commission will have a future opportunity to
explore rate issues arising from the merger in any post-ARP rate proceeding, and
thus need not perform that inquiry as part of this proceeding. CMP has
committed to a 10% rate reduction for customers as of March 1, 2000, and that
commitment remains unchanged by the merger.
<PAGE>
23. Other terms of the merger that help ensure continuity of quality
management and customer service include: (1) the planned retention of the
existing CMP Group holding company entity, with David Flanagan remaining CEO and
Arthur Adelberg serving on its Board; (2) retention of the current CMP Board of
Directors as an Advisory Board to CMP; (3) inclusion of David Flanagan and two
other current CMP Group directors as members of the Energy East Board; (4) the
appointment of David Flanagan as President and Arthur Adelberg as Senior Vice
President and Chief Financial Officer of Energy East, with both individuals
remaining based in Maine; (5) the retention of Sara Burns as President of CMP,
reporting to David Flanagan; (6) the retention of CMP's headquarters in Augusta,
Maine; (7) Energy East's commitment to preserve CMP's charitable and community
involvement at least at current levels; (8) similarity of Energy East and CMP
Group strategic directions and policies, particularly the focus on core energy
delivery businesses, and customer service, generation divestiture and retail
access matters and (9) the compatibility of Energy East and CMP Group
management, demonstrated through CMP Group's association with Energy East as a
co-venturer in CMP Natural Gas. Energy East's commitment to Maine is also
reflected in its track record of investing (with CMP Group) in development of
local gas distribution in Maine and its decision to open a corporate office in
Portland upon consummation of the merger.
RELIEF REQUESTED
----------------
WHEREFORE, for the above-stated reasons, Petitioners respectfully
request that the Commission:
(1) Expedite consideration of the Petition to assure receipt of
regulatory approval on or before December 31, 1999;
<PAGE>
(2) Approve the proposed reorganizations under 35-A M.R.S.A. SS 707 and
708, and such other provisions in Title 35-A that might be applicable,
consistent with the public interest;
(3) As part of its approval, remove certain conditions established in
Docket Nos. 97-930 and 98-077, including royalty payments and restrictions on
investment and debt issuances as more particularly described in this Petition;
and
(4) Grant such other relief as it deems appropriate.
________________________ ________________________
Raymond W. Hepper John W. Gulliver
Anne M. Pare Kevin F. Gordon
Deborah L. Shaw
Attorneys for Attorneys for
CMP Group, Inc. and Pierce Atwood
Central Maine Power Company One Monument Square
83 Edison Drive Portland, Maine 04101
Augusta, Maine 04336 (207) 791-1100
(207) 623-3521
<PAGE>
STATE OF CONNECTICUT
DEPARTMENT OF PUBLIC UTILITY CONTROL
JOINT APPLICATION OF ENERGY EAST : DOCKET NO. 99-08
CORPORATION AND CTG RESOURCES, :
INC. FOR APPROVAL OF A CHANGE OF :
CONTROL :
: AUGUST 11, 1999
JOINT APPLICATION
FOR
APPROVAL OF A CHANGE OF CONTROL
FOR ENERGY EAST CORPORATION FOR CTG RESOURCES, INC.
Kenneth M. Jasinski, Executive Vice Reginald L. Babcock, Vice President,
President and General Counsel General Counsel & Secretary
P.O. Box 1196 100 Columbus Boulevard
Stamford, Connecticut 06904-1196 P. O. Box 1500
Telephone: (203) 325-0690 Hartford, Connecticut 06144-1500
Facsimile: (203) 325-1901 Telephone: (860) 727-3459
Facsimile: (860) 727-3500
James E. Rice Dwight A. Johnson
Brody, Wilkinson and Ober, P.C. Murtha, Cullina, Richter and Pinney LLC
2507 Post Road CityPlace I, 185 Asylum Street
Southport, CT 06490-1259 Hartford, CT 06103-3469
Telephone: (203) 319-7112 Telephone: (860) 240-6024
Facsimile: (203) 254-1772 Facsimile: (860) 240-6150
<PAGE>
TABLE OF CONTENTS
PAGE
EXECUTIVE SUMMARY 1
I. INTRODUCTION 4
II. DESCRIPTION OF APPLICANTS 8
A. Energy East Corporation 8
-----------------------
B. CTG Resources, Inc. 10
------------------
C. Communications/Correspondence 12
-----------------------------
III. REASONS FOR THE MERGER AND DESCRIPTION OF THE 13
TRANSACTION
A. Reasons for the Merger 13
----------------------
1. Enhanced Competition 13
2. New Regulatory Framework 15
B. A Description of the Transaction 16
--------------------------------
IV. ALL OF THE STATUTORY CONDITIONS UNDER CONN. GEN. 18
STAT. 16-47 ARE SATISFIED FOR THE DEPARTMENT TO
APPROVE THE CHANGE IN CONTROL
A. Energy East is Financially Suitable to Acquire 18
---------------------------------------------
Control of CTG Resources, Inc.
------------------------------
B. Technological and Managerial Suitability of 19
-------------------------------------------
Energy East
-----------
C. The Connecticut Natural Gas Corporation 22
---------------------------------------
Will Continue to Provide Safe, Adequate and Reliable
----------------------------------------------------
Service to the Public
---------------------
-i-
<PAGE>
TABLE OF CONTENTS
PAGE
V. THE MERGER WILL BENEFIT CONNECTICUT, EMPLOYEES 23
AND CONSUMERS
VI. CONCLUSION 26
APPENDIX I - Compliance with Conn. Gen. Stat. S 16-47 Requirements 29
APPENDIX II - List of Exhibits 38
LIST OF EXHIBITS
-i-
<PAGE>
EXECUTIVE SUMMARY
CTG Resources, Inc. ("CTG") and Energy East Corporation ("Energy East")
come before the Department of Public Utility Control at a time of unparalleled
change in the energy industry, to present a merger plan that incorporates
important opportunities. In the space of just a few months, all of
Connecticut's local distribution companies ("LDCs") have announced merger plans,
including the merger plan recently announced by Connecticut Energy Corporation
and Energy East. The pace of this change is unprecedented.
One result of these developments will be the various proceedings before the
Department of Public Utility Control. Without minimizing the significance of
this Application, it is a fairly narrow proceeding that addresses well-defined
requirements, focused on the basic suitability of Energy East to acquire control
of the regulated assets of CTG. Matters concerning rates, revenues and related
issues are expected to be addressed fully in a separate proceeding which CTG's
regulated subsidiary, Connecticut Natural Gas Corporation ("CNG"), plans to file
later this year.
Unquestionably, the merger of CTG with Energy East will have a positive
impact on customers, employees and Connecticut, and the implications for
competition, are just as compelling. They are the foundations of the merger,
and this Application and the ensuing proceedings will clarify these advantages.
Considerable portions of this Application are identical to the application
filed in the Energy East/Connecticut Energy merger (Docket No. 99-07-20) and
other portions are very similar, in recognition of the common aspects of both
transactions. Nevertheless,
the two applications constitute independent proceedings, and each decision must
rest on its own merits.
1
<PAGE>
CNG has consistently posted a distinguished record of delivering quality
natural gas service to customers at low prices. Its gas costs have been lower
than those of the other Connecticut LDCs year after year, and generally are
lower than those of all other New England LDCs. It is recognized for the high
quality of both its customer service and record of consumer satisfaction. It has
been innovative in the development of non-traditional markets, first with its
interruptible customers and later with its off-system market. CNG leadership in
formulating policy with regulators and legislators has served the public and the
company extremely well.
It is imperative that this record of positive change and adaptation be
sustained, and the best means for CNG to continue doing so is through the
combination with Energy East. Energy East is committed to introducing an
innovative, new approach to natural gas ratemaking in Connecticut with its
proposal for an alternative rate regulation which provides ratepayers with rate
certainty and revenue sharing above certain thresholds and which provides the
utility with the opportunity for growth and rewards for assuming business and
financial risks. Such innovation offers striking benefits for gas customers,
and will distinguish Connecticut regulatory policy among the states. These
undertakings would be immensely more difficult, if not impossible, by CNG alone.
Energy East has developed a significant expertise through the similar rate
structure it pioneered in New York. CNG looks forward to capitalizing on the
learning curve that Energy East has already created.
2
<PAGE>
Energy East's knowledge goes well beyond expertise in ratemaking for LDCs.
As a combination gas and electric company, it understands the interrelation of
the natural gas and electricity markets. The ability to access this knowledge
base and participate on a more comprehensive basis in the northeastern energy
marketplace are significant advantages for CNG. Energy East has aggressively
expanded its gas business in New York, New Hampshire and Maine, and also seeks
to do so in Vermont. It will bring the same business approach to Connecticut.
CNG's business will grow, as new customers and new territories are served. In
short, Energy East is a prime mover in recognizing and seizing the opportunities
presented by the deregulation of the energy industry. Energy East is willing
to assume reasonable business risks while delivering the highest quality service
to customers.
3
<PAGE>
I. INTRODUCTION
Energy East and CTG (collectively "Applicants") herein request that the
Department of Public Utility Control ("Department") approve the change of
control of CTG, and particularly its regulated subsidiary, CNG, to Energy East.
This application ("Application") is made pursuant to Connecticut General
Statutes ("Conn. Gen. Stat.") S16-47 and SS16-1-65, 16-1-65A and 16-1-65B of the
Regulations of Connecticut State Agencies ("R.C.S.A.").
The proposed change of control transaction is structured as a merger of
Oak Merger Co., 1 and CTG. CTG will merge into Oak Merger Co., with Oak Merger
Co. being the surviving company. Oak Merger Co. will be renamed "CTG Resources,
Inc." and will continue to conduct CTG utility operations as a direct
wholly-owned subsidiary of Energy East (the "Merger"). As a result of the
transaction, Oak Merger Co. will become a wholly-owned first tier subsidiary of
Energy East, with CNG remaining as a wholly-owned, first tier subsidiary of Oak
Merger Co.2 CNG will, after consummation of the Merger, become an indirect
wholly-owned subsidiary of Energy East. There is no
___________________
1 Oak Merger Co. is a Connecticut corporation formed by Energy East in June,
1999 solely for the purpose of merging with CTG Resources. Oak Merger Co. is
wholly-owned by Energy East and is a different corporation than the merger
subsidiary created by Energy East to consummate the Connecticut Energy
transaction. The mailing address of Oak Merger Co.'s principal executive
offices is c/o Energy East Corporation, One Canterbury Green, Fourth Floor,
Stamford, Connecticut 06901.
2 CNG is subject to the jurisdiction of the Department as a public service
company pursuant to Title 16 of the Connecticut General Statutes: CNG is a "gas
company" and therefore, by definition, a public service company. Conn. Gen.
Stat. S 16-1.
4
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merger of public service companies.3 The change of control transaction will not
affect the Department's ability to regulate the operations of CNG.
CNG's management will remain in place, including the President and Chief
Executive Officer ("CEO"), who will remain located in Hartford. The current CNG
Board of Directors will continue as an Advisory Board with responsibility for
local community issues, including the investment of $500,000 in community
activities. All of these efforts will ensure continued and involvement by
current CTG and CNG management in CNG's future after the merger is completed.
CTG's principal unregulated subsidiary, The Energy Network ("TEN"),
which provides district heating and cooling services in Hartford, holds a
partnership interest in the Iroquois pipeline, and conducts other business, also
initially will remain a direct subsidiary of CTG and will become an indirect
wholly-owned subsidiary of Energy East.
To effectuate the transaction, Energy East and CTG have executed an
Agreement and Plan of Merger ("Merger Agreement"), dated as of June 29, 1999, a
copy of which is attached as Exhibit 1, and described in more detail below. The
proposed transaction will be consummated in accordance with all applicable
federal and state laws and regulations, including, but not limited to, the
Securities Act of 1933, the Securities
___________________
3 To the extent that the Department should find Conn. Gen. Stat. 16-43
applicable to this Merger, the Applicants and CNG have filed herein all
information required in R.C.S.A. S16-1-61, and the Applicants request the
Department to accept this Application as a request for approval under Conn. Gen.
Stat. S16-43.
5
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Exchange Act of 1934, the Hart-Scott-Rodino Antitrust Improvements Act of 1976,
(4) the Communications Act of 1934(5), and the Connecticut Business Corporation
Act. The Merger must be approved by CTG shareholders(6) and the Department.
The Merger will become effective when the parties to the Merger Agreement
file a certificate of merger with the Secretary of the State of Connecticut in
accordance with the Connecticut Business Corporation Act, or at a later time
that Energy East and CTG may specify in the certificate of merger. If the
Merger is approved at the Special Meeting, the effective time will occur as
promptly as possible after satisfaction or waiver of the remaining conditions to
the Merger contained in the Merger Agreement, including the receipt of
regulatory approvals.
___________________
4 The Department of Justice ("DOJ") may conduct an antitrust review of the
transaction under Section 7A of the Clayton Act, 15 U.S.C. S18a, as added by
Section 201 of the Hart-Scott-Rodino Antitrust Improvements Act of 1976, Pub. L.
No. 94-435, 90 Stat. 1390.
5 CNG holds radio station licenses from the Federal Communications Commission
("FCC") pursuant to the Communications Act of 1934 with respect to its dispatch
center and certain of its communications equipment and devices. CNG will be
applying to the FCC to approve transfer of the indirect holder of the licenses
pursuant to 47 U.S.C. S310(d) as a result of the merger.
6 Shareholder approval of the merger transaction requires the affirmative vote
of the holders of at least two-thirds of the shares of CTG common stock
outstanding on the record date for the special meeting of CTG shareholders to
vote on the Merger. No approval by the shareholders of Energy East is required
to effect the Merger. The CTG Board of Directors has determined that the Merger
Agreement and the transactions contemplated thereby are in the best interests of
CTG Resources and have recommended unanimously that the CTG shareholders vote
for the Merger proposal. In mid August, 1999, CTG expects to mail its Proxy
Statement/Prospectus to shareholders, a preliminary copy of which is annexed
hereto as Exhibit 2. A special shareholders' meeting to vote on the Merger will
be scheduled as soon as practicable after the mailing date ("Special Meeting").
6
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The Merger Agreement commits Energy East and CTG to consummate the
transaction once all regulatory and other required approvals are obtained.7
The Applicants desire to complete the Merger as expeditiously as possible. The
speed at which regulatory, technological and competitive changes in the electric
and natural gas utility and nonutility energy industries are occurring makes it
important for the Department to act expeditiously on this Application. In
addition, delays in the approval process mean delays in the expected benefits of
the Merger. Accordingly, the Applicants urge the Department to act as
expeditiously as possible to approve the proposed Merger. The Applicants will
work cooperatively with the relevant governmental agencies, including the
Department, to minimize any delay.8
___________________
7 As part of Appendix I, the Applicants have provided a brief description of
the status of Applicants' efforts to obtain each such approval.
8 Pursuant to Conn. Gen. Stat. S16-47(c), a surety bond in the amount of
$50,000, conditioned to indemnify the Department for merger related expenses,
has been filed with the transmittal letter accompanying this Application.
7
<PAGE>
Based on the information provided herein, the Applicants respectfully
request that the Department find that Energy East has satisfied the statutory
criteria in Conn. Gen. Stat. S16-47. In particular, Applicants request that the
Department find that: (i) Energy East has the financial, technological and
managerial suitability and responsibility to obtain control of CTG and CNG; and
(ii) CNG's ability to provide safe, adequate and reliable service using its
plant, equipment and manner of operation will not be adversely affected if the
Merger is approved.
II. DESCRIPTION OF APPLICANTS
A. ENERGY EAST CORPORATION
-------------------------
The legal name and principal place of business of Energy East is:
Energy East Corporation
One Canterbury Green, Fourth Floor
P.O. Box 1196
Stamford, Connecticut 06904-1196
Energy East is a corporation created and existing under the laws of the State of
New York, and has its corporate headquarters in Stamford, Connecticut. Energy
East was formed in 1997 and became the parent of New York State Electric & Gas
Corporation on May 1, 1998. Energy East, which is currently an exempt public
utility holding company under PUHCA, intends to register with the Securities and
Exchange Commission ("SEC") as a holding company under the Act. Energy East is
an energy delivery, products and services company with operations in New York,
Massachusetts, Maine, New Hampshire, Vermont and New Jersey, and has corporate
offices in New York and Connecticut.
Energy East's nonutility subsidiaries include XENERGY Enterprises, Inc.
and Energy East Enterprises, Inc., which invest in energy ventures and provide
energy and telecommunications services. As a holding company, Energy East
neither owns nor operates any significant physical properties.
8
<PAGE>
NYSEG, Energy East's principal subsidiary, is a public utility company
engaged in purchasing, transmitting and distributing electricity and purchasing,
transporting, and distributing natural gas. As part of corporate strategy, it
recently completed a divestiture of all of its coal-fired electric generation
facilities (2,300 MW). In accordance with its strategy of exiting the base-load
power generation business, NYSEG recently agreed to sell its 18% non-operating
interest in the Nine Mile Point 2 nuclear plant, which transaction is expected
to close early next year.
NYSEG's service territory, 99% of which is located outside the corporate
limits of cities, is in the central, eastern and western parts of the State of
New York. NYSEG's service territory has an area of approximately 19,900 square
miles and a population of 2,400,000. The larger cities in which NYSEG serves
both electricity and natural gas customers are Binghamton, Elmira, Auburn,
Geneva, Ithaca and Lockport. NYSEG serves nearly 817,000 electric customers and
243,000 natural gas customers. The service territory reflects a diversified
economy, including high-tech firms, light industry, colleges and universities,
agriculture, and recreational facilities. No customer accounts for 5% or more of
either electric or natural gas revenues. During 1996 through 1998, approximately
84% of NYSEG's operating revenues were derived from electric service with the
balance derived from natural gas service.
Upon final approval of Energy East's announced merger with CMP Group,
Energy East also is gaining control of Central Maine Power Company, which serves
530,000 electric customers in Central and Southern Maine. The transaction,
which values CMP Group common equity at approximately $957 million and includes
the assumption of $271 million in preferred stock and long-term debt, will have
no adverse effect on Energy East's merger with CTG .
9
<PAGE>
Upon final approval of Energy East's announced merger with Connecticut
Energy Corporation, Energy East is also gaining control of The Southern
Connecticut Gas Company, which serves approximately 158,000 customers in 22
municipalities in Connecticut. The transaction, which values Connecticut Energy
common equity at approximately $436 million and includes the assumption of
approximately $150 million in long-term debt, likewise will have no adverse
effect on Energy East's merger with CTG.
NYSEG has completely opened its gas distribution system to competition for
all consumer sectors. As of August 1, 1999, NYSEG's electric distribution system
was opened to all qualified electric suppliers to serve any of NYSEG's nearly
817,000 electric customers who elect to switch.
Energy East's consolidated 1998 adjusted revenues were $2,499,418,000 with
a net income of $194,205,000. Its assets valued at year end 1998 were
$4,883,337,000. Additional financial information regarding Energy East is
attached hereto in the preliminary Proxy (Exhibit 2) and in Exhibit 3.
B. CTG RESOURCES, INC.
---------------------
The legal name and principal place of business of CTG Resources is:
CTG Resources, Inc.
100 Columbus Boulevard
P.O. Box 1500
Hartford, Connecticut 06144-1500
10
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CTG, a Connecticut corporation, is an exempt public utility holding company,9
and neither owns nor operates any significant physical properties.
It has two direct wholly-owned subsidiaries, CNG and TEN, whose
operations are described below. CTG is engaged, through its subsidiaries, in
operations principally in Connecticut, with retail marketing of natural gas and
steam and chilled water in Connecticut.
Connecticut Natural Gas Corporation. CNG, a Connecticut public service
company wholly-owned by CTG , is primarily engaged in the retail distribution of
natural gas for residential, commercial, and industrial uses and the
transportation of natural gas for commercial and industrial uses.
CNG's predecessor, The Hartford City Gas Light Company (renamed The Hartford Gas
Company in 1927), was originally incorporated in Connecticut in 1848. CNG was
formed in 1968 as a result of the merger of The New Britain Gas Light Company
with The Hartford Gas Company. In 1974, The Greenwich Gas Company was merged
into CNG. CNG serves approximately 143,000 customers in Connecticut.
CNG has one subsidiary, CNG Realty Corp., which owns CNG's operating and
administrative center in Hartford that is leased to CNG.
The Energy Network, Inc. ("TEN"). The unregulated businesses of CTG are
conducted through TEN and its wholly-owned subsidiaries, The Hartford Steam
Company ("HSC"), TEN Transmission Company ("TEN Transmission"), ENI Gas
Services, Inc. ("ENI Gas") and TEN Gas Services, Inc. ("TEN Gas").
___________________
9 CTG Resources is a holding company that is exempt from the registration
requirement of PUHCA.
11
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TEN and HSC provide district heating and cooling services to many buildings
and complexes in Hartford. TEN also offers energy equipment rentals to
residential customers. TEN Transmission holds CTG 's 4.87% share in the
Iroquois Pipeline.
TEN Gas and ENI Gas formerly owned a natural gas marketer, but have sold
the assets of that company and are winding down their businesses. CTG 's
operating revenues totaled approximately $282,748,000 for the fiscal year ended
September 30, 1998. CTG 's consolidated net income for the same period was
$15,135,000. Its assets valued at September 30, 1998 were $459,181,000. CTG
and its subsidiaries had 553 full-time employees as of June 30, 1999, 504 of
these individuals were employed by CNG. Additional consolidated financial
information regarding CTG is attached hereto in Exhibits 2, 3 and 4.
C. COMMUNICATIONS/CORRESPONDENCE
-----------------------------
All communications and correspondence with respect to this Application
should be addressed or directed to the attorneys for Energy East as follows:
Kenneth M. Jasinski, Executive Vice President & General Counsel
Energy East Corporation
P.O. Box 1196
Stamford, Connecticut 06904-1196
Telephone: (203) 325-0690
Facsimile: (203) 325-1901
with copies to:
James E. Rice
Brody, Wilkinson and Ober, P.C.
2507 Post Road
Southport, CT 06490-1259
Telephone: (203) 319-7112
Facsimile: (203) 254-1772
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and to the attorneys for CTG:
Reginald L. Babcock, Vice President,
General Counsel & Secretary
100 Columbus Boulevard
PO Box 1500
Hartford, Connecticut 06144-1500
Telephone: (860) 727-3459
Facsimile: (860) 727-3500
Dwight A. Johnson
Murtha, Cullina, Richter and Pinney, LLP
CityPlace I, 185 Asylum Street
Hartford, CT 06103-3469
Telephone: (860) 240-6024
Facsimile: (860) 240-6150
III. REASONS FOR THE MERGER AND DESCRIPTION OF THE TRANSACTION
A. REASONS FOR THE MERGER
-------------------------
The Boards of Directors and management of Energy East and CTG believe that
the Merger will help position their combined companies to become one of the
premier distribution companies for energy and other services in the northeastern
United States by increasing financial flexibility and providing strategic growth
opportunities that will benefit both companies and their customers, employees,
and shareholders in a manner that neither company could achieve on its own.
1. ENHANCED COMPETITION
The Applicants believe the merger will join two companies with
complementary operations as well as a common vision of the future of the retail
and wholesale energy markets in the northeastern region of the United States.
As a result of utility deregulation and the increasingly competitive pressures
electric and natural gas utility companies face in the northeastern United
13
<PAGE>
States, natural gas distribution companies must be efficient, low-cost suppliers
of energy and related services with a diverse customer base. The Applicants
believe the merger will allow CTG to achieve these goals and, especially when
combined with the opportunities the Connecticut Energy and CMP Group mergers
present, will provide substantial strategic and financial benefits to CTG and
its customers, employees and shareholders.
A combination of the companies' complementary expertise and infrastructure,
including CTG's competitive natural gas distribution facilities in Connecticut
and Energy East's diversified electric and natural gas businesses throughout the
northeastern United States, will provide the combined company with the size and
scope necessary to be an effective participant in the emerging and increasingly
competitive electric and natural gas markets. With Energy East's strong capital
base, the combined company intends to continue to invest in the expansion of
CTG's distribution system and enhanced marketing efforts in order to increase
competition and customer choice in Connecticut.
The combined company will also use its distribution channels to market a
portfolio of energy related services throughout the northeastern United States.
The merger will create a company with the ability to develop and market
competitive new products and services and to provide integrated energy solutions
for its customers.
The combined company will also be financially stronger and will have a
broader customer base than CTG as an independent entity. Based on the 1998
results for CTG and Energy East, the total annual revenues for the combined
company for the first year after the merger is projected to be approximately
$3.386 billion.10 With Energy East's
___________________
10 These pro forma figures include financial information and adjustments for CMP
Group and Connecticut Energy for, among other items, merger-related expenses.
See Exhibit 2 of this Application for details.
14
<PAGE>
merger with CMP Group and Connecticut Energy, the combined company will serve
approximately 1.3 million electric customers in New York and Maine and more
than 500,000 natural gas customers in New York and Connecticut. This will
enhance CNG's ability to continue its investments in infrastructure and expand
its customer base.
2. NEW REGULATORY FRAMEWORK
This Merger will likely produce efficiencies, but at this juncture in the
process potential net savings and revenue enhancements have not been quantified.
CNG plans to make a filing pursuant to 16-19 to amend its rate schedule not
later than mid-October of this year to introduce performance-based rates. That
proceeding will provide the Department, and other interested parties, with the
opportunity to address potential savings and costs associated with the Merger,
as well as their appropriate ratemaking treatment.
CTG and Energy East intend to introduce an incentive regulatory framework
for competitive growth in Connecticut to achieve consumer benefits, in a
separate rate riling this year. This regulatory framework will have the
following characteristics:
- - Multi-Year Term.
- - Price cap for residential sales customers (including gas costs) and
pricing options for non-residential sales customers who would have the
option of selecting a fixed or an indexed price.
- - Elimination of the effects of Purchased Gas Adjustment and associated
future deferrals and relief from the Department's Decision in Docket
No. 94-01-12 regarding hedging transactions.
- - Open access for all approved customers and qualified suppliers.
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- - Earnings sharing mechanism - 50% to customers and 50% to
shareholders for earnings over a specified threshold.
- - Negotiated pricing and service offerings for large non-residential
customers without pre-approval from the DPUC.
- - Performance standards for measuring service quality.
- - Adoption of exogenous cost factors.
B. A DESCRIPTION OF THE TRANSACTION
------------------------------------
The Merger Agreement provides that CTG will merge into Oak Merger Co., a
wholly-owned subsidiary of Energy East (distinct from the merger subsidiary that
Energy East has formed to accomplish the Connecticut Energy merger). Oak Merger
Co. will be the surviving company and will continue to conduct CTG 's utility
and nonutility operations as a direct, wholly-owned subsidiary of Energy East.
In the Merger, each outstanding CTG share (other than those that are held by CTG
shareholders who may not have voted in favor of the merger and have properly
demanded dissenters' rights) will be converted into the right to receive cash,
Energy East common stock or a combination of cash and Energy East common stock.
At the effective time of the Merger, each outstanding share of CTG common
stock will be converted into the right to receive (i) $41.00 in cash or (ii) a
number of shares of Energy East common stock equal to the Exchange Ratio (as
defined below) or (iii) a combination of cash and shares of Energy East common
stock. The total transaction consideration will be comprised of 55% cash and
45% stock. To the extent cash or stock elections are over-subscribed, CTG
distributions to shareholders will be pro rated.
16
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The "Exchange Ratio" is equal to $41.00 divided by either (i) Energy East's
common stock price if such price is equal to or less than $30.13 and equal to or
more than $23.67, (ii) $30.13 if the Energy East common stock price is greater
than $30.13, in which case the Exchange Ratio shall equal 1.3609, or (iii)
$23.67 if the Energy East common stock is less than $23.67, in which case the
Exchange Ratio shall equal 1.7320. The Energy East common stock price shall be
equal to the average of the closing prices of the shares of Energy East on the
New York Stock Exchange Composite Transactions Reporting System, as reported in
the Wall Street Journal, for the 20 days immediately preceding the second
trading day prior to the effective time.
The total consideration to be received by CTG shareholders in the Merger,
based on the number of CTG shares and options outstanding of 8,648,029 and
73,600, respectively, as of June 30, 1999 is approximately $355 million. Energy
East anticipates funding the cash portion of the Merger consideration with
internally generated funds or the proceeds from the sale of its generating
assets.
17
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IV. ALL OF THE STATUTORY CONDITIONS UNDER CONN. GEN. STAT. S16-47 ARE
SATISFIED FOR THE DEPARTMENT TO APPROVE THE CHANGE IN CONTROL
Energy East has all of the necessary qualifications to acquire control of
CTG and its regulated subsidiary, CNG, and Energy East has satisfied, through
this Application, the statutory prerequisites for approval of the Merger. In
analyzing the transfer of control under Conn. Gen. Stat. S16-47, the Department
is required to take into consideration: (i) the financial, technological and
managerial suitability and responsibility of Energy East; and (ii) the ability
of CNG to provide safe, adequate and reliable service to the public through its
plant, equipment and operations, assuming the Application is approved by the
Department. As discussed below and in the numerous exhibits attached, all the
requirements in Conn. Gen. Stat. S16-47 are satisfied fully.
A. ENERGY EAST IS FINANCIALLY SUITABLE TO ACQUIRE CONTROL OF CTG
--------------------------------------------------------------------
Energy East has a strong financial base and is a progressive leader in the
introduction of competition to the natural gas and electric industries. Total
operating revenues were $2.5 billion in 1998, up 15% from the 1997 level of
$2.17 billion. Net income was $194 million in 1998, up 11% from $175 million in
1997. Assets valued at year end 1998 were $4.9 billion. Earnings per share
were also up to $3.02 in 1998, an increase of 18% compared to earnings per share
of $2.57 in 1997. With these strong financial results, Energy East is better
positioned to grow and meet the challenges of an emerging competitive market.
Energy East's strong financial position makes it well suited to acquire CTG.
The very successful auction of NYSEG's coal-fired generation facilities
resulted in significant gains that eliminated stranded costs, including nuclear
costs. NYSEG's nuclear operating risk and the risk of increasing
decommissioning costs will also be eliminated as a result of the recently
announced sale of NYSEG's 18% ownership in the Nine Mile 2 nuclear facility to
AmerGen.
18
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Energy East's subsidiary, NYSEG, recently received a credit rating upgrade
by Moody's from Baa1 to A3 and an upgrade of senior secured debt by Standard &
Poor's from BBB+ to A. The reduced risk and the significant cash from the sale
of generating assets have put Energy East in a position from which it can expand
its core business.
B. TECHNOLOGICAL AND MANAGERIAL SUITABILITY OF ENERGY EAST
-------------------------------------------------------------
The best way to describe the technological and managerial suitability and
responsibility of Energy East to exercise control over CTG and CNG is to look at
the operations of its largest subsidiary, NYSEG. NYSEG is a combination
electric and gas corporation which provides electric service to 817,000
customers in 149 cities and villages, and 373 towns in New York State; and
provides gas service to 243,000 customers in 85 cities and villages, and 143
towns. The electric systems presently provide open access transmission and
distribution to large commercial and industrial customers and, as of August 1,
1999, all customers will be able to choose their own electric supplier and have
the transmission and distribution service provided by NYSEG. The natural gas
system has provided transportation for large customers since 1986, and for all
customers since 1996. At the present time approximately 38% of the throughput
of the gas system is third-party gas. The gas business unit of NYSEG holds
contracts for firm transportation on 11 pipelines, and has contracted for
storage on 3 pipelines. NYSEG also owns and operates the only high
deliverability salt storage field in the Northeast.
19
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As of year end 1998, NYSEG owned and operated 55 miles of high pressure
pipeline, 400 miles of transmission pipeline, 4,000 miles of main, 3,200 miles
of services, and 1,195 regulator stations. NYSEG receives its gas at 85
separate delivery points and continues to add new delivery points each year as
NYSEG expands its service territory. In the last four years, NYSEG has
instituted service to 25 new franchise areas in the State of New York, which is
more system expansion than all the other utility companies in New York have
added in the last 20 years. In order to successfully grow its system in a time
of substantial change in the gas industry, it was necessary to develop a new
approach to providing service to the customers. The approach had many features
and covered everything from gas supply and operations to customer service and
rates.
In the operations area, NYSEG rewrote its operations manual so that it
meets and exceeds the requirements of the safety codes of New York State and the
U.S. Department of Transportation. Policies were instituted to provide for more
preventive maintenance, additional leak surveys and the repair of all leaks on
the system, no matter how small. NYSEG updated its meter testing lab with
state-of-the-art equipment to make it more efficient. The gas training
department was enhanced to not only provide all the necessary training and
operator qualification training required to meet the federal and state codes and
job requirements, but also provide training to all fire, police and emergency
responders in the service territory so that they are capable of dealing with a
gas emergency situation.
NYSEG uses contractors to perform most of its construction and main
replacement through an alliance program. This program, which has been approved
by the New York Public Service Commission, allows NYSEG to work with a select
list of contractors instead of putting jobs out for bid each time a need arises.
Working with these select contractors has resulted in a 35% reduction in the
cost of construction for NYSEG.
20
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The gas supply department purchases the gas necessary to meet customer
requirements and manages all of NYSEG's pipeline and storage assets. NYSEG
purchases its gas from approximately 25 different suppliers under varying
contract terms. Approximately 45% of its gas is purchased under contracts with
a term of one to three years. Twenty-two% is purchased under contracts with a
term of less than one year, and 33% is purchased on the spot market. The gas
supply department, which includes a team of Houston-based gas trading
specialists, also does the hedging required to manage NYSEG's gas supply price
risk and is constantly involved in purchasing or selling futures, options, puts,
calls and swaps, and in release of pipeline capacity. The gas supply department
also acts as agent for many large industrial customers, purchasing gas for them,
and arranging transportation to city gates under long-term fixed-price
contracts.
In the customer service area, NYSEG established a centralized call center
for all its New York customers, permitting customer inquiries to be handled
more expeditiously and consistently. The activities of the customer service
unit have resulted in NYSEG obtaining the lowest customer complaint rate of any
utility in the State of New York, and an 85% customer satisfaction rating.
Another important part of customer service is NYSEG's economic development
department, which works with local authorities to retain and attract industrial
and commercial customers to provide jobs within the communities; and the
marketing department, which sells energy services directly to large industrial
and commercial customers. The economic development unit also maintains a data
base for each category of NYSEG's service territory relating to facilities, real
estate, taxes, utilities and special incentives that is available to industrial
customers moving into the area. The unit makes this data available to
companies throughout the United States and, in some cases, other countries, to
21
<PAGE>
interest them in locating new facilities in the service territory. Key account
representatives work with existing customers in order to retain companies in the
service territory or to help them expand and provide additional jobs in the
service territory. NYSEG has a program to make low interest loans available to
any industrial customer for new equipment in order to retain or obtain
additional jobs, with the loan being paid back from the margin of the gas
services over three to five years. Also, the company will provide a special
discounted rate for any increased service that is utilized to provide additional
jobs.
In summary, Energy East brings to Connecticut the technological and
managerial resources and experience from NYSEG that complement those of CTG
and the planned combination with Connecticut Energy.
C. CNG WILL CONTINUE TO PROVIDE SAFE, ADEQUATE AND RELIABLE SERVICE TO THE
-----------------------------------------------------------------------
PUBLIC
- ------
The ability of CNG to provide safe, adequate and reliable service
through its plant, equipment and manner of operation will not be adversely
affected by the Merger. CNG will continue to be headquartered in Hartford,
operated independently and regulated as a public service company in the manner
prescribed by Title 16 of the Connecticut General Statutes and in all
applicable Department regulations, decisions and orders. CNG also will continue
to remain subject to various federal regulations, including regulations which
(1) provide for emergency authority and curtailment allocations under the
Natural Gas Policy Act of 1978 when pipeline supplies are limited and (2)
establish certain retail policies for natural gas utilities under the Public
Utility Regulatory Policies Act of 1978. CNG will also continue to be subject to
the Natural Gas Pipeline Safety Act of 1968 with respect to the construction,
operation and maintenance of its mains, services and LNG Facility as well as
other federal regulations pertaining to safety standards concerning such
facilities.
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<PAGE>
The Merger will have no effect on CNG's commitment to providing safe,
adequate and reliable service to the public. CNG's maintenance and operation of
its gas distribution system facilities will not change. CNG's investments in
infrastructure will not be adversely affected. CNG will continue to extend its
distribution system within its franchise territories.
V. THE MERGER WILL BENEFIT CONNECTICUT, EMPLOYEES AND CONSUMERS
The Merger will join two companies with complementary operations as well as
a common vision of the future of the retail and wholesale energy markets in the
northeastern region of the United States.
In order to succeed in the increasingly competitive market facing electric
and natural gas utility companies in the Northeast, CTG must be an efficient,
low-cost supplier of energy and related services with a diverse customer base.
The CTG Board of Directors believes the Merger will allow CTG to better
achieve these goals and to provide substantial strategic and financial benefits.
Furthermore, Energy East and NYSEG, together with Connecticut Energy and CMP
Group, can leverage their collective experience and skills with CTG to
profitably grow the utility and non-utility businesses in the expanded service
territory. The combined companies will have the assets and management team
(which includes CTG and CNG participants) to succeed.
The Merger will therefore benefit CNG, CNG's employees, natural gas
consumers within CNG's franchise territory (including those potential customers
not currently served), and consumers of unbundled utility services throughout
Connecticut. The combined experience and resources of CTG and Energy East will
provide increased expertise, financial resources and economies of scale. These
23
<PAGE>
greater resources will enable CTG and CNG to: (i) accelerate distribution system
expansion and increase natural gas market penetration within the franchise
territory; (ii) continue CNG's commitment to service quality in an increasingly
competitive and dynamic regulatory environment; and (iii) introduce new
energy-related products and services to provide integrated energy solutions for
customers within CNG's franchise territory and throughout Connecticut.
As the Department is well aware, the natural gas industry is in the midst
of a transition from bundled to unbundled service. Unbundling began in
Connecticut as of April 1, 1996 with respect to commercial and industrial
customers. The process of unbundling to residential customers is being examined.
This will create a climate of competitive and increasingly dynamic forces in
which CNG will have to operate. Against that background, CNG now provides
natural gas service to less than 80% of the potential utility customers on mains
and 52% of the potential utility customers within its franchise territory in the
communities which CNG currently serves. CNG is authorized to install mains and
sell natural gas in several communities in its franchise territory where CNG
currently has no facilities.
Historically, CNG has balanced its desire to invest in system expansion
with prudent fiscal management policies. The Merger may offer CNG greater
opportunities to utilize its supply resources more efficiently through increased
cooperative efforts with Energy East and The Southern Connecticut Gas Company,
Connecticut Energy's regulated subsidiary. This additional financial strength
through a combined company, which will have a broader customer base than either
CTG or Energy East as independent entities, will benefit CNG, CNG's employees
and all consumers in Connecticut, especially those consumers situated in CNG's
franchise territory. Upon completion of all three of the pending transactions
24
<PAGE>
with CTG, Connecticut Energy and CMP Group, Energy East will have the scale and
critical mass necessary to succeed in today's ever-changing energy marketplace.
Energy East will become one of the largest energy providers in the Northeast and
will have more than 1.3 million electric customers and more than 500,000 natural
gas customers in Connecticut, Maine, and New York.
CNG's tradition of investing in Connecticut and the communities which it
serves will continue as a result of the Merger and actually increase. CNG's
operating headquarters will remain in Hartford. Energy East has pledged in the
Merger Agreement not only to continue CNG's historic level of charitable
contributions, but to more than double the charitable contributions from
$180,000 to $500,000 per year. CNG also intends to continue employee programs
promoting volunteerism, especially in the communities which CNG serves. Energy
East also has pledged its full cooperation for the necessary relocation of CTG's
facilities in connection with Adriaen's Landing in Hartford. CNG therefore is
continuing its rich history as a generous corporate citizen in Connecticut.
After the Merger and the completion of the Connecticut Energy transaction,
Energy East will be structured to offer Connecticut consumers new energy-related
products and services which package integrated energy solutions for customers
within CNG's franchise territory and throughout Connecticut. As previously
mentioned, two of Energy East's subsidiaries, XENERGY Enterprises and Energy
East Enterprises, will relocate to Connecticut. Energy East and CTG intend to
integrate those Energy East subsidiaries with the current nonutility operations
of CTG, to offer new energy-related products and services to consumers in
Connecticut and throughout the Northeast.
As the benefits of energy deregulation become available in Connecticut, the
merged company's nonutility subsidiaries will be well situated to offer
meaningful competition in the Connecticut marketplace. At a time when many
natural gas marketing companies are struggling to survive in the climate of
volatile natural gas prices and changing transportation tariff requirements
imposed by LDCs in Connecticut, the merged company will also offer Connecticut's
commercial and industrial natural gas consumers a financially solid natural gas
marketing competitor. As the benefits of natural gas deregulation become
available to residential consumers in Connecticut, the merged company's
25
<PAGE>
nonutility subsidiaries will also be poised to deliver competitive energy
products and services to homeowners throughout Connecticut. In short, the
Merger presents a unique opportunity for CTG to bring to Connecticut the
resources of a leading energy delivery, products and services company in the
Northeast region. CNG's employees and customers throughout Connecticut will
benefit from the Merger.
VI. CONCLUSION
For the reasons discussed above, the proposed Merger meets the applicable
statutory requirements. The Merger will serve the interests of all customers of
natural gas and energy services in Connecticut in the context of a rapidly
changing natural gas and energy environment. Accordingly, Energy East and CTG
request the Department to approve the Merger.
26
<PAGE>
Respectfully submitted,
ENERGY EAST CORPORATION
By: /S/ KENNETH M. JASINSKI
---------------------------------------
Kenneth M. Jasinski
Executive Vice President and General Counsel
P.O. Box 1196
Stamford, Connecticut 06904-1196
Tel: (203) 325-0690
Fax: (203) 325-1901
By: /S/ JAMES E. RICE
---------------------------------------
James E. Rice
Brody, Wilkinson and Ober, P.C.
2507 Post Road
Southport, CT 06490-1259
Tel: (203) 319-7112
Fax: (203) 254-1772
CTG RESOURCES, INC.
By: /S/ REGINALD L. BABCOCK
---------------------------------------
Reginald L. Babcock
100 Columbus Boulevard
PO Box 1500
Hartford, Connecticut 06144-1500
Tel: (860) 727-3459
Fax: (860)727-3500
By: /S/ DWIGHT A. JOHNSON
---------------------------------------
Dwight A. Johnson
Murtha, Cullina, Richter and Pinney LLC
CityPlace I - 185 Asylum Street
Hartford, Connecticut 06103-0197
Tel: (860) 240-6024
Fax: (860)240-6150
27
<PAGE>
THIS DOCUMENT (INCLUDING ALL EXHIBITS) CONTAINS FORWARD-LOOKING STATEMENTS
WITHIN THE MEANING OF SECTION 21E OF THE SECURITIES EXCHANGE ACT OF 1934. THE
FORWARD-LOOKING STATEMENTS ARE SUBJECT TO VARIOUS RISKS AND UNCERTAINTIES.
RISK FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM
MANAGEMENT'S PROJECTIONS, FORECASTS, ESTIMATES AND EXPECTATIONS MAY INCLUDE
FACTORS THAT ARE BEYOND THE COMPANY'S ABILITY TO CONTROL OR ESTIMATE PRECISELY,
SUCH AS ESTIMATES OF FUTURE MARKET CONDITIONS, THE ABILITY TO REALIZE COST
SAVINGS, AND THE TIMING AND TERMS ASSOCIATED WITH OBTAINING REGULATORY
APPROVALS. OTHER FACTORS INCLUDE, BUT ARE NOT LIMITED TO, WEATHER CONDITIONS,
ECONOMIC CONDITIONS IN THE COMPANIES' SERVICE TERRITORIES, FLUCTUATIONS IN
ENERGY-RELATED COMMODITY PRICES, AND OTHER UNCERTAINTIES. OTHER RISK FACTORS
ARE DETAILED FROM TIME TO TIME IN THE APPLICANTS' SEC REPORTS.
28
<PAGE>
APPENDIX I
Docket No. 99-08
August 11, 1999
I. COMPLIANCE WITH CONN. GEN. STAT. 16-47 REQUIREMENTS
For purposes of the following R.C.S.A. sections, the Applicants are Energy East
- --------------------------------------------------------------------------------
and CTG Resources:
- -------------------
SECTION 16-1-46(A) APPLICATION SHOULD STATE CLEARLY THE REQUEST FOR APPROVAL
OF THE MERGER; CITE THE STATUTORY PROVISIONS AND
AUTHORITY UNDER WHICH AUTHORIZATION CAN BE GRANTED BY
THE DEPARTMENT; AND ALSO INCLUDE (A) NAME OF EACH PERSON
SEEKING AUTHORIZATION AND THE ADDRESS AND PRINCIPAL
PLACE OF BUSINESS AS WELL AS THE STATE UNDER WHICH THE
CORPORATION WAS ORGANIZED; (B) NAME, TITLE, ADDRESS AND
TELEPHONE NUMBER OF THE ATTORNEY TO WHOM CORRESPONDENCE
SHOULD BE ADDRESSED AND SERVICE MADE, (C) A CONCISE AND
EXPLICIT STATEMENT OF THE FACTS RELEVANT TO THE
DEPARTMENT'S AUTHORIZATION OR APPROVAL INCLUDING PUBLIC
CONVENIENCE AND NECESSITY; AND (D) AN EXPLANATION OF
ANY UNUSUAL CIRCUMSTANCES INVOLVING THE PETITION OR
APPLICATION, INCLUDING EMERGENCY CONDITIONS.
(a) See Application, Sections I, II.A., and II.B.
(b) See Application, Section II.C.
(c) See Generally Application and Exhibits thereto.
(d) The Merger Agreement intends an effective time prior to
June 29, 2000. See Merger Agreement at 42 (Exhibit 1).
SECTION 16-1-65(A) GENERAL DESCRIPTION OF THE PROPERTY, FIELD OF OPERATION,
AND EXISTING BUSINESS INTERESTS OF THE APPLICANT OR
DESCRIPTION OF THE OFFICIAL, BOARD OR COMMISSION
PURPORTING TO ACT UNDER ANY GOVERNMENTAL AUTHORITY OTHER
THAN THAT OF THIS STATE (CONNECTICUT) OR OF ITS
DIVISIONS, MUNICIPAL CORPORATIONS OR COURTS.
See Exhibit 11 (Energy East SEC Form 10-K for year ended 12/31/98);
Exhibit 12 (Energy East 1998 Annual Report).
29
<PAGE>
SECTION 16-1-65(B) APPLICANT'S FINANCIAL STATEMENT FOR THE MOST RECENT
FISCAL YEAR AND THE PRO FORMA PERIOD (INCLUDE
ASSUMPTIONS), GIVING EFFECT TO THE ACQUISITION, TO
INCLUDE BALANCE SHEET, INCOME STATEMENT AND STATEMENT OF
SOURCE AND APPLICATION OF FUNDS.
See Exhibit 3 (Energy East and CTG Resources Unaudited Pro Forma
Combined Financial Statements).
SECTION 16-1-65(C) APPLICANT'S MOST RECENT FORM 10-K AND SUBSEQUENT FORMS
10-Q FILED WITH THE SEC OR COMPARABLE INFORMATION.
See Exhibit 3 (Energy East and CTG Resources Unaudited Pro
Forma Combined Financial Statements);
Exhibit 4 (CTG Resources SEC Form 10-K for the fiscal year
ending 9/30/98);
Exhibit 5 (CTG Resources SEC Form 10-Q for the period
ending 12/31/98);
Exhibit 6 (CTG Resources SEC Form 10-Q for the period
ending 3/31/99);
Exhibit 7 (CTG Resources SEC Form 10-Q for the period
ending 6/30/99);
Exhibit 11 (Energy East SEC Form 10-K for the year ending
12/31/98);
Exhibit 12 (Energy East 1998 Annual Report);
Exhibit 13 (Energy East SEC Form 10-Q for the period ending
3/31/99);
Exhibit 14 (Energy East SEC Form 10-Q for the period ended
6/30/99);.
Exhibit 27 (CTG Resources 1998 Annual Report and 1998 Proxy
Statement).
SECTION 16-1-65(D) APPLICANT'S MOST RECENT FORM 8-K FILED WITH THE SEC OR
COMPARABLE INFORMATION.
See Exhibit 15 (Energy East SEC Form 8-K dated 4/26/99);
Exhibit 18 (CTG Resources SEC Form 8-K dated 6/29/99).
SECTION 16-1-65(E) APPLICANT'S MOST RECENT ANNUAL REPORT TO STOCKHOLDERS, OR
COMPARABLE INFORMATION IS SUCH REPORT IF NOT PUBLISHED.
See Exhibit 12 (Energy East 1998 Annual Report);
Exhibit 27 (CTG Resources 1998 Annual Report and 1998
Proxy Statement).
30
<PAGE>
SECTION 16-1-65(F) APPLICANT'S LATEST PROXY STATEMENT SENT TO STOCKHOLDERS,
OR COMPARABLE INFORMATION IF SUCH REPORT IS NOT PUBLISHED.
See Exhibit 16 (Energy East Notice of 1999 Annual Meeting and Proxy
Statement);
Exhibit 27 (CTG Resources 1998 Annual Report and 1998
Proxy Statement).
SECTION 16-1-65(G) DESCRIPTION OF TRANSACTION OR SERIES OF TRANSACTIONS,
INCLUDING INTENDED FINANCING, BY WHICH THE PROPOSED
TRANSACTION WILL BE EFFECTED, AND AGREEMENTS OR OTHER
INSTRUMENTS ASSOCIATED WITH THE PROPOSED TRANSACTION.
See Application, Section III.B.,
Exhibit 1 (Merger Agreement);
Exhibit 2 (CTG Resources Preliminary Proxy Statement/Prospectus dated
7/30/99 (the "Preliminary Merger Proxy").
SECTION 16-1-65(H) A STATEMENT OF THE PURPOSE AND INTENT OF THE APPLICANT IN
UNDERTAKING THE PROPOSED TRANSACTION(S).
See Application, Section III.A.,
Exhibit 1 (Merger Agreement);
Exhibit 2 (Preliminary Merger Proxy).
SECTION 16-1-65(I) A STATEMENT OF THE BENEFITS, INCLUDING RATES, STANDARDS
OF SERVICE AND EFFICIENCY AND ADEQUACY OF MANAGEMENT, THAT
WOULD RESULT TO THE CUSTOMERS AND STOCKHOLDERS OF THE
PUBLIC SERVICE COMPANY OR HOLDING COMPANY THE INTERFERENCE
WITH, OR ACQUISITION OR CONTROL OF WHICH, IS THE SUBJECT
OF THE APPLICATION (HEREINAFTER "AFFECTED COMPANY").
See Application, Sections IV and V;
Exhibit 1 (Merger Agreement);
Exhibit 2 (Preliminary Merger Proxy).
SECTION 16-1-65(J) ANY PROSPECTUS, OFFICIAL STATEMENT, PRELIMINARY
PROSPECTUS OR PRELIMINARY OFFICIAL STATEMENT PREPARED BY
OR ON BEHALF OF THE APPLICANT OR ANY OTHER PERSON WITH
REGARD TO THE PROPOSED TRANSACTION.
31
<PAGE>
See Exhibit 2 (Preliminary Merger Proxy);
Exhibit 15 (Energy East SEC Form 8-K dated 4/23/99).
SECTION 16-1-65(K) APPLICANT'S CAPITAL STRUCTURE AND CAPITALIZATION RATIOS,
PRESENT AND PRO FORMA (INCLUDE ASSUMPTIONS), ASSUMING
APPROVAL OF THE PROPOSED TRANSACTION.
See Exhibit 19 (Energy East Capital Structure and Ratios, Including
Pro Forma);
Exhibit 25 (CTG Resources Capital Structure and Ratios).
SECTION 16-1-65(L) APPLICANT'S INTEREST (BEFORE AND AFTER INCOME TAXES) AND
FIXED CHARGE COVERAGES, PRESENT AND PRO FORMA (INCLUDE
ASSUMPTIONS), ASSUMING APPROVAL OF THE PROPOSED
TRANSACTION.
See Exhibit 20 (Energy East Interest and Fixed Charge Coverages,
Including Pro Forma).
SECTION 16-1-65(M) PROPOSED TABLE OF ORGANIZATION OF THE MANAGEMENT OF THE
APPLICANT, AND OF THE AFFECTED COMPANY, AFTER GIVING
EFFECT TO THE PROPOSED TRANSACTION, INCLUDING THE NAME OF
EACH EXECUTIVE OFFICER ON EACH SUCH PROPOSED TABLE OF
ORGANIZATION.
See Exhibit 9 (Energy East and CTG Resources Proposed Organization
Chart and Officers - Post Merger).
SECTION 16-1-65(N) NAMES OF THE PROPOSED MEMBERS OF THE BOARD OF DIRECTORS
OF THE APPLICANT, AND OF THE AFFECTED COMPANY, AFTER
GIVING EFFECT TO THE PROPOSED TRANSACTION.
See Exhibit 10 (Energy East and CTG Resources Proposed Boards of
Directors - Post Merger).
SECTION 16-1-65(O) NARRATIVE DESCRIPTION OF THE PROPOSED OPERATIONS OF THE
APPLICANT AND THE AFFECTED COMPANY FOR THE FIRST CALENDAR
YEAR FOLLOWING THE EFFECTIVENESS OF THE PROPOSED
TRANSACTIONS(S), INCLUDING, BUT NOT LIMITED TO, EMPLOYMENT
LEVELS AND OFFICE AND SERVICE CENTER LOCATIONS, AND DETAILS
OF ALL CHANGES FROM THE EXISTING OPERATIONS OF THE
AFFECTED COMPANY.
32
<PAGE>
See Application, Section IV.
SECTION 16-1-65(P) A DESCRIPTION OF THE EXPERIENCE OF EACH OF THE APPLICANTS
IN THE OPERATION, MANAGEMENT OR CONTROL OF ANY PUBLIC
SERVICE COMPANY, AND, TO THE EXTENT NOT OTHERWISE
PROVIDED, A STATEMENT AS TO THE SUITABILITY OF THE
APPLICANTS TO CONTROL THE AFFECTED COMPANY.
See Application, Sections II.A., II.B., IV.A., and IV.B.
SECTION 16-1-65(Q) A LIST OF ALL DEPARTMENT ORDERS, RULINGS AND REGULATIONS
IN EFFECT AND APPLICABLE TO THE AFFECTED COMPANY, AND
AN INDICATION OF THOSE WHICH THE APPLICANT PROPOSES WOULD
BE DISCONTINUED IN CONNECTION WITH THE PROPOSED
TRANSACTION(S), TOGETHER WITH A STATEMENT OF THE REASON
FOR EACH SUCH PROPOSED DISCONTINUANCE.
The Applicants do not anticipate that the Merger will have any impact on
any Department orders, rulings, or regulations in effect and applicable to
CNG.
SECTION 16-1-65(R) A LIST OF STOCKHOLDER APPROVAL AND ALL FEDERAL, STATE AND
LOCAL GOVERNMENTAL APPROVALS REQUIRED IN ORDER TO
EFFECT THE PROPOSED TRANSACTION(S), TOGETHER WITH A
DESCRIPTION OF THE STATUS OF THE APPLICANT'S EFFORTS TO
OBTAIN EACH SUCH APPROVAL AS OF THE DATE REASONABLY
PROXIMATE TO THE DATE OF THE APPLICATION.
Department of Justice/Antitrust Division - Hart-Scott-Rodino premerger
notification to be filed as
expeditiously as possible.
(The Department of Justice will
conduct a review of the
competitive aspects of the
Merger transaction.)
Federal Trade Commission - Premerger notification forms
to be filed.
Securities and Exchange Commission ("SEC") - Preliminary Merger Proxy filed
on 7/30/99. The SEC will not
review. Definitive Merger
Proxy to be filed as
expeditiously as possible.
33
<PAGE>
Federal Communications Commission ("FCC") - Application seeking approval
for the transfer of control of
certain FCC authorizations to
be filed as soon as
practicable.
Department of Public Utility Control - This Application.
CTG Resources shareholders - Definitive Merger Proxy will be
mailed to shareholders as soon
as practicable and a special
meeting of CTG Resources
shareholders will be scheduled
to occur as soon after the
mailing date as possible.
SECTION 16-1-65(S) A STATEMENT OF THE PERCENTAGE OF VOTING SECURITIES OF THE
AFFECTED COMPANY OWNED OR CONTROLLED BY THE APPLICANT, AND
CONTROL EXERCISED OR CAPABLE OF BEING EXERCISED OVER THE
PUBLIC SERVICE COMPANY AFTER THE CONCLUSION OF THE PROPOSED
TRANSACTION.
See Exhibit 2 (Preliminary Merger Proxy).
For purposes of the following R.C.S.A. sections "affected" company is
- ------------------------------------------------------------------------------
interpreted to mean CTG Resources:
- -------------------------------------
SECTION 16-1-65B(A) AFFECTED COMPANY'S FINANCIAL STATEMENTS FOR THE MOST
RECENT FISCAL YEAR AND THE PRO FORMA PERIOD (INCLUDE
ASSUMPTIONS), WITH AND WITHOUT APPROVAL OF THE PROPOSED
TRANSACTION, TO INCLUDE BALANCE SHEET, INCOME STATEMENT AND
STATEMENT OF SOURCE AND APPLICATION OF FUNDS.
See Exhibit 4 (CTG Resources SEC Form 10-K for the fiscal year ending
9/30/98);
Exhibit 5 (CTG Resources SEC Form 10-Q for the period ending 12/31/98);
Exhibit 6 (CTG Resources SEC Form 10-Q for the period ending 3/31/99);
Exhibit 7 (CTG Resources SEC Form 10-Q for the period ending 6/30/99);
Exhibit 27 (CTG Resources 1998 Annual Report and 1998 Proxy Statement).
SECTION 16-1-65B(B) AFFECTED COMPANY'S EXISTING REPORTING STRUCTURE FOR
PERSONNEL, FROM CONNECTICUT LOCAL OPERATIONS TO CHIEF
EXECUTIVE OFFICER, INCLUDING BOARD OF DIRECTORS.
34
<PAGE>
See Exhibit 24 (Existing CTG Resources Corporate Structure).
SECTION 16-1-65B(C) AFFECTED COMPANY'S CAPITAL STRUCTURE AND CAPITALIZATION
RATIOS, PRESENT AND PRO FORMA (INCLUDE ASSUMPTIONS),
GIVING EFFECT TO THE PROPOSED TRANSACTION.
See Exhibit 25 (CTG Resources Capital Structure and Ratios).
SECTION 16-1-65B(D) AFFECTED COMPANY: ANY PROSPECTUS, OFFICIAL STATEMENT,
PRELIMINARY PROSPECTUS OR PRELIMINARY OFFICIAL
STATEMENT ASSOCIATED WITH THE TRANSACTION FOR WHICH
APPROVAL IS SOUGHT.
See Exhibit 2 (Preliminary Merger Proxy);
Exhibit 18 (CTG Resources SEC Form 8-K dated 6/29/99).
SECTION 16-1-65B(E) AFFECTED COMPANY: A STATEMENT OF THE INTERFERENCE,
AUTHORITY OR CONTROL THAT APPLICANT IS CAPABLE OF
EXERCISING OVER THE AFFECTED COMPANY AFTER COMPLETION
OF THE PROPOSED TRANSACTION.
See Exhibit 1 (Merger Agreement);
Exhibit 2 (Preliminary Merger Proxy).
35
<PAGE>
II. COMPLIANCE WITH CONN. GEN. STAT. 16-43 REQUIREMENTS
For purposes of the following regulations, the applicant is CNG:
- ------------------------------------------------------------------------
SECTION 16-1-61(A)(1) STATEMENT OF FINANCIAL CONDITION OF APPLICANT AND
SURVIVING COMPANY. THESE STATEMENTS MUST REFLECT THE
FINANCIAL CONDITION OF THE SURVIVING COMPANY BEFORE
AND AFTER THE MERGER.
See Exhibit 21 (CNG Audited 1998 Financial Statements);
Exhibit 22 (CNG Unaudited Financial Statements ending 6/30/99);
Exhibit 23 (CNG Annual Report to DPUC on FERC Form No. 2 for the
period ending 9/30/99).
SECTION 16-1-61(A)(2) COPY OF THE MERGER OR ACQUISITION AGREEMENT.
See Exhibit 1 (Merger Agreement).
SECTION 16-1-61(A)(3) DESCRIPTION OF APPLICANT'S PROPERTY, FIELD OF
OPERATION, ORIGINAL COST OF PROPERTY AND EQUIPMENT
(INDIVIDUALLY OR BY CLASS), COST OF PROPERTY AND
EQUIPMENT TO APPLICANT, DEPRECIATION AND AMORTIZATION
RESERVES APPLICABLE TO SUCH PROPERTY AND EQUIPMENT
(INDIVIDUALLY OR BY CLASS).
See Exhibit 26 (CNG Fixed Asset Report);
Exhibit 2 (Preliminary Merger Proxy).
SECTION 16-1-61(A)(4) FINANCIAL STRUCTURE OF THE DEAL.
See Application, Section III.B.,
Exhibit 1 (Merger Agreement);
Exhibit 2 (Preliminary Merger Proxy).
SECTION 16-1-61(A)(5) COPIES OF INSTRUMENTS DEFINING THE TERMS OF ANY
PROPOSED SECURITY, ANY PLANS OR OFFERS OF
REORGANIZATION OR READJUSTMENT OF INDEBTEDNESS OR
CAPITALIZATION, AND ANY PLAN FOR THE RETIREMENT OR
EXCHANGE OF SECURITIES.
N/A
36
<PAGE>
SECTION 16-1-61(A)(6) STATEMENT OF THE PURPOSE FOR WHICH THE SECURITIES ARE
TO BE ISSUED (INCLUDING SOME DISCUSSION OF THE
CONSIDERATION FOR THE MERGER AND THE METHOD OF
ARRIVING AT THAT AMOUNT).
N/A
SECTION 16-1-61(A)(7) COMPLETE DESCRIPTION OF OBLIGATIONS/LIABILITIES
ASSUMED BY APPLICANT.
N/A
SECTION 16-1-61(A)(8) COPY OF THE LATEST PROXY STATEMENT AND ANNUAL REPORT
OF APPLICANT OR PARENT COMPANY.
See Exhibit 2 (Preliminary Merger Proxy);
Exhibit 27 (CTG Resources 1998 Annual Report and 1998 Proxy
Statement).
SECTION 16-1-61(A)(9) COPIES OF ALL SEC FILINGS OF APPLICANT OR PARENT
COMPANY IN CONNECTION WITH THE MERGER.
See Exhibit 2 (Preliminary Merger Proxy);
Exhibit 18 (CTG Resources SEC Form 8-K dated 6/29/99).
SECTION 16-1-61(A)(10) DESCRIPTION OF THE PROPERTY INVOLVED IN THE
TRANSACTION.
See Exhibit 26 (CNG Fixed Asset Report);
Exhibit 2 (Preliminary Merger Proxy).
SECTION 16-1-61(A)(11) CERTIFIED COPY OF THE BOARD OF DIRECTORS RESOLUTIONS
APPROVING THE INITIATION OF THE ACQUISITION.
See Exhibit 8 (CTG Resources Board of Directors Resolutions).
37
<PAGE>
APPENDIX II
Docket No. 99-08
August 11, 1999
Consisting of 1 page
<TABLE>
<CAPTION>
Exhibit Title
- ------- ---------------------------------------------------------------------------------
<C> <S>
1 Merger Agreement
2 CTG Resources Preliminary Proxy Statement/Prospectus dated 7/ 30/99
3 Energy East and CTG Resources Unaudited Pro Forma Combined Financial
Statements
4 CTG Resources SEC Form 10-K for the fiscal year ending 9/30/98
5 CTG Resources SEC Form 10-Q for the period ending 12/31/98
6 CTG Resources SEC Form 10-Q for the period ending 3/31/99
7 CTG Resources SEC Form 10Q for the period ending 6/30/99
8 CTG Resources Board of Directors Resolutions
9 Energy East and CTG Resources Proposed Organization Chart and Officers - Post
Merger
10 Energy East and CTG Resources Proposed Boards of Directors - Post Merger
11 Energy East SEC Form 10-K for year ended 12/31/98
12 Energy East 1998 Annual Report
13 Energy East SEC Form 10-Q for the period ending 3/31/99
14 Energy East SEC Form 10-Q for the period ending 6/30/99
15 Energy East SEC Form 8-K dated 4/23/99
16 Energy East Notice of 1999 Annual Meeting and Proxy Statement
17 Energy East SEC Form S-8/Registration Statement filed 12/17/98
18 CTG Resources SEC Form 8-K dated 6/29/99
19 Energy East Capital Structure and Ratios, Including Pro Forma
20 Energy East Interest and Fixed Charge Coverages, Including Pro Forma
21 CNG Audited 1998 Financial Statement
22 CNG June 30, 1999 unaudited Financial Statement
23 CNG Annual Report to DPUC on FERC Form No. 2 for the period ending
9/30/98
24 Existing CTG Resources Corporate Structure
25 CTG Resources Capital Structure and Ratios
26 CNG Fixed Asset Report
27 CTG Resources 1998 Annual Report and 1998 Proxy
28 Sworn Written Testimony of Arthur Marquardt
29 Sworn Written Testimony of Robert E. Rude
30 Sworn Written Testimony of George E. Bonner
</TABLE>
38
<PAGE>
TROUTMAN SANDERS LLP
ATTORNEYS AT LAW
A LIMITED LIABILITY PARTNERSHIP
NATIONSBANK PLAZA
600 PEACHTREE STREET, N.E. - SUITE 5200
ATLANTA, GEORGIA 30308-2216
www.troutmansanders.com
TELEPHONE: 404-885-3000
FACSIMILE: 404-885-3900
ARTHUR H. DOMBY Direct Dial: 404-885-3130
[email protected] Direct Fax: 404-962-6546
October 6, 1999
Request for Threshold Determination
or Consent under 10 C.F.R. S 50.80
U.S. Nuclear Regulatory Commission
Attention: Docket Control Desk
One White Flint North
11555 Rockville Pike
Rockville, Maryland 20852
Re: NRC Docket No. 50-423 (Millstone Unit 3);
Central Maine Power Company - Merger of Parent Holding Company
Dear Sir or Madam:
Central Maine Power Company (Central Maine) currently holds an undivided
2.5 percent ownership interest in Millstone Unit 3 and is a Nuclear Regulatory
Commission licensee with respect to this interest(1). The purposes of this
letter are: 1) to inform the Nuclear Regulatory Commission (NRC) of the proposed
acquisition of the parent holding company of Central Maine and 2) to request the
NRC's concurrence, based on a threshold review, that the proposed acquisition
does not, in fact, constitute a transfer subject to Section 50.80 of Title 10 of
the Code of Federal Regulations. To the extent that the NRC finds that the
------------------------------
acquisition of the parent holding company constitutes an indirect transfer of
Central Maine's license, Central Maine requests the NRC's consent to the
indirect transfer of control of NRC Operating License NPF-49 issued for
Millstone Unit 3. Attachment A to this letter provides the NRC with information
pertinent to this request for consent.
- -------------------------------
1. Central Maine also owns equity interests in four corporations that are NRC
licensees for the Maine Yankee, Yankee Rowe, Haddam Neck and Vermont Yankee
nuclear power plants, but Central Maine is not an NRC licensee with respect to
any of these plants.
<PAGE>
TROUTMAN SANDERS LLP
ATTORNEYS AT LAW
PAGE 2
Background
- ----------
Central Maine is a subsidiary of CMP Group, Inc. which holds all of the
common stock of Central Maine; both are corporations incorporated under the laws
of the State of Maine. The NRC previously reviewed and approved this structure.
Specifically, by letter dated March 4, 1998, Central Maine submitted an
application for consent under 10 C.F.R. S 50.80 for the restructuring of Central
Maine, which resulted in CMP Group, Inc. (referred to as "HoldCo" in that
correspondence) becoming the parent holding company of Central Maine. At that
time, Central Maine requested the NRC's consent to any "indirect" transfer of
control of the Millstone Unit 3 license, to the extent that the NRC determined
that such consent was required under Section 184 of the Atomic Energy Act of
1954, as amended, and 10 C.F.R. S 50.80. By Order issued June 2, 1998,
supported by the Staff's Safety Evaluation, the Commission approved the
application regarding the restructuring, subject to Central Maine providing the
Director of the NRC's Office of Nuclear Reactor Regulation a copy of any
application of Central Maine to transfer to its parent or any affiliates any of
its facilities having a depreciated book value in excess of ten percent (10%) of
Central Maine's consolidated net utility plant investment. A copy of the Order
and the Staff's Safety Evaluation are attached for ease of reference as
Attachment B.
On June 14, 1999, CMP Group, Inc. and Energy East Corporation (Energy East)
signed a definitive merger agreement for the acquisition of CMP Group by Energy
East, subject to regulatory approvals. Energy East is an investor-owned holding
company with offices in New York and Connecticut. Through its subsidiaries, it
is an energy delivery, products and services company with operations in New
York, Massachusetts, New Hampshire, Maine, Vermont and New Jersey. In the
merger, Energy East will acquire all of the common stock of CMP Group. CMP
Group, upon completion of the transaction, will become a wholly-owned subsidiary
of Energy East and will continue its corporate existence under the laws of the
State of Maine. After the completion of the acquisition, all of Central Maine's
common stock will continue to be owned by the surviving CMP Group, and Central
Maine will retain its headquarters at its present offices in Augusta, Maine.
All of the members of the board of directors of Central Maine and Central
Maine's President after the transaction will be citizens of the United States.
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Request for Threshold Determination
- --------------------------------------
NRC regulations in 10 C.F.R. S 50.80 require NRC review of, and written
consent to, indirect as well as direct transfers of operating licenses. In the
case of Central Maine, no direct transfer of the license or interest in
Millstone 3 will result from the proposed acquisition of CMP Group by Energy
East. Northeast Nuclear Energy Corporation (NNECo), a co-owner of Millstone
Unit 3, has exclusive authority under the license to operate the facility.
NNECo is not involved in the proposed acquisition by Energy East; NNECo would
continue to have exclusive responsibility for the management, operation and
maintenance of Millstone Unit 3. No physical or operational changes to
Millstone Unit 3 will result from the proposed merger. No transfer of assets
from Central Maine will result from the merger of CMP Group and Energy East. No
change in the Millstone Unit 3 license is required because Central Maine will
remain the owner of its present 2.5 percent ownership interest in the facility.
After the merger is completed, Central Maine will continue to be a public
utility subject to regulation by the Maine Public Utilities Commission (Maine
PUC) under the laws of the State of Maine, providing the same utility services
as it did prior to the acquisition(2). The Federal Energy Regulatory Commission
(FERC) will still regulate Central Maine's wholesale electric rates and
transmission service. As a consequence, Central Maine will remain an "electric
utility" within the meaning of 10 C.F.R. S 50.2, since it will continue to be"
an entity that generates or distributes electricity and which recovers the cost
of this electricity, either directly or indirectly, through rates established by
the entity itself or by a separate regulatory authority." The proposed
acquisition of Central Maine's parent will have no impact on the revenues and
expenses of Central Maine relative to the operation of Millstone Unit 3, or on
the ability of Central Maine to fund its pro-rata share of decontamination and
decommissioning costs for the facility. Central Maine's responsibility for such
costs and its obligations under 10 C.F.R. Part 140 and 10 C.F.R. S 50.54(w) will
not be affected. As a result of the acquisition, Central Maine believes that it
and the non-utility subsidiaries of CMP Group will be able to compete more
effectively in the changing commercial and regulatory environment, including
decisions of the FERC that promote additional competition at the wholesale
level.
- -------------------------------
2. The Maine Electric Utility Restructuring Act of 1997 (35-A MRSA S 3201 et
--
seq.) requires all investor-owned utilities in the State of Maine, including
- ----
Central Maine, to 1) divest their non-nuclear generating assets and generation-
related activities by March 1, 2000, at which time all retail customers in Maine
will have the right to purchase electric generating services directly from
competitive providers licensed by the Maine PUC, 2) limit their electric utility
operations to transmission and distribution services after that date, and 3)
create separate corporate entities for any marketing and sale of electricity to
retail customers.
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PAGE 4
Central Maine requests an NRC threshold determination, pursuant to NUREG
SR1577, rev. 1, Section III.1.e, that the acquisition of CMP Group by Energy
East does not require the NRC's consent under 10 C.F.R. S 50.80. The
acquisition does not entail a merger of Central Maine, a formation of a holding
company of Central Maine or an acquisition of or divestiture by Central Maine
and, therefore, consent may not be required under Section 50.80. The
transaction does not affect Central Maine's status as an "electric utility" or
affect the corporate ownership or identity of the licensee (i.e., it will remain
a subsidiary of a holding company, CMP Group, Inc., which will continue to own
Central Maine to the same extent it does now). Therefore, not only will the
licensee's financial qualifications not be adversely affected as a consequence
of the acquisition, but also Central Maine is exempt from a financial
qualifications review in accordance with NRC regulation.
The consummation of Energy East's acquisition of CMP Group, Inc. is
dependent upon the receipt of various regulatory and shareholder approvals and
is currently expected to occur in the middle of the year 2000, or earlier if all
approvals have been obtained. Any requisite NRC approval is a precondition to
Securities and Exchange Commission and, possibly, Connecticut Department of
Public Utility Control approvals. Accordingly, Central Maine respectfully
requests that the NRC complete its threshold determination of the proposed
acquisition by November 15, 1999 and, if required, provide its consent pursuant
to 10 C.F.R. S 50.80 by December 31, 1999.
If the NRC has any questions with regard to the proposed transaction,
please contact me directly at 404-885-3130.
Sincerely yours,
Arthur H. Domby
AHD/lrb
Enclosures: Attachment A - "Information related to the Proposed Acquisition
of CMP Group, Inc. (Parent of Central Maine Power Company) by
Energy East Corporation"
Attachment B - "Order Approving the Application Regarding the
Proposed Restructuring of Central Maine Power Company By
Establishment of a Holding Company" with Staff Safety
Evaluation.
xc: Attached List
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ATTACHMENT B
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
ENERGY EAST CORPORATION )
)
AND ) DOCKET NO. EC99- -000
)
CMP GROUP, INC. )
JOINT AFFIDAVIT OF STEVEN S. GARWOOD AND JEFFREY L. MCKINNEY
INTRODUCTION
1. My name is Steven S. Garwood. I am the Managing Director of
Transmission Operations for Central Maine Power Company ("Central Maine" or
"CMP"). My primary responsibility is to provide management oversight and
direction to the areas of Transmission Planning, Transmission Services,
Interconnection Agreement Administration, and CMP's Control/Dispatch Center.
During my career at CMP, which began in June 1985, I have worked in various
capacities in the areas of Engineering, Licensing, Cost of Service, and Rate
Design. I participated extensively in the restructuring of the New England
Power Pool ("NEPOOL") as part of the NEPOOL Regional Transmission Group
negotiating team and in my current capacity as Chair of the Regional
Transmission Operations Committee. I serve as CMP's primary representative on
the NEPOOL Participant's Committee (formerly the NEPOOL Executive Committee).
2. My name is Jeffrey L. McKinney. I am Manager of Transmission Services &
Policies in the Energy Operating Services Department of New York State Electric
& Gas Corporation ("NYSEG"). I am responsible for directing and aiding the work
of the Transmission Services & Policies Section with the primary goals of
providing transmission contractual services and formulating strategies and
policies related to transmission issues. I coordinate and have ultimate
responsibility for filings before the Federal Energy Regulatory Commission
("FERC") related to transmission services and contracts and manage the
day-to-day administrative matters of the Section. I have been a member of
several New York Power Pool ("NYPP") and Northeast Power Coordinating Council
("NPCC") system study working groups and am familiar with transmission pricing
under the New York Independent System Operator tariff described below.
3. The purpose of this joint affidavit is to support the merger of Energy
East Corp. and CMP Group, Inc. In particular, we explain how Central Maine and
NYSEG intend to integrate their Open-Access Transmission Tariffs ("OATTs") so
that, with respect to transmission facilities over which CMP or NYSEG have
retained some operational or administrative control, customers who use both
transmission systems are not required to pay both companies' embedded cost
transmission charges.
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PAGE 5
4. I, Mr. Garwood, will describe CMP's transmission system, as well as
transmission services within NEPOOL and CMP.
5. I, Mr. McKinney, will describe NYSEG's transmission services, as well as
transmission services within NYPP and NYSEG.
DESCRIPTION OF CENTRAL MAINE'S TRANSMISSION SYSTEM
6. Central Maine's transmission system serves approximately 533,000
native load retail customers within an 11,000 square mile territory in southern,
central, and western Maine. CMP's transmission system consists of 208 miles of
345 kV lines, 1065 miles of 115 kV lines and 1021 miles of 34.5 kV lines. CMP
is a member of NEPOOL. As such, all of its qualifying 345 kV and 115 kV
transmission facilities are classified as Pool Transmission Facilities ("PTF")
and are under the operational control of the independent system operator for New
England ("ISO-NE"). The remainder of CMP's transmission system, consisting of
its 34.5 kV transmission lines, and certain 345 and 115 kV facilities, are
classified as non-PTF. Central Maine has retained operational control only over
its non-PTF facilities. CMP does not own or control any of the tie lines that
comprise the New England to New York interface. These lines on the New England
side of the interface are owned by other New England utilities, are within
NEPOOL and are under the operational control of the ISO-NE.
DESCRIPTION OF NYSEG'S TRANSMISSION SYSTEM
7. NYSEG is a combination electric and gas utility serving
approximately 826,000 retail electric customers and 244,000 gas customers in
upstate New York. NYSEG's electric transmission system consists of
approximately 4,482 circuit miles of line. NYSEG's electric distribution system
consists of 35,967 miles of line. NYSEG, which is a member of the New York
Power Pool ("NYPP"), has committed to transfer control of its transmission
system to the independent system operator for New York ("NYISO").(3), 79 FERC
61,374 (1997). As is the case with CMP, NYSEG does not own or control any of
the transmission lines that comprise the New York to New England interface. All
these lines are owned by others and will be under the operational control of the
NYISO. The NYISO expects to commence operations in October 1999.
TRANSMISSION SERVICES WITHIN NEPOOL AND CMP
8. Within NEPOOL, transmission service over PTF is governed by the
NEPOOL OATT, which is administered by ISO-NE.(4) ISO-NE has operational control
of all New England utilities' PTF, including CMP's PTF. The provision of open
access transmission service over these facilities is provided under the terms of
the Restated NEPOOL Agreement and the NEPOOL Open Access Transmission Tariff
("OATT"). The NEPOOL OATT provides for Regional Network Service, Internal
Point to Point Service, and service through and exports from NEPOOL ("Through
and Out Service") at non-pancaked rates.
- -------------------------------
3. New England Power Pool, 79 FERC 61,374 (1997).
4. The Restated NEPOOL Agreement and NEPOOL OATT became effective on March 1,
1997. ISO-NE took over management and administration of the NEPOOL PTF on July
1, 1998.
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PAGE 6
9. Under the NEPOOL OATT, New England load pays for Regional Network Service
over PTF. As a result, generators, power marketers, and other power suppliers
do not pay for transmission service to serve load in New England, unless they
purchase Internal Point to Point Service. The NEPOOL OATT provides for zonal
rates for Regional Network Service and Internal Point to Point Service, which
will ultimately be replaced with a system-wide, postage-stamp rate equal to the
NEPOOL PTF Rate. Transmission service over the PTF of all NEPOOL
member-utilities is subject to NEPOOL OATT charges only and not company specific
charges. Through and Out Service (transmission service to wheel power through
or export power out of NEPOOL to another control area, such as NYPP), is
provided at the NEPOOL PTF Rate. The NEPOOL PTF Rate is a postage stamp rate;
thus, a wheel from a generator anywhere on PTF to another control area, such as
NYPP, is subject only to a single NEPOOL transmission charge under the NEPOOL
OATT, irrespective of how many individual transmission systems are used. A New
England power marketer or generator that desires to wheel power through or out
of NEPOOL must arrange and pay for NEPOOL Through and Out Service.
10. Central Maine administers transmission service over its non-PTF system
under the terms of its Local OATT. This tariff provides for Local Network
Service to network transmission customers connected to CMP's, non-PTF
transmission system. The CMP Local OATT also provides for Local Point to Point
Service to customers, such as generators, connected to CMP's non-PTF system. A
generator, for example, could use Local Point to Point Service to transmit power
from CMP's local network to the NEPOOL PTF. Thus, a generator located on CMP's
local network that wishes to serve load in New England under NEPOOL Regional
Network Service would pay only a CMP Local Point to Point Service rate, and New
England load would pay for the Regional Network Service. If such a generator
wishes to serve load in New York, it must pay for NEPOOL Through and Out
Service, in addition to CMP Local Point to Point Service.
TRANSMISSION SERVICES WITHIN NYPP AND NYSEG
11. The NYISO is scheduled to become operational in October 1999.(5)
UNDER THE NYISO TARIFF, ALL TRANSMISSION SERVICES, WITH THE EXCEPTION OF CERTAIN
GRANDFATHERED CONTRACTS, WILL BE ADMINISTERED BY THE NYISO AND OFFERED UNDER THE
TERMS OF THE NYISO OATT. TRANSMISSION SERVICE WITHIN THE NYISO CONTROL AREA
WILL BE SUBJECT TO A SINGLE ZONAL RATE EQUAL TO THE TRANSMISSION SERVICE CHARGE
("TSC") OF THE TRANSMISSION OWNER ON WHOSE SYSTEM THE LOAD WITHDRAWS THE ENERGY
OR ON WHOSE SYSTEM THE ENERGY IS WHEELED OUT OF OR EXPORTED FROM THE NYISO
CONTROL AREA (THE NYISO OATT EQUIVALENT OF ISO-NE'S THROUGH AND OUT SERVICE).
ACCORDINGLY, WHEELS TO LOADS WITHIN NYSEG'S SERVICE TERRITORY WILL BE SUBJECT TO
NYSEG'S TSC. AFTER THE NYISO GOES INTO OPERATION, NEW YORK UTILITIES WILL NOT
OFFER ANY NEW TRANSMISSION SERVICE UNDER THEIR INDIVIDUAL OATTS. THE NYISO WILL
ADMINISTER ALL TRANSMISSION SERVICES ACROSS ALL EIGHT TRANSMISSION SYSTEMS.
12. TRANSMISSION SERVICE ASSOCIATED WITH EXPORTS OF POWER FROM A GENERATOR
IN THE NYISO CONTROL AREA OUT OF THE NYISO CONTROL AREA (EXPORTS) OR WHEELS
THROUGH (TRANSMISSION OF ENERGY FROM ANOTHER CONTROL AREA, SUCH AS NEPOOL,
THROUGH THE NYISO CONTROL AREA TO ANOTHER CONTROL AREA, SUCH AS PJM(6)) will be
subject to the non-pancaked TSC of each system at which the energy exits the
NYISO control area. The NYISO will calculate "generator shift factors" to
determine the megawatt flow that is transmitted on each of the transmission
owners' facilities that comprise the interface with the control area to which
the energy is exported. These distribution factors will be used in determining
each utility's billing units for application of its TSC, but only one TSC shall
apply to each MWH of Export or Wheel Through.
13. While NYSEG owns some of the tie lines that comprise the NYISO-to-PJM
interface, it does not own any of the tie lines that comprise the
NYISO-to-NEPOOL interface. NYSEG will apply its TSC to Wheels Through and
Exports to PJM in accordance with the shift factors. NYSEG will not apply its
TSC to Wheels Through and Exports to NEPOOL because it does not own the lines
comprising the interface between the NYISO control area and NEPOOL, and thus is
not allocated a shift factor for use of these facilities. NYSEG will receive
revenues for wheeling to loads located on or within its service territory.
- -------------------------------
5. Currently, transmission service within NYPP is offered under the
individual OATTs of the eight New York utilities. Thus, transmission service
within or through NYSEG's service territory is governed by the NYSEG OATT and
multiple transmission service charges apply for wheeling through multiple
utility systems within NYPP.
6.The Pennsylvania-New Jersey-Maryland Interconnection.
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ATTORNEYS AT LAW
PAGE 7
NYSEG AND CMP TRANSMISSION CHARGES POST-MERGER
14. Following the merger, there will be only three types of
transactions that, absent a tariff modification or change in billing procedures,
could result in a charge under both CMP's Local OATT and the NYSEG TSC under the
NYISO OATT: wheels from a generator on CMP's non-PTF System (a) to wholesale
load on NYSEG's system, such as a municipal utility; (b) to a retail load within
NYSEG's service territory; or (c) through NYSEG's system to a buyer or
transmitter in PJM. In order to avoid that result, NYSEG and CMP commit that,
upon approval of the merger, they will waive or reduce the otherwise applicable
charges such that transmission customers in these three types of transactions
will not have to pay more than the equivalent of one transmission service charge
to NYSEG and CMP for transmission.
15. Without the CMP OATT protocol (described in Paragraph 17 below), a
generator located on CMP's non-PTF system wheeling power to a load located on
NYSEG's system or in NYSEG's service territory would have to pay both a CMP
Local Point to Point Service charge(7) and a NYSEG TSC pursuant to NYSEG's
retail access tariff or the NYISO Tariff.
16. Without a posted NYSEG TSC billing credit (described in Paragraph 18
below), a generator located on CMP's non-PTF system wheeling power through NYSEG
to a buyer or transmitter in PJM may have to pay both CMP's Local Point to Point
Service charge(8) under the CMP OATT and the full NYSEG TSC under the NYISO OATT
to the extent the NYISO determines that the transaction uses NYSEG's tie lines
interconnecting the NYISO control area with PJM. The NYISO OATT permits such
adjustments for Export and Wheel Through transactions. See Attachment H,
---
Section 8.0 of the NYISO OATT on file with the Commission.
17. CMP commits to adopt a protocol under CMP's Local OATT, to be effective
upon consummation of the merger, to waive CMP's otherwise applicable Local Point
to Point Service transmission service charge in the first two types of
transactions described in Paragraph 14, above [(a) and (b)].
18. For the third type of transaction described in Paragraph 14, above
[(c)], NYSEG similarly commits to implement a TSC billing credit such that NYSEG
will charge no more than its FERC-accepted or approved TSC less an amount
equivalent to the applicable Local Point to Point Transmission Service charge
under the CMP OATT.(9) If NYSEG does not bill TSC charges in excess of this
amount as described, the customers will pay in the aggregate no more than the
NYSEG TSC or the equivalent of only a single system rate for use of both Central
Maine's non-PTF system and NYSEG's system. The effect of this posted TSC billing
credit is that transmission customers in such transactions will not be charged
the equivalent of both CMP's Local OATT rate for Local Point to Point Service
and the full NYSEG TSC.
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7. As discussed in this affidavit, the "transmission service charge" under
either the CMP OATT or the NYISO OATT does not include ancillary service
charges, congestion charges or losses, the application of which will remain
unchanged by the rate treatment discussed in this affidavit.
8. CMP's Local Point to Point Service rate is currently $2.87 per MWH.
9. NYSEG's TSC as filed in the NYISO Docket is $7.99 per MWH, subject to the
outcome of the NYISO proceeding. The equivalent amount of the billing credit
associated with the CMP OATT rate is currently $2.87 per MWH. NYSEG would issue
a TSC credit on its TSC bills to be consistent with the hourly TSC ceiling
described above.
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TROUTMAN SANDERS LLP
ATTORNEYS AT LAW
PAGE 8
19. While the NYISO OATT contemplates a discount applicable to all customers
delivering across a particular interconnection, the more specific application of
a billing credit to only those customers that pay CMP Local Point to Point
Transmission Service charges satisfies the Commission's policy in mergers. The
billing credit places customers using both CMP's and NYSEG's systems, and
subject to both companies' charges in the same position they would have realized
had CMP waived its Local Point to Point Transmission Service charge and NYSEG
charged its full TSC. This stated billing credit practice, which the Commission
can approve as a condition of the merger authorization sought in this
application, is not discretionary, thereby avoiding completely concerns that
might otherwise arise in a discounting context. By proposing the equivalent of
only one rate for use of both CMP's non-PTF system and NYSEG's system, through a
combination of waiving the CMP Local OATT TSC in some transactions and a NYSEG
TSC billing credit in others, the applicants will spread any revenue impacts and
benefits associated with the rate treatment across both systems.
20. In transactions from a generator on the NYSEG system or another control
area, such as PJM, through NYSEG to a load on the CMP non-PTF system, there
would be no duplicate NYSEG/CMP transmission charges. Under the NYISO OATT, the
transmission owners at the point of withdrawal of the energy apply their TSCs.
Accordingly, NYSEG would not collect a TSC for transactions out of NYISO control
area to NEPOOL because NYSEG does not own any of the tie lines comprising the
NYISO control area to NEPOOL interface. Similarly, NYSEG would not collect a
TSC for transactions into NYISO control area from PJM. In these transactions,
the only CMP/NYSEG transmission charge imposed would be CMP's charge under its
Local OATT. Therefore, no tariff amendments or changes in billing practice are
required.(10)
21. The companies can achieve the proposed mechanisms for eliminating
application of both a CMP OATT embedded cost transmission charge and a NYSEG TSC
under the NYISO OATT through the CMP protocol under its Local OATT and NYSEG's
billing credit protocol described above. Neither the NYISO OATT nor the NEPOOL
OATT requires amendment to achieve this result. In this way, implementation of
the rate treatment specified in this application is simplified.
- -------------------------------
10. While there are other transactions between or through the CMP and NYSEG
transmission systems, no other transactions would be assessed both a NYSEG TSC
and a transmission charge under the CMP Local OATT. For instance, a generator
located on CMP's PTF system serving load in either NYSEG's service territory or
in PJM would not pay a CMP Local OATT charge.
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ATTORNEYS AT LAW
PAGE 9
SUMMARY AND CONCLUSIONS
22. By the time the merger of Energy East and CMP Group is completed,
NYSEG and CMP will have relinquished operational control of their transmission
systems to their respective ISOs consistent with FERC-approved tariffs and
agreements. Services over the intervening NEPOOL and NYISO transmission systems
will be offered under the non-discriminatory terms of the NEPOOL OATT and the
NYISO OATT. CMP and NYSEG commit to eliminate the potential effects of
multiple transmission charges that would otherwise result from application of
CMP's Local OATT and the NYSEG TSC under the NYISO OATT. By lowering the
otherwise applicable transaction costs, these proposed measures will encourage
additional competitive economic transactions between the two companies' systems.
<PAGE>
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PAGE 10
EXHIBIT LIST
------------
Exhibit 1: Joint 1998 Annual Report on Form 10-K of CMP Group and Central
- ----------
Maine filed with the Securities and Exchange Commission (SEC) in
March, 1999. Joint Quarterly Report on Form 10-Q of CMP Group
and Central Maine filed with the SEC on August 10, 1999.
Exhibit 2: Agreement and Plan of Merger By and Among CMP Group, Inc., Energy
- ---------
East and EE Merger Corp. dated June 14, 1999 (without Schedules).
Exhibit 3: Energy East's Quarterly Report on Form 10-Q filed with the SEC on
- ---------
August 10, 1999.
Exhibit 4: Petition for Approval of Reorganizations and Affiliate Interest
- ----------
Transactions filed with the Maine PUC on July 1, 1999 (Docket No.
99-411) (without Appendix 1).
Supplemental Prefiled Testimony of Arthur W. Adelberg, July 22,
1999.
<PAGE>
Exhibit I-1
UNITED STATES OF AMERICA
before the
SECURITIES AND EXCHANGE COMMISSION
under the
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
(Release No. 35-______; 70-________) ___________, 1999
___________________________________
In the Matter of )
)
Energy East Corporation, et al. )
P.O. Box 1196 )
Stamford, Connecticut 060904-1196 )
___________________________________)
NOTICE IS HEREBY GIVEN that Energy East Corporation ("Energy East"), P.O.
Box 1196, Stamford, Connecticut 06904-1196, a New York corporation and an exempt
public utility holding company, CMP Group, Inc. ("CMP Group"), 83 Edison Dr.,
Augusta, Maine, 04336, a Maine corporation and an exempt public utility holding
company, and CTG Resources, Inc. ("CTG Resources"), 100 Columbus Boulevard,
Hartford, Connecticut 06103, a Connecticut corporation and an exempt public
utility holding company ("collectively, "the Applicants") have filed with this
Commission an application pursuant to the Public Utility Holding Company Act of
1935 ("the Act"), designating Section 9(a)(2), Section 10(b) and Section 10(c)
of the Act as applicable to the proposed transactions. The Applicants request
an order of the Commission authorizing Energy East to acquire all of the issued
and outstanding common stock of CMP Group and CTG Resources. Pursuant to the
proposed transactions, CMP Group and CTG Resources would become direct
subsidiaries of Energy East and Energy East would become a registered public
utility holding company under the Act. The Applicants also seek approvals in
connection with (i) the operation of Energy East as a combination electric, gas
and utility holding company and (ii) the retention by Energy East of its
non-utility activities, businesses and investments and the acquisition by Energy
East of the non-utility activities, businesses and investments of CMP Group and
CTG Resources.
Energy East currently holds, directly or indirectly, in excess of 5% of the
voting securities of two public utility companies as defined under the Act: New
York State Electric & Gas Corporation ("NYSEG") and CMP Natural Gas, L.L.C.
("Maine Gas Co."). NYSEG is engaged in the business of purchasing, transmitting
and distributing electricity and purchasing, transporting and distributing
natural gas. NYSEG also generates electricity from its 18 percent share of the
Nine Mile Point Unit 2 Nuclear Plant ("NM2") and from its hydroelectric
stations, however, NYSEG has agreed to sell its share of NM2 and anticipates
that the sale will be completed by early 2000. NYSEG serves 826,000 electric
customers and 244,000 natural gas customers in upstate New York. Maine Gas Co.,
a gas utility company, is in the process of constructing a local natural gas
distribution system in certain areas of the State of Maine, and began to provide
<PAGE>
service to retail customers in May 1999. Maine Gas Co is a joint venture
between New England Gas Development Corp., a wholly-owned subsidiary of CMP
Group, and Energy East Enterprises, Inc. ("EE Enterprises") a wholly-owned
subsidiary of Energy East.
Energy East also has a number of direct and indirect subsidiaries that are
not "public utility companies" under the Act, including EE Enterprises and
XENERGY Enterprises, Inc. ("XENERGY"). EE Enterprises is an exempt public
utility holding company that indirectly holds public utility assets through its
ownership of an 77 percent interest in Maine Gas Co. EE Enterprises'
non-utility subsidiaries are New Hampshire Gas Corporation, an energy services
company in New Hampshire specializing in propane air distribution systems;
Southern Vermont Natural Gas Corporation, which is developing a combined natural
gas supply and distribution project that includes an extension of a pipeline
from New York to Vermont by Iroquois Gas Transmission System, and the
development of natural gas distribution systems in Vermont; and Seneca Lake
Storage, Inc., which proposes to own and operate a gas storage facility in New
York
XENERGY invests in providers of energy and telecommunication services.
XENERGY Enterprises currently holds no public utility assets and is neither a
public utility company nor a holding company under the Act. XENERGY's principal
subsidiaries are XENERGY Inc., an energy services, information systems and
consulting company that specializes in energy management, conservation
engineering and demand-side management; Energy East Solutions, Inc., which
markets electricity and natural gas to end users and provides wholesale
commodities to retail electric suppliers in the northeastern United States;
NYSEG Solutions, Inc., which markets electricity and natural gas to end users
and provides wholesale commodities to retail electric suppliers in the State of
New York; Energy East Telecommunications, Inc. which provides telecommunication
services, including the construction and operation of fiber optic networks; and
Cayuga Energy, Inc., which holds investments in cogeneration facilities.
Other current direct non-utility subsidiaries of Energy East are: Energy
East Management Corporation, a Delaware corporation, that invests the proceeds
of the sale of an affiliate's generation assets; Oak Merger Co., a Connecticut
corporation, formed solely for the purpose of consummating the proposed merger
with CTG Resources and which upon consummation of such merger, will change its
name to, and operate under, the name of "CTG Resources, Inc."; EE Merger Corp.,
a Maine corporation, formed solely for the purpose of consummating the proposed
merger with CMP Group.
On April 23, 1999, Connecticut Energy Corporation ("Connecticut Energy")
and Energy East entered into an agreement and plan of merger. By separate
application dated August 30, 1999, Energy East has requested authorization from
the Commission for Connecticut Energy to merge with and into a wholly-owned
subsidiary of Energy East. Connecticut Energy, an exempt holding company that
neither owns nor operates any physical property, is primarily engaged in the
retail distribution of natural gas through its principal wholly-owned
subsidiary, The Southern Connecticut Gas Company ("Southern Connecticut Gas").
Connecticut Energy, through its subsidiaries, is an energy delivery, products
and services company that provides an array of energy commodities and services
to commercial and industrial customers throughout New England. Southern
Connecticut Gas serves approximately 158,000 customers in the State of
Connecticut, primarily in 22 towns along the southern Connecticut coast from
Westport to Old Saybrook, which include the urban communities of Bridgeport and
New Haven.
<PAGE>
Connecticut Energy also has a number of direct and indirect subsidiaries
that are not "public -utility companies" under the Act., including CNE Energy
Services Group, Inc. ("CNE Energy"), CNE Development Corporation ("CNE
Development") and CNE Venture-Tech, Inc. ("CNE Venture-Tech"). All three of
these non-utility subsidiaries are Connecticut corporations.
CMP Group is a holding company by virtue of owning, directly or indirectly,
more than five percent of the voting securities of Central Maine Power, Maine
Electric Power Company, Inc. ("MEPCO", NORVARCO and Maine Gas Co, all public
utility companies as defined in the Act. Central Maine Power is the largest
electric utility in Maine and serves approximately 533,000 customers in its
11,000 square-mile service area in southern and central Maine. Central Maine
Power has divested and/or relinquished control over substantially all of its
generating assets and purchase power contracts and now functions as an electric
transmission and distribution utility. Pursuant to Maine electric utility
restructuring legislation, as of March 1, 2000, Central Maine Power will not
control any generation resources and all retail electric consumers in Maine will
be able to choose their electric supplier. Since under Maine law, Central Maine
Power would be able to serve only a limited number of retail customers and would
not be the supplier of last resort, Central Maine Power has elected not to
continue as a retail electric supplier. In the future, Central Maine Power will
be a "wires" only transmission and distribution utility.
Central Maine Power currently has two utility subsidiaries, each of which
is organized and operates almost exclusively in Maine: MEPCo and NORVARCO.
MEPCo owns and operates a 345-kV transmission interconnection between the
Maine-New Brunswick, Canada international border at Orient, Maine. Central
Maine Power owns a 78.3% voting interest in MEPCo, with the remaining interests
owned by two other Maine utilities. NORVARCO holds a 50% general partnership
interest in Chester SVC Partnership, a general partnership which owns a static
var compensator in Chester, Maine, adjacent to MEPCo's transmission
interconnection.
CMP Group holds an approximately 23% interest in Maine Gas Co., the joint
venture with New England Gas Development Corporation and EE Enterprises.
CMP Group's non-utility subsidiaries include: CNEX (formerly called CMP
International Consultants) which provides consulting, planning, training,
project management, and information and research services to foreign and
domestic utilities and government agencies in various aspects of utility
operations and utility support services; MaineCom Services ("MaineCom") which
develops fiber-optic data service for bulk carriers, provides other
telecommunications services, and holds direct or indirect voting interests in
various entities that are in the business of developing a fiber-optics network
in the Northeast; Northeast Optic Network which develops, constructs, owns and
operates a fiber optic telecommunications system in New York and New England
(Maine-Com. owns 38.5% of its common stock); TelSmart which provides collections
and related accounts receivable management services and has a division which
collects charged-off accounts; Central Securities Corporation which owns and
leases office and service facilities in Central Maine Power's service territory
for the conduct of Central Maine Power's business (Central Maine Power owns all
<PAGE>
of the outstanding common stock of Central Securities); Cumberland Securities
Corporation which owns and leases office and service facilities in Central Maine
Power's service territory for the conduct of Central Maine Power's business
(Central Maine Power owns all of the outstanding common stock of Cumberland
Securities); and, The Union Water-Power Company ("Union Water") which provides
utility construction and support services (On Target division), energy
efficiency performance contracting and energy use and management services
(Combined Energies division), and commercial and residential real estate
development services (Union-Land Services and MaineHome Crafters division)
(Union Water is a wholly-owned subsidiary of CMP Group).
CTG Resources is an exempt public utility holding company that owns
Connecticut Natural Gas Corporation ("CNGC"), a public utility that operates as
a regulated local natural gas distribution company. CNGC distributes gas to
approximately 143,300 customers in 22 Connecticut communities, principally in
the Hartford-New Britain area and in Greenwich. CNGC's gas distribution
business is subject to regulation by the Connecticut Department of Public
Utility Control as to franchises, rates, standards of service, issuance of
securities, safety practices and certain other matters.
CTG Resources' non-public utility subsidiaries include: CNG Realty Corp.
("CNGR"), a single purpose corporation which owns the Operating and
Administrative Center located on a seven-acre site in downtown Hartford,
Connecticut; The Energy Network, Inc ("TEN"), which, through its
wholly-owned subsidiary, The Hartford Steam Company ("HSC"), provides district
heating and cooling services to a number of large buildings in Hartford,
Connecticut; TEN Transmission, a wholly-owned subsidiary of TEN, which owns a
4.87 percent interest in Iroquois Gas Transmission System; and ENI Gas Services,
Inc. ("ENI Gas"), and TEN Services Inc., both wholly-owned subsidiaries of TEN,
which together own 100% of KBC Energy Services, a partnership. TEN's other
unregulated operating divisions offer energy equipment rentals, property rentals
and financing services and own a 3,000 square foot building in Hartford,
Connecticut.
The acquisition by Energy East of the common stock of CMP Group will be
effected pursuant to the terms of the Agreement and Plan of Merger dated June
14, 1999 ("CMP Group Merger Agreement"). Under the terms of the CMP Group Merger
Agreement, each outstanding share of CMP Group's common stock, $5.00 par value
per share, other than dissenting shares and treasury shares or shares owned by
any subsidiary of the CMP Group, Energy East or any subsidiary of Energy East,
will be converted into the right to receive $29.50 in cash. Approximately $957
million in cash will be paid to holders of shares of CMP Group common stock.
The acquisition of Energy East of the common stock of CTG Resources will be
effected pursuant to the terms of the Agreement and Plan of Merger dated June
29, 1999 ("CTG Merger Agreement"). Under the terms of the CTG Resources Merger
Agreement, each outstanding share of CTG Resources' common stock, other than
dissenting shares, will be converted into the right to receive (i) $41.00 in
cash or (ii) a number of shares of Energy East common stock equal to the
Exchange Ratio, or (iii) the right to receive a combination of cash and shares
of Energy East common stock. The Exchange Ratio shall be equal to the CTG
Resources cash consideration divided by either (i) the Energy East share price
if the Energy East share price is equal to or less than $30.13 and equal to or
more than $23.67, (ii) $30.13 if the Energy East share price is greater than
$30.13, in which case the Exchange Ration will equal 1.3609, or (iii) $23.67 if
the Energy East share prices is less than $23.67, in which case the Exchange
Ratio will equal 1.7320.
<PAGE>
The shareholders of the CMP Group and CTG Resources approved their
respective mergers with Energy East at meetings held on October 7, 1999 and
October 18, 1999, respectively. Each of the companies has submitted
applications requesting approval of the proposed mergers and/or related matters
to the appropriate state and federal regulators. The Applicants believe that
their combination will provide benefits to the public, investors and consumers,
and that the mergers will meet all applicable standards under the Act.
The combination of NYSEG's electric system and CMP Group's electric
operations will result in a single, integrated electric utility system (the "new
Energy East Electric System"). Integration of the new Energy East Electric
System will be facilitated by NYSEG's and Central Maine's membership in
adjacent, highly interconnected and coordinated power pools (NEPOOL and the New
York Power Pool) and their participation in interconnected independent system
operators ("ISOs") (New York ISO and ISO-New England). This integration will be
accomplished by the functioning of the open, competitive markets administered by
the interconnected ISOs. Sellers and purchasers in either ISO's control area
may engage in transactions in the other ISO's control area through
readily-accessible, OASIS-based transmission access. Further, the combination
of Energy East's current gas system (i.e., NYSEG's gas operations, Connecticut
Energy and Maine Gas Co.) with the gas operations of CMP Group and CTG Resources
will result in a single, integrated gas utility system (the "new Energy East Gas
System"). Accordingly, the Applicants request the Commission to find that the
new Energy East Electric System will be the primary integrated public utility
system for purposes of Section 11(b)(1) and the new Energy East Gas System is a
permissible additional system under Section 11(b)(1)A-C.
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 Energy East at the
address specified above. Proof of service (by affidavit or, in case of attorney
at law, by certificate) should be filed with the request. Any request for a
hearing must 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 this matter. After said date,
the application, as filed or as it may be 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 J-1
ANALYSIS OF THE ECONOMIC IMPACT OF
A DIVESTITURE OF THE
GAS OPERATIONS OF ENERGY EAST
This study was undertaken by the management and staff of Energy East with the
assistance of PHB Hagler Bailly. The objective of the study is to quantify the
economic impact on shareholders and customers of divesting Energy East of its
natural gas assets and business in New York, Connecticut and Maine.
October 29, 1999
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
PAGE
<S> <C>
I. EXECUTIVE SUMMARY. . . . . . . . . . . 1
II. CONCLUSIONS. . . . . . . . . . . . . . 5
III. SPIN-OFF ASSUMPTIONS . . . . . . . . . 7
IV. GENERAL STUDY ASSUMPTIONS. . . . . . . 9
V. NEWGASCO ANALYSIS. . . . . . . . . . . 11
A. Specific Assumptions . . . . . . . 11
B. Organization of NewGasCo . . . . . 14
C. Annual Cost Increases. . . . . . . 18
D. Capital Cost Increases . . . . . . 28
E. Transition Cost Increases. . . . . 30
F. Additional Lost Economies. . . . . 31
G. Total Lost Economies . . . . . . . 32
VI. OTHER CUSTOMER IMPACTS . . . . . . . . 34
VII. EFFECT ON REMAINING ELECTRIC CUSTOMERS 35
</TABLE>
i
<PAGE>
I. EXECUTIVE SUMMARY
Energy East Corporation, with the assistance of PHB Hagler Bailly, has conducted
this analysis of the economic impact of spinning off Energy East's natural gas
assets and operations on the shareholders and its customers of Energy East.
This study made several key assumptions:
- - This study assumed that Energy East's acquisitions of CTG Resources Inc.
("CTG Resources") and Connecticut Energy Corporation ("Connecticut Energy")
were completed and that Connecticut Natural Gas Company ("CNGC, " a
subsidiary of CTG Resources) and Southern Connecticut Gas ("Southern
Connecticut," a subsidiary of Connecticut Energy) became operating
subsidiaries of Energy East.
- - This study assumed that Energy East's natural gas business consists of four
operating subsidiaries: the natural gas business associated with NYSEG;
CNGC; Southern Connecticut; and CMP Natural Gas ( a joint venture between
Energy East and Central Maine Power).
- - This study assumed that, if required, Energy East would spin-off its
natural gas business into a stand-alone gas company, independent of Energy
East. The new company is referred to as "NewGasCo," and would encompass
the natural gas businesses of the relevant segments of NYSEG (currently a
combination electric and gas company), CNGC, Southern Connecticut, and CMP
Natural Gas.
- - This study assumed that CMP Natural Gas would continue in its start-up
state, sharing management and resources from the other NewGasCo segments as
appropriate.
- - This study assumed the current customer levels and business structure of
the Energy East operating subsidiaries.
This study quantifies the increased costs or "lost economies" associated with
divesting the existing Energy East natural gas business from two perspectives:
1) from the position of the shareholder; and 2) from the position of the
customer. The effects on shareholders were calculated by assuming that there
would be no regulatory relief to compensate for the increased costs resulting
from the divestiture of Energy East's natural gas business. The effects on
customers were calculated by assuming that the increased costs resulting from
divestiture would be recovered through regulator-approved rate increases. In
addition to increased rates, customers may also be impacted by other
quantifiable and non-quantifiable costs in the event of divestiture.
Quantification of economic losses was performed in detail for the NYSEG segment
of Energy East's natural gas business. As this study demonstrates, the economic
losses associated with divestiture of the NYSEG segment of Energy East's natural
gas business would be significant. The aggregate effect of the divestiture of
Energy East's natural gas business into NewGasCo would be $30.5 million.
1
<PAGE>
While there would also be losses in the form of foregone savings through
divestiture of Energy East's proposed CNGC and Southern Connecticut segments, a
quantification of the economic losses associated with this further divestiture
was not performed at this time. It is anticipated that efficiencies and
associated savings will be gained as CNGC and Southern Connecticut are
integrated into Energy East. These potential cost savings translate into lost
economies if the acquisitions of CNGC and Southern Connecticut were not
completed. The lost economies associated with the spin-off of these segments
from Energy East are economies that will be realized over years following
integration of CNGC and Southern Connecticut into Energy East. Experience with
various acquisitions and mergers in the electric, gas and telecommunications
industries indicates that related savings typically are significant.
At a minimum, savings are likely to be realized in the areas of consolidation of
corporate governance functions, shareholder services and other corporate
functions, cost of capital, and uncollectibles. Assuming that Energy East would
be required to spin-off its CNGC and Southern Connecticut segments subsequent to
an approved acquisition, the economic losses associated with that action would
be in addition to the approximately $30.5 million resulting from the spin-off of
the natural gas portion of Energy East's NYSEG segment.
The projected impacts on the Energy East shareholders of the portion of lost
economies associated with the spin-off of Energy East's NYSEG natural gas
segment is shown in Table I-1. The impact on shareholders assumed that rate
adjustments are not allowed to recover the lost economies and associated income
taxes.
<TABLE>
<CAPTION>
TABLE I-1
ANNUAL SHAREHOLDER IMPACT OF LOST ECONOMIES
LOST ECONOMIES AS A PERCENT OF:
<S> <C>
Total Gas Operating Revenues. . . . . . 9.6%
- --------------------------------------- ------
Total Gas Operating Revenues Deductions 10.2%
- --------------------------------------- ------
Gross Gas Income. . . . . . . . . . . . 147.3%
- --------------------------------------- ------
Net Gas Income. . . . . . . . . . . . . 239.3%
- --------------------------------------- ------
</TABLE>
In Table I-1, Total Gas Operating Revenue is the sum of all natural gas revenues
for the 12 months ending December 31, 1998 for Energy East's NYSEG natural gas
segment. Total Gas Operating Revenue Deductions include all purchased gas,
operations and maintenance expenses, administrative and general expenses,
depreciation, interest, taxes other than income taxes, and other income
deductions. Gross Gas Income is the difference between Total Gas Operating
Revenue and Total Gas Operating Revenue Deductions. Net Gas Income is Gross Gas
Income minus income taxes.
2
<PAGE>
Alternatively, assuming that NewGasCo is allowed by state regulators to increase
its rate revenue to recover the lost economies and associated income taxes
through rate increases, the projected impact on customers is shown in Table I-2.
<TABLE>
<CAPTION>
TABLE I-2
ANNUAL GAS CUSTOMER IMPACT OF LOST ECONOMIES
============================================
REVENUE
<S> <C>
Pre-Spin-off . . $305,880,754
- ---------------- -------------
Post-Spin-off. . $336,429,508
- ---------------- -------------
Increase . . . . $ 30,548,754
- ---------------- -------------
Percent Increase 10.0%
- ---------------- -------------
</TABLE>
In addition to the foregoing impacts relating to the natural gas business,
divesting the NYSEG natural gas segment from Energy East would result in a rate
increase of 0.87 percent on Energy East's remaining electric customers
(comprised of NYSEG's current electric business). This impact is primarily due
to: 1) the expense associated with additional electric business unit employees
being required to support functions that previously were provided by employees
jointly for both the electric and gas business units; 2) the expenses associated
with certain fixed costs which were previously allocated between the electric
and gas business units now being borne entirely by the electric business unit;
and 3) the capital cost associated with the transfer of assets, as well as the
acquisition of new assets, into the electric rate base. The analysis of the
impact on the remaining electric customers assumed that the pass-through of lost
economies and associated income taxes was allowed by state regulators. This
impact is shown in Table I-3.
3
<PAGE>
<TABLE>
<CAPTION>
TABLE I-3
ANNUAL ELECTRIC CUSTOMER IMPACT OF LOST ECONOMIES
=================================================
REMAINING NYSEG
RATE REVENUE ELECTRIC CUSTOMERS
<S> <C>
Pre-Spin-off . . $ 1,519,207,240
- ---------------- --------------------
Post-Spin-off. . $ 1,532,385,532
- ---------------- --------------------
Increase . . . . $ 13,178,292
- ---------------- --------------------
Percent Increase 0.87%
- ---------------- --------------------
</TABLE>
Finally, a significant portion of NYSEG's current customers receive both
electric and natural gas services and pay a single bill. These customers would
incur increased personal costs such as postage on separate envelopes and any
costs associated with writing additional checks to remit payment to two
utilities rather than one. In addition, a non-quantifiable impact involves the
confusion to many customers resulting from doing business with two utilities
instead of one. Increased postage expense to customers is shown in Table I-4.
<TABLE>
<CAPTION>
TABLE I-4
OTHER ANNUAL CUSTOMER IMPACTS
=============================
<S> <C>
Postage $754,158
======= ========
</TABLE>
4
<PAGE>
II. CONCLUSIONS
The spin-off of Energy East's natural gas business into a stand-alone company is
estimated to result in a substantial increase in costs. Absent any
regulator-approved relief to recoup these decreased earnings through increases
in rates charged to customers, the immediate effect on the shareholders of
Energy East would be substantial. On the other hand, if the increases in cost
are passed through to customers, customers would experience a significant
increase in the level of rates, with no attendant increase in the level or
quality of service.
The aggregate effect of the divestiture of Energy East's natural gas businesses
into NewGasCo would be approximately $30.5 million for the NYSEG segment of
Energy East's natural gas business alone, as shown in Table I-2. The rate
increase required to provide the level of revenue needed to cover these costs
would amount to approximately 10 percent. Such a rate increase would come at a
time when NewGasCo would be facing the emergence of retail competition and
increased competition in the energy industry. Economic losses would also result
in a revenue requirement increase of $13.2 million to Energy East's remaining
electric business, which if passed on to customers would amount to an increase
of about 0.87%.
In addition to the economic losses associated with the NYSEG segment of Energy
East's natural gas business, it is anticipated that additional economic losses
would be associated with the divestiture of the Energy East's CNGC and Southern
Connecticut segments. Estimates of the economic losses associated with the CNGC
and Southern Connecticut segments of Energy East's natural gas business have not
been quantified at this time. The lost economies associated with the spin-off of
these segments from Energy East are economies that will be realized over several
years following the integration of CNGC and Southern Connecticut into Energy
East. These potential cost savings translate into lost economies if the
acquisition of CNGC and Southern Connecticut were not completed.
Experience with various acquisitions and mergers in the electric, gas and
telecommunications industries indicates that related savings typically are
significant. Review of aspects of the operations and administration of CNGC and
Southern Connecticut indicate that post-acquisition savings (and hence economic
losses) are likely to be realized in the areas of consolidation of corporate
governance functions, shareholder services and other corporate functions, cost
of capital, and uncollectibles.
The quantified effects of divestiture on the combined natural gas and electric
businesses for Energy East's NYSEG segment alone exceeds $43 million. The
effect of the additional, yet as of the present unquantified, impacts associated
with the CNGC and Southern Connecticut segments of Energy East's natural gas
business will unquestionably increase the total estimate of economic losses.
5
<PAGE>
Divestiture would not provide any likely benefits to NewGasCo in the form of
operational improvements or regulatory efficiencies. From an operations
perspective, the segments of Energy East's natural gas business will be managed
as independent operating units. Aside from sharing certain common corporate
functions, Energy East plans to continue this local approach following the
acquisition of CNGC and Southern Connecticut. The Connecticut and New York
Commissions currently regulate these companies and will continue to do so
whether the companies are spun-off or remain part of Energy East.
Based on the foregoing analysis, spinning-off Energy East's natural gas
businesses would result in significant lost economies, to the detriment of
Energy East's shareholders and/or its gas and electric customers.
6
<PAGE>
III. SPIN-OFF ASSUMPTIONS
This study has applied several key assumptions in determining the lost economies
resulting from Energy East divesting itself of its natural gas business.
A. This study assumed that Energy East's acquisitions of CTG Resources Inc.
("CTG Resources") and Connecticut Energy Corporation ("Connecticut Energy")
were completed and that Connecticut Natural Gas Company ("CNGC," a
subsidiary of CTG Resources) and Southern Connecticut Gas ("Southern
Connecticut," a subsidiary of Connecticut Energy) became operating
subsidiaries of Energy East.
B. This study assumed that Energy East's natural gas business consists of four
operating subsidiaries: the natural gas business associated with NYSEG;
CNGC; Southern Connecticut; and CMP Natural Gas (a joint venture between
Energy East and Central Maine Power).
C. This study assumed that, if required, Energy East would spin-off its
natural gas business into a stand-alone gas company, independent of Energy
East. The new company is referred to as "NewGasCo," which would encompass
the natural gas businesses of the relevant segments of NYSEG (a combination
electric and gas company), CNGC, Southern Connecticut, and CMP Natural Gas.
D. This study assumed current level of customers and business for Energy
East's operating subsidiaries.
1. NYSEG is a combination electric and gas utility, engaged in: 1) the
purchase, transmission, distribution and sale of electricity; and 2)
the purchase, transmission, distribution, sale and transportation of
natural gas. NYSEG's gas business includes transmission and
distribution facilities serving numerous communities across New York
State, encompassing approximately 244,000 residential, commercial and
industrial customers. NYSEG's 1998 gas revenues were about $306
million with associated gas deliveries of about 61,689 thousand
dekatherms. NYSEG's electricity business serves approximately 826,000
residential, commercial and industrial customers in New York.
2. CNGC is a gas utility involved in the purchase, transmission,
distribution, sale and transportation of natural gas. CNGC serves
approximately 143,300 residential, commercial and industrial customers
in 22 Connecticut communities, principally in the Hartford-New Britain
area and Greenwich. CNGC's 1998 gas revenues were about $262 million
with associated gas deliveries of about 47,725,537 mmBtus.
7
<PAGE>
3. Southern Connecticut is a gas utility involved in the purchase,
transmission, distribution, sale and transportation of natural gas.
Southern Connecticut delivers natural gas to approximately 158,000
customers in 22 communities in southern Connecticut, including the
cities of Bridgeport and New Haven. Southern Connecticut's 1998 gas
revenues were about $216 million with associated gas deliveries of
about 32,728 thousand dekatherms.
4. The Securities and Exchange Commission recently approved the joint
venture between Energy East and CMP Group subsidiaries that formed CMP
Natural Gas. CMP Natural Gas is a start-up gas business and is
currently developing a customer base, has minimal recorded revenues
and few employees.
8
<PAGE>
IV. GENERAL STUDY ASSUMPTIONS
The assumptions, information and data used in this study are based on industry
expertise and experience of personnel at Energy East and PHB Hagler Bailly. The
Energy East personnel providing input and analyses into this study included
employees with experience in all major aspects of utility operations and
corporate support. Energy East retained PHB Hagler Bailly to assist in
developing this study, relying on the firm's industry experience and
independence as an external party. PHB Hagler Bailly is an economic and
management consulting firm specializing in the energy industry and has expertise
in cost analysis and utility operations. The conclusions of this study
represent the combined and independent inputs and analyses of Energy East
personnel and PHB Hagler Bailly consultants. The general assumptions applied to
develop lost economies follow:
A. The economic losses associated with the spin-off of the NYSEG segment of
Energy East's natural gas operations into NewGasCo were quantified, based
on an analysis of the work functions, facilities, vehicles, information
system and telecommunications, and capital requirements associated with the
utility.
B. A comprehensive analysis of the economic losses associated with the CNGC
and Southern Connecticut segments were not performed at this time. Examples
of economic losses associated with the spin-off of the CNGC and Southern
Connecticut segments of Energy East's natural gas operations were
identified in part in the accompanying analysis.
C. The economic losses associated with the spin-off of the CNGC and Southern
Connecticut segments of Energy East's natural gas operations were assumed
to be equal to the savings that will be realized over several years
following the integration of CNGC and Southern Connecticut into Energy
East.
D. Economic losses were developed in dollar amount and as a percentage of
Total Gas Operating Revenue, Total Gas Operating Revenues Deductions, Gross
Gas Income, and Net Gas Income for the spin-off of NYSEG's natural gas
operations. Depiction of the economic losses as a percentage of aggregate
statistics reflecting the combined NYSEG, CNGC, Southern Connecticut and
CMP Natural Gas segments would provide inaccurate and misleading results.
E. The base case, from which economic losses were measured, used 1998 revenue,
cost, employee, customer, asset and other data provided by Energy East.
F. NewGasCo would require the organization, employees, facilities and
infrastructure to ensure that customers receive appropriate levels of
service, that operations be conducted in a safe and reliable fashion, for
the company to plan for the future, and for the company to meet industry
and functional practices regarding corporate and support services.
9
<PAGE>
1. NewGasCo would have the facilities, equipment, materials and supplies,
management and personnel, and information and telecommunications
systems to function on a stand-alone basis.
2. Operating subsidiaries would continue to be managed as independent
units.
3. Staffing levels for NewGasCo's field and corporate functions were
based on current levels of efficiency and service quality and at a
level appropriate for a natural gas company of its size.
4. The various business segments of NewGasCo would share resources when
possible, enabling NewGasCo to realize efficiencies in certain
functions. Savings would include consolidation of the Board of
Director and governance function, shareholder service function, as
well as certain other common corporate functions.
G. Costs were developed on a bottom-up basis.
1. Labor costs were determined using the average labor cost for the
relevant job function. The costs of pensions and benefits were then
added to the labor cost based on the loading used by Energy East.
2. Non-labor costs included the costs for information systems,
telecommunications, field facilities, postage and others. Certain
functions were outsourced for the purpose of this analysis when such
treatment enhanced cost efficiencies.
H. All economic losses represent the net effect after the allocations to the
gas business unit from the combined company have been taken into account.
10
<PAGE>
V. NEWGASCO ANALYSIS
The quantification of the impact of a divestiture of the NYSEG segment of Energy
East's natural gas business was conducted by the management and staff of Energy
East and PHB Hagler Bailly. This quantification addressed the impact of a
spin-off of the Energy East's NYSEG segment alone into a stand-alone NewGasCo
comprised of Energy East's NYSEG, CNGC, Southern Connecticut and CMP Natural Gas
segments. Quantification addressed requirements for organization, staffing
levels and labor costs; outside services; buildings and facilities construction
and operations and maintenance; furniture and equipment; vehicles; information
systems; telecommunications networks; and other costs.
A. SPECIFIC ASSUMPTIONS
1. Labor Assumptions:
a. The current organizational structures, business practices and
levels of efficiency were used as the basis for NewGasCo's
organization and staffing levels.
b. Numbers of employees required for NewGasCo were developed using a
bottom-up approach, in which each functional area was reviewed to
determine the nature of the work performed and the level of
effort required to support a stand-alone gas company. Functional
managers were interviewed and consulted to determine the
appropriate staffing levels.
c. Meter reading and customer service data, such as reads per day
and call response, were considered to determine the needed
staffing levels to read meters and staff the Call Center for the
stand-alone company.
d. Employee benefits were assumed to be similar to the existing
levels of benefits. Pensions and benefits were estimated as a
percentage of direct labor cost. The pension and benefits
percentage excluded any over-funding, which would be credited to
the spun-off company on a negotiated basis.
e. Re-negotiation of union contracts was assumed to be minimal.
f. Labor cost increases were determined on a net basis.
Labor-related allocations from the combined utility were deducted
from the cost of labor for NewGasCo.
g. Labor costs were determined using the average labor costs for
employees in each functional area.
11
<PAGE>
2. Board of Director Assumptions: The previously shared Board of
Directors would have to be provided on a stand-alone basis to NewGasCo
and to NYSEG's remaining electric business.
3. Outside Services Assumptions: Requirements for certain outside
services which were conducted jointly on behalf of the combined
electric and gas company would have to be provided on a stand-alone
basis to NewGasCo and to NYSEG's remaining electric business. Examples
of these services include the annual financial audit performed by an
independent external auditor, transfer agent services, certain legal
services, safety training, and human resource and benefit consulting.
4. Building, Facilities and Vehicles Assumptions:
a. Facilities requirements were determined through the analysis of
geographic service areas and levels of staffing. A division
approach was adopted for NewGasCo, following NYSEG's current
field organizational structure. One division was eliminated as no
gas customers are located within the bounds of that division.
b. Field office size was determined by building-up requirements from
the number of employees. Field offices costs also include
furniture, garage and equipment, and parking and paved areas and
operations and maintenance costs.
c. Vehicles were determined by building-up requirements of NewGasCo
employees. Specialized gas vehicles are already assigned to the
gas businesses. NewGasCo incremental vehicle needs were comprised
of passenger vehicles and small pick-up trucks.
d. Operations and maintenance costs for facilities and vehicles were
based on the NYSEG rates.
5. Information Systems and Telecommunications Assumptions:
a. NewGasCo would need to procure information system (IS)
capabilities that it currently receives as part of the combined
utility. NewGasCo's information systems would need to support the
requirements associated with finance and accounting, human
resources, payroll, work management, inventory and purchasing
functions, field services, meter reading and customer services.
Historically, utilities have constructed information systems
themselves to meet their unique requirements. For a stand-alone
gas business with less than 300,000 customers, IS needs would
more efficiently be procured through licensing agreements with
software packages. The build-up of NewGasCo IS costs was based on
lease costs for licensed software packages. Labor costs
associated with maintaining the IS system and supporting IS users
were included in the Labor Cost section of this study. IS costs
are net of the related allocations from the combined utility.
12
<PAGE>
b. NewGasCo would need to develop telecommunications capabilities
across its various locations and between field office and
personnel in the field. These capabilities would include a radio
dispatch system that allows communications between the field and
dispatch locations, various data circuits, telephone service
including 800 service and cellular service, yellow page listings,
and internet connectivity. Telecommunications costs are net of
the related allocations from the combined utility.
6. Depreciation Assumptions: Annual depreciation was calculated for
NewGasCo's incremental buildings and facilities, vehicles and
capitalized labor, using the NYSEG's depreciation rates. Additionally,
depreciation was calculated for additional assets or transfers of
assets to the remaining electric business.
7. Other Cost Assumptions: Other costs included in the determination of
the total annual cost increase included the increased costs of postage
and uncollectibles. Uncollectibles rates for NewGasCo were based on
benchmarks for stand-alone gas companies.
8. Capital Expenditure and Cost Assumptions:
a. NewGasCo's new capital would consist of: 1) the costs associated
NewGasCo's building, facilities, and plant notably field offices,
corporate offices and a call center; 2) vehicle purchases; and 3)
capitalized labor.
b. The divestiture of NewGasCo was assumed to be a tax-free spin-off
to the existing shareholders. This would involve the
incorporation of NewGasCo, transfer of gas-related assets to
NewGasCo, and distribution of shares to current shareholders.
c. Capital costs associated with NewGasCo were based on the analysis
of the capital costs of publicly traded companies which are
primarily involved in the business of gas distribution to
industrial, commercial and retail customers. Because gas
distribution is a regulated industry, this provides a reasonable
estimate of the financial conditions which NewGasCo would face as
independent business entity.
d. Statutory returns were used in determining capital costs because
they reflect approved regulatory returns. In regulated industries
anticipated investor returns will be guided by regulatory
returns.
e. The cost of debt for NewGasCo is based on the current yield for
25-year debentures for an investment grade corporation, assuming
an investment rating of "BBB+."
13
<PAGE>
f. The spin-off of NewGasCo is based on an asset transfer at the net
book value of the existing gas assets attributable to NYSEG's
natural gas business plus additional capital expenditures.
g. Working capital costs following divestiture are assumed to be the
same as pre-spin-off rates.
9. Transition Cost Assumptions:
a. Transition costs primarily reflect financial transaction costs
and professional fees, such as legal fees.
b. Divestiture of NewGasCo would not require redemption of the
existing NYSEG mortgage or pollution control bonds. The residual
capital base in the remaining electric business would be adequate
to satisfy indenture requirements.
c. Divestiture would be structured to avoid material federal or
state income tax events. The future tax obligations of NewGasCo
and the remaining electric business would be based on the
stand-alone future tax obligations of the independent entities
and would not be materially effected by the spin-off itself.
d. Investment banking fees related to debt issuance were estimated
to be approximately 0.875 percent of the total debt amount.
Investment banking fees related to stock issuance were estimated
to be 1.5 percent of the total equity issuance amount.
e. Transaction costs associated with recapitalization were included
with transition costs. These costs were amortized over 25 years
and include the issuance of new debt and common stock for
NewGasCo.
B. ORGANIZATION OF NEWGASCO
The organizational structure of NewGasCo reflects the needs of the company in
providing service to its customers, in meeting mandatory legal and regulatory
requirements and in conducting business following industry and generally
accepted business practices. Organizational structure is a primary determinant
of the level of staffing for NewGasCo which, in turn, determines labor costs.
In 1998, NYSEG's electric, gas and combined operations accounted for 3,341
employees. Following divestiture, NewGasCo would no longer be able to share
staff for various corporate and field functions. Considerable organizational
adjustment would be required for NewGasCo, as it would need to ensure that many
of the services previously provided jointly with the electric business are now
provided on a stand-alone basis. These include adjustments to the field
organizations as well as to corporate functions. NYSEG's current structure
provided the basic structure for the NewGasCo organization. In addition,
management representing each of NYSEG's functional areas were consulted for
input concerning the requirements for a stand-alone NewGasCo. Also, experience
with utility benchmarks and industry practices were taken into account.
14
<PAGE>
1. Board of Directors. NewGasCo would require a Board of Directors. The
Board for NewGasCo would be similar in size and composition to the
Board associated with Energy East, which is currently composed of ten
Directors.
2. President and Chief Executive Officer. The President and CEO would
report directly to the Board of Directors and would be responsible for
overseeing the entire NewGasCo. The President and CEO would have five
direct reports spanning the following functions: Chief Operating
Officer; Chief Financial Officer; General Counsel; Information
Systems; and Human Resources.
3. Chief Operating Officer would report directly to the President and CEO
and would be responsible for the operating activities of NewGasCo,
which would include Corporate Support, Customer Service, Gas Planning
and Supply, Field Operations, and Marketing.
a. Corporate Support includes administering the various contracts
for services provided to the Company, oversight of the garages
and transportation equipment used throughout the Company,
managing various facilities and real estate, supporting licensing
applications and coordinating material management. In 1998, NYSEG
had 98 employees in the Corporate Support function (29 hourly and
69 salaried). NewGasCo would include additional support services
currently provided through other NYSEG organizations. These
include security, printing and graphics and mail services. In
1998, NYSEG employed 32 people (10 hourly and 22 salaried) in
these functions. NewGasCo would require 28 employees to
accomplish the Corporate Support function. NYSEG's remaining
electric business would need 124 employees to meet the
requirements of this function.
b. Customer Service spans a range of customer-oriented services. In
1998, the total employees for the Customer Service department
were 294 (220 hourly and 74 salaried employees). The largest
component of Customer Service is the Call Center. In 1998,
NYSEG's Call Center employed 221 people to answer customer
inquiries, assist with service installations and disconnections,
respond to billing inquiries, and other customer related issues.
The majority of Call Center employees (209) are hourly employees,
with the remaining 12 employees performing supervisory and
managerial functions. Customer Service is a critical component of
a utility's relationship with its customers. State regulators
have also developed standards regarding access by customers to
the utility for emergencies and for inquiries. NewGasCo would
require 68 Customer Service employees, 54 of whom would be
employed in the Call Center. NYSEG's remaining stand-alone
electric business would need 276 employees to meet electric-only
Customer Service requirements, including 210 employees in the
Call Center.
15
<PAGE>
c. Gas Planning and Supply involves the procurement of gas supply,
the selection of financial instruments to hedge gas prices, the
control of the utility's gas infrastructure, the planning for gas
infrastructure and construction, and the gas meter shop. In 1998,
NYSEG's gas operation had 90 employees (15 hourly and 75
salaried) involved in these functions. These employees would be
transferred to NewGasCo.
d. Division Operations refers to the construction and customer
activities taking place in the various geographic regions and
divisions. NYSEG currently has segmented its operations into 5
regions covering 13 divisions. Each division is responsible for
connecting and disconnecting customers, reading meters,
constructing facilities and meeting with customers for NYSEG's
electric and gas operations. While some functions, such as
specialized construction activities, are distinctly assigned to
either the gas or electric business, other activities (such as
meter reading) are performed jointly for both businesses. Each
division is headed by a manager. The divisions are in turn
overseen by five Regional Managers. In 1998, NYSEG's division
operations employed 2,063 employees, including Regional Managers
(1,700 hourly and 363 salaried). Only one division does not have
gas customers. Based on the number of gas customers to be served
and the customer density of the geographic area, NewGasCo would
require 522 employees in its divisions. NYSEG's remaining
electric business would require 1,715 employees in its field
organization.
e. Marketing and Sales involves the analysis and sales support to
address specific customer needs, and to position NewGasCo to
retain and acquire customers. In 1998, NYSEG's marketing and
sales activities related to natural gas employed 23 people, all
of whom were salaried. These employees would be transferred to
NewGasCo.
4. The Chief Financial Officer (CFO) function would be responsible for
the rates and regulatory, controller, treasury, tax, shareholder
services, corporate planning, audit and economic development and
public policy functions.
a. Rates and Regulatory involves the development of rates and prices
for natural gas services and the regulatory approval of tariffs,
as well as certain issues associated with billing. In 1998,
NYSEG's rates and regulatory activities related to natural gas
employed 19 people, all of whom were salaried. These employees
would be transferred to NewGasCo.
b. The Controller function is responsible for the integrity of the
Company's accounting books and records and for preparing various
reports and filings. In 1998, the Controller function employed 40
people (17 hourly and 23 salaried). The Controller function would
have to be replicated in order to serve two distinct stand-alone
companies. NewGasCo would require 10 people to perform the
various controller activities. NYSEG's remaining electric
business would need 35 people to meet its controller
requirements.
16
<PAGE>
c. Treasury involves the management of investments, cash and
disbursements, as well as financial planning. In 1998, NYSEG's
treasury function employed 35 people (20 hourly and 15 salaried).
The treasury function would have to be replicated in order to
serve two distinct stand-alone companies. NewGasCo would require
5 people to perform the treasury activities. NYSEG's remaining
electric business would need 30 people to meet its treasury
requirements.
d. The Tax function involves the preparation of income and property
tax submissions. In 1998, NYSEG's Tax organization employed 14
people (3 hourly and 11 salaried). the Tax function would have to
be replicated in order to serve two distinct stand-alone
companies. NewGasCo would require 4 people to perform the tax
activities. NYSEG's remaining electric business would need 12
people to meet its tax requirements.
e. Shareholder Services involves tracking and maintaining
communications with equity holders and the transfer agency
function. NYSEG with Chase Mellon currently acts as its own
transfer agent. In 1998, the Shareholder Services function
employed 7 people (4 hourly and 3 salaried). NewGasCo would
require 2 people to perform the Shareholder Services function,
who would coordinate with an outsourced transfer agent. NYSEG's
remaining electric business would need 7 people to continue its
shareholder services function.
f. Corporate Planning and Budgets involves the analysis and
projection of the Company's actual and budgeted (capital and
operations and maintenance) financial state. This function
typically is involved with various special projects. In 1998,
NYSEG employed 32 people (4 hourly and 28 salaried) in this
function. NewGasCo would require 5 people to perform corporate
planning and budgets activities. NYSEG's remaining electric
business would need 28 people to meet this requirement.
g. Audit involves the management and coordination of the annual
financial audit performed by an independent audit firm. The audit
function and the associated certification from the independent
audit firm are mandatory for public companies. In 1998, NYSEG's
Audit organization employed 12 people (1 hourly and 11 salaried).
NewGasCo would require 4 people to perform audit activities.
NYSEG's remaining electric business would need 11 people to meet
its audit requirements.
17
<PAGE>
h. Economic Development and Public Policy is responsible for area
and business development, coordination with state and regional
economic development programs, as well as the tracking and
analysis of regulatory and legislative initiatives. In 1998,
NYSEG's Economic Development and Public Policy organization
employed 24 people, all of whom were salaried. NewGasCo would
require 6 people to perform this function. NYSEG's remaining
electric business would need 21 people to perform the economic
development and public policy function.
5. General Counsel is responsible for all aspects involving legal
compliance and/or risk. This function performs legal services itself
and manages specialized outside counsel. In 1998 NYSEG employed 9
people in Legal Services, all of whom were salaried. NewGasCo would
require 3 legal employees to meet ongoing legal requirements, but
would need to outsource larger and more specialized cases to outside
counsel. NYSEG's remaining electric business would need 8 people to
meet its requirements for legal services.
6. Information Services is responsible for the development and
maintenance of the full range of information systems and
telecommunications networks. This function includes various managers
and staff responsible for application development, infrastructure
standards, security, user training, and the telecommunication network.
In 1998 NYSEG employed 125 people in Information Services (19 hourly
and 106 salaried). NewGasCo would require 22 employees in Information
Services. NYSEG's remaining electric business would need 114 people to
meet its information services requirements.
7. Human Resources includes labor relations, organizational development,
training, the development of compensation and benefits plans,
ensurance of compliance with employee-related regulations and
maintenance of employee-related information systems. The size of the
Human Resources department is typically related to the size of the
Company. In 1998 NYSEG employed 46 people in Human Resources, all of
whom were salaried. NewGasCo would require 11 employees in Human
Resources. NYSEG's remaining electric business would need 40 people to
meet its human resources requirements.
C. ANNUAL COST INCREASES
The incremental annual costs associated with divesting the NYSEG natural gas
segment of Energy East is shown in Table V-2.
18
<PAGE>
<TABLE>
<CAPTION>
TABLE V-2
ANNUAL COST INCREASES TO GAS COMPANY
====================================
<S> <C>
Labor Costs . . . . . . . . $ 9,525,980
- --------------------------- -----------
Pension and Benefits. . . . $ 3,619,872
- --------------------------- -----------
Board of Directors. . . . . 270,000
- --------------------------- -----------
Outside Services. . . . . . $ 2,346,005
- --------------------------- -----------
Building and Facilities O&M $ 429,463
- --------------------------- -----------
Vehicles and Equipment O&M. $ 62,772
- --------------------------- -----------
Information Systems . . . . $ 2,380,999
- --------------------------- -----------
Telecommunications. . . . . $ 2,532,930
- --------------------------- -----------
Depreciation. . . . . . . . $ 365,037
- --------------------------- -----------
Postage . . . . . . . . . . $ 563,836
- --------------------------- -----------
Uncollectables. . . . . . . $ 1,398,969
- --------------------------- -----------
Total Annual Cost Increase. $23,495,863
</TABLE>
1. Labor costs represent the largest single cost increase resulting from
the spin-off of NewGasCo.
a. The spin-off of NewGasCo would require the duplication of many
job activities that were jointly provided to both NYSEG's
electric and gas businesses. These jobs fall into five
categories:
i. Division Operations involves field activities that were
jointly performed for both the electric and gas businesses.
These include meter readers, field service representatives,
customer service representatives, engineering, construction,
energy delivery and various administrative and supervisory
functions. NewGasCo would need to ensure it could perform
each of these functions at a level to ensure continued
quality service to its customers. An analysis of each
function was conducted to determine the number and
classifications of employees that would be needed by
NewGasCo,. The number of additional employees needed for
NYSEG's remaining electric business was also determined.
ii. Corporate Functions reflect a range of supporting and
administrative activities. Included in this category are
support to operating divisions, the provision of centralized
services across the company, and planning and management to
ensure continuity across the company and compliance with
requirements for the corporation. An analysis of each
corporate function was conducted to determine the number and
classifications of employees that would be needed by
NewGasCo, as well as for the NYSEG's remaining electric
business.
19
<PAGE>
iii. Call Center is a critical area of centralized support
responsible for interaction with customers in matters of new
service, disconnections, billing, inquiries. The Call Center
is also responsible for scheduling appointments with
customers. NewGasCo would have to build a call center,
install telecommunications and customer information system
capabilities, and staff the call center. (The costs
associated with facility construction are discussed under
Facilities and Vehicles. The costs associated with
telecommunications and customer information systems are
discussed under Information Systems and
Tele-communications.) Staffing requirements alone are
considerable. Based on call center demand and requirements
and input from NYSEG's current call center personnel, a
stand-alone NewGasCo call center would require about 54
employees. A stand-alone call center for NYSEG's remaining
electric business would require about 210 employees.
iv. Gas Supply & Planning refers to the functions associated
with planning, financing and supplying gas across NewGasCo's
system. The employees associated with this function are
currently dedicated to Energy East's gas business and will
be transferred to NewGasCo. Therefore no additional
employees will be required to fulfill the requirements
associated with this function.
v. Board of Directors were previously shared by NYSEG's
electric and gas businesses. NewGasCo would be required to
acquire its own Board. The cost of NYSEG's current Board
would be assigned to the remaining electric business
b. The number of incremental employees needed by NewGasCo to meet
the business requirements and the associated incremental labor
costs are shown in Table V-3. The incremental labor costs have
netted out any allocations made by the combined utility to the
gas business unit. Pensions and benefits were added to
incremental labor cost based on the pension and benefit
percentage loading used by NYSEG.
20
<PAGE>
<TABLE>
<CAPTION>
TABLE V-3
SUMMARY OF INCREMENTAL LABOR COSTS
==================================
LABOR INCREMENTAL INCREMENTAL PENSION & BENEFITS TOTAL
CATEGORY EMPLOYEES LABOR COST COST
<S> <C> <C> <C> <C>
Division Operations. . . . . . . . . . . . 120 $ 6,885,000 $ 2,616,300 $ 9,501,300
- ------------------------------------------ ----------- ------------ ------------------- -----------
Corporate Functions. . . . . . . . . . . . 2 220,847 83,922 304,769
- ------------------------------------------ ----------- ------------ ------------------- -----------
Support Services. . . . . . . . . . . . . 11 $ 416,134 $ 158,131 $ 547,265
Customer Services (excluding Call Center) 6 $ 400,026 $ 152,010 $ 552,036
Chief Financial Officer . . . . . . . . . 10 $ 506,084 $ 192,312 $ 698,396
Information Services. . . . . . . . . . . 5 $ 312,074 $ 118,588 $ 430,662
Human Resources . . . . . . . . . . . . . 5 $ 524,983 $ 199,493 $ 724,476
Marketing, Sales and Pricing. . . . . . . 0 -- -- --
Economic Development and Policy . . . . . 2 $ 142,016 $ 53,966 $ 195,982
Shareholder Services. . . . . . . . . . . 1 $ 49,466 $ 18,797 $ 68,263
Legal . . . . . . . . . . . . . . . . . . 2 $ 139,850 $ 53,143 $ 192,993
Call Center. . . . . . . . . . . . . . . . 3 $ 135,587 $ 51,523 $ 187,110
- ------------------------------------------ ----------- ------------ ------------------- -----------
Gas Planning & Supply. . . . . . . . . . . 0 -- -- --
- ------------------------------------------ ----------- ------------ ------------------- -----------
Board of Directors . . . . . . . . . . . . 9 $ 270,000 -- $ 270,000
- ------------------------------------------ ----------- ------------ ------------------- -----------
Total. . . . . . . . . . . . . . . . . . . 176 $ 9,795,982 $ 3,619,873 $13,415,855
</TABLE>
c. NewGasCo's staffing was also benchmarked against other
stand-alone gas companies on the basis of customers per employee,
a generally accepted measure of efficiency. NewGasCo is compared
to other gas companies in Table V-4.
21
<PAGE>
<TABLE>
<CAPTION>
TABLE V-4
COMPARISON OF CUSTOMERS PER EMPLOYEE
====================================
NUMBER OF
DISTRIBUTION NUMBER OF CUSTOMERS
GAS UTILITY CUSTOMERS EMPLOYEES PER EMPLOYEE
<S> <C> <C> <C>
Corning Natural Gas . . . 14,100 72 195.8
- ------------------------- ------------ --------- ------------
Filmore Gas Company . . . 906 7 129.4
- ------------------------- ------------ --------- ------------
CTG Resources . . . . . . 140,411 611 229.8
- ------------------------- ------------ --------- ------------
Yankee Energy Systems . . 180,476 673 268.2
- ------------------------- ------------ --------- ------------
Southern Connecticut Gas. 148,273 532 278.7
- ------------------------- ------------ --------- ------------
Washington Gas Light. . . 798,739 2,484 321.6
- ------------------------- ------------ --------- ------------
Boston Gas. . . . . . . . 515,218 1,532 336.3
- ------------------------- ------------ --------- ------------
Piedmont Natural Gas. . . 506,632 1,983 255.5
- ------------------------- ------------ --------- ------------
NewGasCo. . . . . . . . . 243,000 830 292.8
- ------------------------- ------------ --------- ------------
NYSEG (estimate). . . . . 243,000 663 366.5
- ------------------------- ------------ --------- ------------
<FN>
Source: Brown's Directory of North American and International Gas Companies
================================================================================
(1999).
=======
</TABLE>
d. NYSEG's level of efficiency is comparable with or exceeds most of
the stand-alone companies. As expected, the addition of employees
for NewGasCo lowers the efficiency of the gas company compared
with its original position. NewGasCo's reduced efficiency would
also be a result of divisions with few gas customers and low
density, as shown in Table V-5.
22
<PAGE>
<TABLE>
<CAPTION>
TABLE V-5
DIVISION COMPARISON
===================
NEWGASCO-NY NUMBER OF NUMBER OF CUSTOMERS
DIVISION METERS EMPLOYEES PER EMPLOYEE
<S> <C> <C> <C>
Brewster. . . 1,004 8 126
- ------------- --------- --------- ------------
Mechanicville 2,161 12 180
- ------------- --------- --------- ------------
Plattsburgh . 938 9 104
- ------------- --------- --------- ------------
Geneva. . . . 39,451 68 580
- ------------- --------- --------- ------------
Ithaca. . . . 31,831 62 513
- ------------- --------- --------- ------------
Auburn. . . . 20,315 43 472
- ------------- --------- --------- ------------
Elmira. . . . 32,631 58 563
- ------------- --------- --------- ------------
Binghamton. . 64,468 100 645
- ------------- --------- --------- ------------
Oneonta . . . 13,850 50 277
- ------------- --------- --------- ------------
Liberty . . . 3,093 14 221
- ------------- --------- --------- ------------
Lockport. . . 30,204 59 512
- ------------- --------- --------- ------------
Hornell . . . 14,326 34 421
- ------------- --------- --------- ------------
Total . . . . 254,272 517* 492
<FN>
*Excludes 5 Regional Managers who oversee the 12 Field Divisions.
==========================================================================
</TABLE>
2. Outside Services refers to the full range of externally provided
services. These services include consulting services, the annual
financial audit, benefits planning, transfer agent services and legal
services. NewGasCo would need to acquire several outside services if
it were spun-off from Energy East. The outside services and the
associated costs for these services for NYSEG were reviewed in terms
of the types and extent of services which would be needed by NewGasCo.
The additional costs associated with outside services for NewGasCo
would be $2.3 million.
3. Building and Facilities reflect the incremental operations and
maintenance expenses associated with buildings and facilities needed
by NewGasCo.
a. NewGasCo would need to construct or lease buildings and
associated garages and parking areas for their field operations.
NYSEG currently has 13 divisions, each of which have one or more
buildings to house field personnel, division supervisory and
administrative personnel and vehicles. Currently, one facility in
the Binghamton, NY area is dedicated to gas operations, and it is
assumed that this building would be transferred to NewGasCo and
used as NewGasCo's Binghamton division office. Another NYSEG
division does not have gas customers, eliminating the need for a
NewGasCo division in that area. Thus, NewGasCo would have to
construct or lease 11 buildings for division operations. NYSEG
facility managers have found that leasing options may not be
available in the geographic locations of the divisions.
23
<PAGE>
b. Corporate offices would also be required for NewGasCo. The size
of the corporate offices were determined based on the number of
employees that were employed in the corporate facilities.
c. NewGasCo would also have to construct a Call Center, involving
physical space and furniture for the Call Center. The Call Center
would be located in NewGasCo's corporate facility. The cost for
the Call Center was determined on the same basis as Corporate
Offices.
d. Building costs were determined on a location-by-location basis,
using the number of division employees by job classification as
the primary determinant of facilities requirements. Facility
costs included office and computer equipment and garage
equipment. Operations and maintenance costs covering building
maintenance and utility costs were determined based on NYSEG's
O&M costs in its division locations.
e. The incremental cost associated with financing building and
facility construction is included under Capital Costs; the
incremental cost associated with the depreciation of these
buildings and facilities is under Depreciation.
f. Building and facility, capitalized equipment and operations and
maintenance costs for these buildings are shown in Table V-6. The
incremental cost to NewGasCo for the operations and maintenance
associated with these buildings and facilities is $429,463 (which
is shown on Table V-2.
24
<PAGE>
<TABLE>
<CAPTION>
TABLE V-6
BUILDING CONSTRUCTION AND OPERATING COSTS
=========================================
NEEDED OPERATING
FACILITY BUILDING SIZE BUILDING AND CAPITALIZED EQUIPMENT COSTS
LOCATION (SQ. FT) FACILITY CONSTRUCTION COST COST
<S> <C> <C> <C> <C>
Corporate Offices 101,600 $ 5,129,256 $ 1,016,000 $1,259,953
- ----------------- -------------- --------------------------- ---------------------- ----------
Call Center . . . 5,940 $ 417,080 $ 135,000 $ 71,476
- ----------------- -------------- --------------------------- ---------------------- ----------
Brewster. . . . . 2,272 $ 196,047 $ 44,000 $ 28,559
- ----------------- -------------- --------------------------- ---------------------- ----------
Mechanicville . . 3,108 $ 230,003 $ 51,000 $ 25,040
- ----------------- -------------- --------------------------- ---------------------- ----------
Plattsburgh . . . 2,481 $ 198,724 $ 45,750 $ 24,712
- ----------------- -------------- --------------------------- ---------------------- ----------
Geneva. . . . . . 14,812 $ 1,222,468 $ 149,000 $ 120,687
- ----------------- -------------- --------------------------- ---------------------- ----------
Ithaca. . . . . . 13,558 $ 986,295 $ 138,500 $ 40,172
- ----------------- -------------- --------------------------- ---------------------- ----------
Auburn. . . . . . 9,587 $ 721,599 $ 105,250 $ 73,973
- ----------------- -------------- --------------------------- ---------------------- ----------
Elmira. . . . . . 12,722 $ 899,420 $ 131,500 $ 94,724
- ----------------- -------------- --------------------------- ---------------------- ----------
Oneonta . . . . . 11,050 $ 825,649 $ 117,500 $ 107,950
- ----------------- -------------- --------------------------- ---------------------- ----------
Liberty . . . . . 3,526 $ 270,871 $ 54,500 $ 28,002
- ----------------- -------------- --------------------------- ---------------------- ----------
Lockport. . . . . 12,931 $ 875,970 $ 133,250 $ 93,133
- ----------------- -------------- --------------------------- ---------------------- ----------
Hornell . . . . . 7,706 $ 563,342 $ 89,500 $ 56,913
Total NewGasCo. . 201,293 $ 12,436,726 $ 2,210,750 $2,025,295
- ----------------- -------------- --------------------------- ---------------------- ----------
</TABLE>
4. The costs for Vehicles and Equipment refers to the incremental
vehicles that would need to be purchased and maintained to meet the
requirements of the spun-off gas companies. NewGasCo would require the
addition of vehicles that were previously jointly used in NYSEG's
division operations. In addition, several incremental vehicles would
be required for corporate personnel.
a. Specialized gas operations vehicles and equipment was already
assigned to NYSEG's gas business unit and it is assumed that
these will be transferred to NewGasCo.
b. Incremental vehicle requirements will be for passenger vehicles
and ton pickup trucks, reflecting usage by meter readers and
field service representatives. The number of vehicles were
derived from the job classification and number of employees.
25
<PAGE>
c. The incremental cost associated with financing vehicle
acquisition is included under Capital Costs; the incremental cost
associated with the depreciation of these vehicles is included
under Depreciation.
d. The incremental number of vehicles needed by NewGasCo, as well as
the vehicle acquisition cost and operations and maintenance costs
are shown in Table V-7.
<TABLE>
<CAPTION>
TABLE V-7
INCREMENTAL VEHICLE COST
========================
NUMBER OF INCREMENTAL
INCREMENTAL VEHICLE OPERATING
VEHICLES COST COST
<S> <C> <C> <C>
Binghamton . . 10 $ 195,000 $ 6,060
Brewster . . . 3 $ 60,000 $ 1,865
Mechanicville. 4 $ 75,000 $ 2,331
- -------------- ----------- ------------ ----------
Plattsburgh. . 5 $ 105,000 $ 3,263
- -------------- ----------- ------------ ----------
Geneva . . . . 8 $ 150,000 $ 4,661
- -------------- ----------- ------------ ----------
Ithaca . . . . 5 $ 90,000 $ 2,797
- -------------- ----------- ------------ ----------
Auburn . . . . 8 $ 165,000 $ 5,127
- -------------- ----------- ------------ ----------
Elmira . . . . 10 $ 195,000 $ 6,060
- -------------- ----------- ------------ ----------
Oneonta. . . . 13 $ 255,000 $ 7,924
- -------------- ----------- ------------ ----------
Liberty. . . . 8 $ 165,000 $ 5,127
- -------------- ----------- ------------ ----------
Lockport . . . 7 $ 135,000 $ 4,195
- -------------- ----------- ------------ ----------
Hornell. . . . 8 $ 150,000 $ 4,661
- -------------- ----------- ------------ ----------
Corporate. . . 14 $ 280,000 $ 8,701
Total NewGasCo 101 $ 2,020,000 $ 62,772
</TABLE>
5. Information Systems and Telecommunications reflect the replacement of
infrastructure that were provided by Energy East relating to computing
and connectivity. NewGasCo would have to acquire sufficient
information system and telecommunications capabilities to operate
effectively on a stand-alone basis.
26
<PAGE>
a. Information systems capabilities would need to address
fundamental business applications, industry practices and
regulatory requirements. Specialized gas business applications,
such as the System Control and Data Acquisition (SCADA) system
are already assigned to NYSEG's gas business and it is assumed
the related hardware and software would be transferred to
NewGasCo. In determining the incremental cost of information
systems to NewGasCo, information systems managers and specialists
were consulted for input. The most efficient cost approach was
used. For NewGasCo, this would involve the licensing of
pre-packaged, multi-purpose software as opposed to in-house
development. The licensing costs associated with several software
packages capable of supporting NewGasCo's needs were reviewed.
The total incremental cost for NewGasCos information systems
would be about $2.4 million, including the net effect of
allocations from the combined utility.
(i) NewGasCo would need a full suite Enterprise Resource
Planning (ERP) system which would cover its accounting,
human resource, payroll, work management, inventory and
purchasing needs.
(ii) A Customer Information System (CIS) would also be required
which would store and allow access to customer records, be
integrated with customer billing and be used extensively by
Call Center personnel.
(iii)NewGasCo would also need Field Service Systems and Meter
Reading System software packages.
b. NewGasCo's telecommunications costs involve to the connectivity
across the company and between field operations and dispatch
locations.
(i) Radio dispatch system is a critical component of utility
operations. Commercially available mobile communications
networks, such as work crew radio services offered by
NexTel, are not available throughout NYSEG's or NewGasCo's
service territory. The cost for radio dispatch for NewGasCo
was determined by reviewing a lease proposal from Motorola
for this service. This approach is considerably more
economical than construction of a radio dispatch facility,
which would include tower construction and attachments
across New York State. The annual cost of a leased radio
dispatch system covering NewGasCo's service area would be
approximately $2.7 million.
(ii) Access to dialtone, 800 services, cellular service and
leasing and maintenance for telephone systems.
(iii)Various data and supervisory circuits and network
supervisions for NewGasCo.
27
<PAGE>
(iv) Other telephone costs, such as yellow page publishing costs
and internet-related cost.
(v) As a lower volume user than the combined NYSEG, NewGasCo
would receive a reduced discount on various telephone
contracts.
(vi) Netting the effect of telecommunications costs being
directly charged to the gas business or charged on an
allocated basis, the incremental telecommunications cost to
NewGasCo would be $2,532,930.
6. Depreciation cost increases result from the addition of buildings and
facilities, furniture, computer equipment, vehicles, and garage
equipment required by the stand-alone NewGasCo. Regulatory approved
depreciation rates were applied to each of the asset values to
determine annual depreciation costs. The incremental depreciation for
NewGasCo would be about $365,037.
7. Postage cost increases would result from the duplication of bill
mailings associated with NYSEG's current combined gas and electric
customers. Postage costs were calculated using a $.01 volume discount.
In 1998, NYSEG had almost 190,000 customers who received both gas and
electric service. The increased cost of postage to NewGasCo would be
$563,836.
8. Uncollectibles represents an area of increased costs in a stand-alone
gas company scenario. Benchmark data indicates that uncollectibles are
generally lower for a combined utility than for a stand-alone gas
company. NYSEG's current uncollectible rate for its combined utility
is less than one percent. The level of incremental uncollectible cost
was determined through the review of benchmark data. Uncollectible
cost increases are estimated to be $1.4 million.
D. CAPITAL COST INCREASES
The capital cost for the potential spin-off will increase as a result of
increased cost of equity and debt.
1. The cost of equity for NewgasCo will be higher than the current cost
of equity capital for Energy East's natural gas business. This
increased cost reflects the higher risk of operating an independent
business. The cost of equity capital for NewGasCo was estimated by
determining the median regulatory equity cost of comparable
publicly-traded stand-alone gas utilities, as reported by Bloomberg
Financial Services.
2. The cost of debt for NewGasCo will also be higher than the cost of
debt of the natural gas business unit under Energy East. NewGasCo is
not likely to finance debt at the same cost as NYSEG. It is assumed
that NewGasCo would not have access to tax exempt pollution control
bonds and preferred stock securities, but will rely on corporate
debentures It was assumed that the borrowing costs for NewGasCo will
be approximately 1.6 percent higher than for NYSEG.
28
<PAGE>
3. A comparison of the costs of equity, debt and the weighted average
cost of capital (WACC) is shown for Energy East and NewGasCo in Table
V-8. The weighted average cost of capital comparison reflects the net
capital cost once both the effects of leverage and the tax
deductibility of interest expense have been considered.
<TABLE>
<CAPTION>
TABLE V-8
CAPITAL COST COMPARISON
=========================
ENERGY NEWGASCO INCREASE
EAST (DECREASE)
<S> <C> <C> <C>
CAPITAL COST
COMPONENTS
Cost of Equity. 11.20% 11.83% 0.63%
Cost of Debt. . 6.37% 7.97% 1.60%
WACC PARAMETERS
Debt Financing 52.80% 52.80% ----
=============== ======= ========== =========
Tax Rate 35.00% 35.00% ----
WACC. . . . . . 7.47% 8.32% 0.84%
=============== ======= ========== =========
</TABLE>
4. The total impact of the lost economies due to capital costs is
captured by (1) the increase in the NewGasCo WACC shown above and (2)
new equity and debt financing at NewGasCo's higher cost resulting from
the new capital expenditures discussed in an earlier section. The
impact of these two incremental financial costs is shown in Table V-9.
The impact of capital costs on NewGasCo lost economies is
approximately $5.5 million per year, $4 million of which is
attributable to higher capital costs and $1.5 million of which is
attributable to new capital financing requirements.
29
<PAGE>
<TABLE>
<CAPTION>
TABLE V-9
TOTAL CAPITAL COST LOST ECONOMIES
==================================
TOTAL
EQUITY DEBT COST
<S> <C> <C> <C>
Resulting From
Increase in Capital
Cost. . . . . . . . $1,412,794 $2,610,129 $4,022,922
=================== ========== ========== ==========
Resulting From New
Capital Expenditure $ 988,382 $ 484,230 $1,472,613
=================== ========== ========== ==========
Total . . . . . . . $2,401,176 $3,094,359 $5,495,535
=================== ========== ========== ==========
</TABLE>
5. In addition, Energy East's remaining electric business would incur
$509,082 in increased capital costs as a result of the spin-off.
E. TRANSITION COST INCREASES
The divestiture of Energy East's natural gas business into a stand-alone
NewGasCo would be a complex legal and financial undertaking that would involve
substantial transition costs. These costs would include legal and financial
advisory fees, investment banking fees, and the services of independent
accountants, actuaries and other consultants. Transition costs were determined
based on the fee schedules for the professional services identified above, costs
incurred in other divestitures and input from Energy East financial managers.
Total transition costs are estimated at $264,415 per year illustrated in the
Table V-10
30
<PAGE>
<TABLE>
<CAPTION>
TABLE V-10
TRANSITION COSTS
================
TOTAL COSTS ANNUALIZED
<S> <C> <C>
Legal Fees. . . . . $ 750,000 $ 30,000
- ------------------- ------------ -----------
Debt Issuance . . . $ 2,199,582 $ 87,983
- ------------------- ------------ -----------
Stock Issuance. . . $ 3,3,70,788 $ 134,832
- ------------------- ------------ -----------
Benefits Consulting $ 40,000 $ 1,600
- ------------------- ------------ -----------
Consulting Support. $ 250,000 $ 10,000
- ------------------- ------------ -----------
Total . . . . . . . $ 6,610,370 $ 264,415
</TABLE>
F. ADDITIONAL LOST ECONOMIES
In addition to the economic losses associated with the NYSEG segment of Energy
East's natural gas business, additional economic losses associated with the
divestiture of Energy East's CNGC and Southern Connecticut segments would be
likely. However, a quantification of the economic losses associated with the
CNGC and Southern Connecticut segments of Energy East was not performed at this
time. Cost savings associated with the spin-off of these segments from Energy
East likely will be realized over years following integration of CNGC and
Southern Connecticut into Energy East. These potential cost savings translate
into lost economies if the acquisitions of CNGC and Southern Connecticut were
not completed. Experience with various mergers in the electric, gas and
telecommunications industries indicates that merger-related savings typically
can be significant. NewGasCo is likely to realize savings in the following
areas:
1. Corporate governance costs, such as the cost associated with Corporate
Secretaries and certain Board of Director related expenses.
2. Certain corporate functions likely will be consolidated following the
acquisitions of CNGC and Southern Connecticut by Energy East. These
include various financial, accounting, treasury and corporate planning
functions.
3. Shareholder services and transfer agency function will not be required
for multiple entities.
4. Cost of capital savings are anticipated to accrue as CNGC and Southern
Connecticut operations receive equity and debt financing through
Energy East.
31
<PAGE>
5. Uncollectibles cost, as indicated in benchmark data, are greater for
stand-alone gas companies than for combined utilities. Energy East
will apply best industry practices to reduce the uncollectible rates
for CNGC and Southern Connecticut.
6. Operational Efficiencies and the associated savings are derived from
several factors, including the degree of operational consolidation and
the deployment of improved practices in areas such as construction,
manpower planning, gas supply, and customer service. Energy East plans
to manage CNGC and Southern Connecticut as independent operating
units, which minimizes efficiency gains caused by operating staff
consolidation. However, Energy East will apply best industry practices
to these areas of CNGC and Southern Connecticut to achieve savings in
operating costs.
7. Outside Services would be rationalized following the integration of
CNGC and Southern Connecticut into Energy East. These savings include
reductions in certain areas of consulting and legal support.
Savings resulting from the integration of CNGC and Southern Connecticut into
Energy East likely will be achieved over the course of several years. The full
extent of savings is dependent on several factors, including the size and cost
structures of the organizations involved, as well as the anticipated levels of
operational integration. Experience gained from previous merger and acquisition
activities in utilities and telecommunications in the last several years has
indicated that annual cost savings can be substantial.
Energy East has not quantified the savings associated with the acquisition of
CNGC and Southern Connecticut, and hence the economic losses associated with the
spin-off of these segments. Assuming that Energy East would be required to
spin-off its CNGC and Southern Connecticut segments subsequent to an approved
acquisition, the economic losses associated with that action would be in
addition to the considerable economic losses resulting from the spin-off of the
natural gas portion of Energy East's NYSEG segment.
G. TOTAL LOST ECONOMIES
Summing the quantified portion of increased annual costs, increased capital
costs and amortized transition costs yields total lost economies of about $29.3
million per year. Recovery of the foregoing lost economies in a general rate
proceeding would also require an increase to recover income taxes associated
with the lost economies. This effect would result from additional income tax
requirements associated with the equity-financed portion of additional assets
and the taxes associated with the incremental equity costs associated with the
asset base transferred from Energy East to NewGasCo. Incremental income taxes
would be $1.3 million. The total quantified impact on the revenue requirements
of NewGasCo would be $30.5 million. This quantified portion reflects only the
economic losses associated with a spin-off of Energy East's existing NYSEG
natural gas segment into a stand-alone company together with Energy East's CNGC,
Southern Connecticut, and CMP Natural Gas segments.
32
<PAGE>
VI. OTHER CUSTOMER IMPACTS
In addition to the foregoing lost economies relating to the NewGasCo and
potentially their customers, customers of the NewGasCo will experience other
impacts.
A. Under a spin-off scenario, NYSEG customers who received combined electric
and gas services would have to incur additional costs in check writing and
postage. At year-end 1998, NYSEG provided combined electric and gas service
to 190,000 customers. These customers would have to mail two payments to
two separate utilities, at a cost of approximately $754,000.
B. CMP Natural Gas is a start-up venture targeting the greater Portland, ME
market. CMP Natural Gas will provide customers with access to natural gas
and an alternative to other energy providers. By itself, NewGasCo may not
be able to finance the CMP Natural Gas start-up, which would remove CMP
Natural Gas from the Maine market.
C. Several non-quantifiable impacts would also result from the spin-off of
Energy East's natural gas business.
1. Although customer choice is important in the emerging energy market, a
segment of customers prefer to deal with one utility instead of two.
2. Customers will have to provide additional access to meters and other
facilities to two utilities instead of one.
33
<PAGE>
VII. EFFECT ON REMAINING ELECTRIC CUSTOMERS
Divesting Energy East's natural gas businesses will also have an effect on
remaining Energy East business and customers. Specifically, many of the costs
that were shared between NYSEG's gas and electric businesses would have to be
assigned to one business or the other. In most cases, because NYSEG's electric
business is significantly larger than its gas business (approximately 817,000
electric customers at year-end 1998, compared with about 243,000 gas customers),
most of the facilities and infrastructure associated with the jointly provided
services would remain with the electric business. Cost previously allocated to
the gas business would be incurred by the electric business resulting in
increased costs. The increased cost are the result of:
A. Increased labor costs resulting from the elimination of shared job
functions in division operations, corporate services, call center and
corporate governance.
B. Increased outside service costs resulting from the elimination of the
allocation of costs associated with services such as benefits planning and
audit.
C. Increased building and facilities costs as sharing of facilities with the
gas business would be eliminated.
D. Increased vehicles and equipment cost resulting from additional vehicle
purchases required for meter readers and field service representative
supporting the electric business.
E. Increased information systems costs as sharing of IS with the gas business
would be eliminated.
F. Increased telecommunications costs, notably with regard to the elimination
of joint usage of radio dispatch.
G. Increased depreciation costs reflecting the transfer of previously common
assets to the electric business.
H. Increased postage costs since the electric business would be required to
mail individual bills to its customers.
The total increased cost to NYSEG's remaining electric customers is shown in
Table V-11.
34
<PAGE>
<TABLE>
<CAPTION>
TABLE V-11
ANNUAL COST INCREASES TO ELECTRIC BUSINESS
==========================================
<S> <C>
Labor Costs . . . . . . . . . $ 5,401,368
- ----------------------------- -----------
Pension and Benefits. . . . . $ 2,052,520
- ----------------------------- -----------
Outside Services. . . . . . . $ 1,257,170
- ----------------------------- -----------
Building and Facilities Costs $ 1,275,021
- ----------------------------- -----------
Vehicles and Equipment. . . . $ 7,613
- ----------------------------- -----------
Information Systems . . . . . $ 1,819,001
- ----------------------------- -----------
Telecommunications. . . . . . $ 136,981
- ----------------------------- -----------
Depreciation. . . . . . . . . $ 321,954
- ----------------------------- -----------
Postage . . . . . . . . . . . $ 167,469
- ----------------------------- -----------
Capital Costs . . . . . . . . $ 509,082
Board of Directors. . . . . . $ 30,000
Total . . . . . . . . . . . . $12,978,180
</TABLE>
Energy East's remaining electric business would also experience an increase in
income taxes of $200,112. Including the income tax impact, the total lost
economies for Energy East's remaining electric business would be $13,178,292.
35
<PAGE>
<TABLE>
<CAPTION>
Energy East Corporation
Combined Condensed Balance Sheet
Giving Effect to the CMP Group Merger
and the CTG Resources Merger
At June 30, 1999
Actual and Pro Forma
(Unaudited)
Pro Forma
Energy East
and CMP CTG Merger
Connecticut Group Resources Pro Forma Pro Forma
Energy Actual Actual Adjustments Energy East
- --------------------------------------------------------------------------------------------------
Assets (thousands)
<S> <C> <C> <C> <C> <C>
Current Assets
Cash and cash equivalents . . . . $1,079,671 $ 335,094 $ 36,013 ($652,013)(4) $ 798,765
Special deposits. . . . . . . . . 911 911
Accounts receivable, net. . . . . 165,872 125,754 35,704 327,330
Other . . . . . . . . . . . . . . 183,710 13,230 20,411 217,351
----------- ---------- -------- --------- ----------
Total Current Assets . . . . 1,430,164 474,078 92,128 (652,013) 1,344,357
Utility Plant, at Original Cost. . 4,545,703 1,332,465 520,743 6,398,911
Less accumulated depreciation . . 2,128,834 550,173 189,059 2,868,066
----------- ---------- -------- --------- ----------
Net utility plant in service. . 2,416,869 782,292 331,684 3,530,845
Construction work in progress . . 15,495 14,823 5,956 36,274
----------- ---------- -------- --------- ----------
Total Utility Plant. . . . . 2,432,364 797,115 337,640 3,567,119
Other Property and Investments, Net 109,170 72,081 12,476 193,727
Regulatory Assets. . . . . . . . . 331,344 872,787 6,781 30,808(5) 1,241,720
Other Assets . . . . . . . . . . . 72,524 41,529 28,416 5,081(5) 147,550
Goodwill . . . . . . . . . . . . . 249,360 653,812(6)(7) 903,172
----------- ---------- -------- --------- ----------
Total Assets . . . . . . . . $4,624,926 $2,257,590 $477,441 $ 37,688 $7,397,645
=========== ========== ======== ========= ==========
</TABLE>
The notes on pages 5 through 7 of this exhibit are an integral part of the pro
forma combined condensed financial statements.
2
<PAGE>
<TABLE>
<CAPTION>
Energy East Corporation
Combined Condensed Balance Sheet
Giving Effect to the CMP Group Merger
and the CTG Resources Merger
At June 30, 1999
Actual and Pro Forma
(Unaudited)
Pro Forma
Energy East
and CMP CTG Merger
Connecticut Group Resources Pro Forma Pro Forma
Energy Actual Actual Adjustments Energy East
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Liabilities (thousands)
Current Liabilities
Current portion of long-term debt
and sinking fund requirements . . $ 3,647 $ 18,716 $ 3,237 $ 25,600
Notes payable and interim financing 4,150 101,628 105,778
Taxes accrued . . . . . . . . . . . 308,371 154,386 462,757
Other . . . . . . . . . . . . . . . 255,756 94,180 43,190 $ 17,500(7) 410,626
----------- ----------- --------- --------- -----------
Total Current Liabilities . . . . 571,924 368,910 46,427 17,500 1,004,761
Regulatory Liabilities
Gain on sale of generation assets . 520,861 520,861
Other . . . . . . . . . . . . . . . 108,238 70,295 78,840 3,303(5) 260,676
----------- ----------- --------- --------- -----------
Total Regulatory Liabilities. . . 108,238 591,156 78,840 3,303 781,537
Deferred Income Taxes and
Unamortized Investment
Tax credits. . . . . . . . . . . . 291,762 83,091 1,778(8) 376,631
Other. . . . . . . . . . . . . . . . 328,339 494,312 30,808(5) 853,459
Long-term debt . . . . . . . . . . . 1,535,079 124,205 217,516 500,000(9) 2,376,800
----------- ----------- --------- --------- -----------
Total Liabilities . . . . . . . . 2,835,342 1,661,674 342,783 553,389 5,393,188
Commitments. . . . . . . . . . . . . 88 88
Preferred stock redeemable solely
at the option of subsidiary . . . 10,131 35,528 879 46,538
Preferred stock subject to mandatory
redemption requirements . . . . . 25,000 18,910 43,910
Common Stock Equity
Common stock Energy East
($.01 par value, 300,000 shares
authorized and 124,188 shares
outstanding as of June 30, 1999). 1,257 61(10) 1,318
Common stock CMP Group
($5 par value, 80,000 shares
authorized and 32,443 shares
outstanding as of June 30, 1999). 162,213 (162,213)
Common stock CTG Resources
(no par value, 20,000 shares
authorized and 8,648 shares
outstanding as of June 30, 1999)
Capital in excess of par value. . . . 1,038,017 286,035 67,448 (193,988)(10) 1,197,512
Retained earnings . . . . . . . . . . 754,088 94,217 66,841 (161,058) 754,088
Unearned compensation -
restricted stock awards . . . . . . (510) 510
Treasury stock, at cost (1,500
shares at June 30, 1999). . . . . . (38,997) (987) 987 (38,997)
----------- ----------- --------- --------- -----------
Total Common Stock Equity. . . . . 1,754,365 541,478 133,779 (515,701) 1,913,921
----------- ----------- --------- --------- -----------
Total Liabilities and
Shareholders' Equity . . . . . . $ 4,624,926 $2,257,590 $477,441 $ 37,688 $7,397,645
=========== =========== ========= ========= ===========
</TABLE>
The notes on pages 5 through 7 of this exhibit are an integral part of the pro
forma combined condensed financial statements.
3
<PAGE>
<TABLE>
<CAPTION>
ENERGY EAST CORPORATION
COMBINED CONDENSED STATEMENT OF INCOME
GIVING EFFECT TO THE CMP GROUP MERGER
AND THE CTG RESOURCES MERGER
TWELVE MONTHS ENDED JUNE 30, 1999
ACTUAL AND PRO FORMA
(UNAUDITED)
Pro Forma
Energy East
and CMP CTG Merger
Connecticut Group Resources Pro Forma Pro Forma
Energy Actual Actual Adjustments Energy East
------------- --------- ---------- ----------- -------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Operating Revenues
Sales and services . . . . . . . $ 2,706,279 $993,357 $ 283,471 $ 3,983,107
Operating Expenses
Fuel used in electricity
generation . . . . . . . . . . 199,842 29,124 228,966
Electricity purchased. . . . . . 776,077 456,811 1,232,888
Natural gas purchased. . . . . . 273,387 140,997 414,384
Other operating expenses . . . . 405,341 233,486 54,001 692,828
Maintenance. . . . . . . . . . . 100,888 38,671 7,859 147,418
Depreciation and amortization. . 712,050 55,540 20,199 $ 16,345(11) 804,134
Other taxes. . . . . . . . . . . 224,631 26,895 19,512 271,038
Gain on sale of generation assets (674,572) (674,572)
Writeoff of Nine Mile Point 2. . 69,930 69,930
------------- -------------
Total Operating Expenses. . . 2,087,574 840,527 242,568 16,345 3,187,014
------------- --------- ---------- ----------- -------------
Operating Income . . . . . . . . . 618,705 152,830 40,903 (16,345) 796,093
Other Income and Deductions. . . . (9,013) (39,321) (2,711) (51,045)
Merger related expenses. . . . . . 1,537 1,537
Interest Charges, net. . . . . . . 142,974 57,068 17,042 37,500(9) 254,584
Preferred Stock Dividends
of Subsidiary. . . . . . . . . . 5,775 3,676 61 9,512
------------- --------- ---------- -------------
Income Before Federal Income Taxes 477,432 131,407 26,511 (53,845) 581,505
Federal Income Taxes . . . . . . . 231,764 58,169 12,253 (13,125)(8) 289,061
------------- --------- ---------- ----------- -------------
Net Income . . . . . . . . . . . . $ 245,668 $ 73,238 $ 14,258 ($40,720) $ 292,444
============= ========= ========== =========== =============
Earnings Per Share, basic and
Diluted. . . . . . . . . . . . . $ 1.87 $ 2.12
Average Common Shares Outstanding. 131,606 6,107(12) 137,713
</TABLE>
The notes on pages 5 through 7 of this exhibit are an integral part of the pro
forma combined condensed financial statements.
Per share amounts and number of average Energy East shares outstanding have been
restated to reflect the two-for-one common stock split, effective April 1, 1999.
4
<PAGE>
<TABLE>
<CAPTION>
Energy East Corporation
Combined Condensed Statement of Retained Earnings
Giving Effect to the CMP Group Merger
and the CTG Resources Merger
Twelve Months Ended June 30, 1999
Actual and Pro Forma
(Unaudited)
Pro Forma
Energy East
and CMP CTG Merger
Connecticut Group Resources Pro Forma Pro Forma
Energy Actual Actual Adjustments Energy East
------------ ------- ---------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Balance, beginning of period. . . $ 624,936 $50,512 $ 61,394 ($111,906) $ 624,936
Add net income. . . . . . . . . . 231,213 73,238 14,258 (87,496) 231,213
Add restricted stock plan . . . . 9 (9)
Deduct dividends on common stock. 102,061 29,199 8,820 (38,019) 102,061
Deduct reacquired preferred stock 333 (333)
------- ------------
Balance, end of period. . . . . . $ 754,088 $94,218 $ 66,841 ($161,059) $ 754,088
============ ======= ========== ============ ============
</TABLE>
The notes on pages 5 through 7 of this exhibit are an integral part of the pro
forma combined condensed financial statements.
5
<PAGE>
NOTES TO UNAUDITED PRO FORMA
COMBINED CONDENSED FINANCIAL STATEMENTS
GIVING EFFECT TO THE CMP GROUP MERGER
AND THE CTG RESOURCES MERGER
Note 1. Unaudited Pro Forma Combined Condensed Financial Statements.
The unaudited pro forma combined condensed financial statements as of and
for the twelve months ended June 30, 1999, have been adjusted to give effect to
the CMP Group Merger and the CTG Resources merger. The unaudited pro forma
combined condensed financial statements reflect preliminary purchase accounting
adjustments in compliance with generally accepted accounting principles.
Estimates relating to the fair value of some assets, liabilities and other
events have been made as more fully described below. Actual adjustments will be
made on the basis of actual assets, liabilities and other items as of the
closing date of the mergers on the basis of appraisals and evaluations.
Therefore, actual amounts may differ from those reflected below.
The unaudited pro forma combined condensed balance sheet and statement of
retained earnings assume that the mergers occurred on June 30, 1999. The
unaudited pro forma combined condensed statement of income for the twelve months
ended June 30, 1999, assumes that the mergers were completed on July 1, 1998 and
does not give effect to the sales of Energy East's coal-fired generation assets
and CMP Group's steam and hydro generation assets prior to when they occurred in
March and May 1999 and April 1999, respectively, and the pending sale of Energy
East's interest in nuclear generation assets.
The pro forma combined condensed financial statements should be read in
conjunction with the consolidated historical financial statements and the
related notes of Energy East, CMP Group and CTG Resources, which are
incorporated by reference. The pro forma statements are for illustrative
purposes only. They are not necessarily indicative of the financial position or
operating results that would have occurred had the sales and the mergers been
completed on July 1, 1998 or June 30, 1999, as assumed above; nor is the
information necessarily indicative of future financial position or operating
results.
Note 2. Accounting Method.
The CMP Group merger and the CTG Resources merger will be accounted for as
an acquisition of CMP Group and CTG Resources by Energy East under the purchase
method of accounting in accordance with generally accepted accounting
principles. The amount of goodwill recorded will reflect the excess of the
purchase prices over the estimated net fair value of assets and liabilities of
CMP Group's and CTG Resources's utility and nonutility businesses at the time of
closing, plus Energy East's estimated transaction cost related to the mergers.
The assets of CMP Group's and CTG Resources's unregulated subsidiaries will be
revalued to fair value, including an allocation of goodwill to the subsidiaries,
if appropriate. The remaining goodwill will be allocated to Central Maine Power
and Connecticut Natural Gas and will be recorded as an acquisition adjustment.
6
<PAGE>
Note 3. Earnings Per Share and Average Shares Outstanding.
The pro forma earnings per share and number of average shares outstanding
have been restated to reflect Energy East's two-for-one common stock split,
effective April 1, 1999, and the average number of shares that would have been
outstanding if the merger occurred at the beginning of the periods presented
assuming a conversion of 45% CTG Resources shares into 1.57 Energy East shares
per CTG Resources share. The following table presents the range of shares that
could be issued based on various potential conversion ratios under the merger
agreement:
Conversion ratio 1.36 1.57 1.73
Number of shares (thousands) 5,296 6,107 6,740
Note 4. Cash Consideration.
This amount reflects the cash consideration paid to CMP Group's
shareholders based on a purchase price per share of $29.50 for all of the CMP
Group shares outstanding and the cash consideration paid to CTG Resources
shareholders based on a purchase price per share of $41.00 for 55% of the CTG
Resources shares outstanding.
Note 5. Regulatory Asset and Related Other Liability, and Other Asset and
Related Regulatory Liability.
This amount reflects the recognition of a regulatory asset and related
other liability, or, an other asset and related regulatory liability for the
estimated difference between CMP Group's and CTG Resources's pension and other
postretirement benefit obligations and the previously unrecognized asset or
liability.
Note 6. Goodwill.
This amount reflects the recognition of an amount of goodwill equal to the
excess of the estimated purchase price of $957 million over the estimated net
fair value of the assets and liabilities of CMP Group acquired of $541.5
million, plus estimated transaction costs of $11 million related to the merger;
and an amount of goodwill equal to the excess of the estimated purchase price of
$355 million over the estimated net fair value of the assets and liabilities of
CTG Resources acquired of $134 million, plus estimated transaction costs of $6.5
million related to the merger.
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Note 7. Merger-Related Costs.
Energy East, CMP Group and CTG Resources will incur direct expenses related
to the merger, including financial advisor, legal and accounting fees. The pro
forma adjustments include an estimate for Energy East's merger-related costs of
$11 million for the CMP Group merger and $6.5 million for the CTG Resources
merger, which are included in goodwill. CMP Group and CTG Resources expect to
incur approximately $7.5 million and $5.5 million, of merger-related costs,
respectively, which they will expense as incurred. The actual amount of
merger-related costs may differ from the amounts reflected in the unaudited pro
forma combined condensed financial statements.
Note 8. Income Taxes.
Income taxes on the pro forma combined condensed income statement have been
based on the statutory rate and adjusted for goodwill, which is not tax
deductible.
Note 9. Notes Payable
This amount reflects the issuance of $500 million principal amount of notes
payable with an assumed interest rate of 7.5%, the proceeds of which may be used
to fund the consideration paid to CMP Group shareholders.
Note 10. Common Stock.
This amount reflects the Energy East shares to be issued to CTG Resources
shareholders in exchange for 45% of their CTG Resources shares, assuming a
conversion ratio of 1.57 Energy East shares per CTG Resources share, and the
purchase of 55% of their CTG Resources shares for cash.
Note 11. Amortization of Goodwill.
This amount represents the amortization of goodwill, for financial
accounting purposes, over a 40-year period. The goodwill is not amortizable for
tax purposes.
Note 12. Energy East Shares Issued.
Reflects the number of Energy East shares to be issued in the merger with
CTG Resources assuming a conversion of 45% of the CTG Resources shares into 1.57
Energy East shares per CTG Resources share.
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