<PAGE>
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________ to _________
Commission file number 1-2301
BOSTON EDISON COMPANY
(Exact name of registrant as specified in its charter)
<TABLE>
<S> <C>
Massachusetts 04-1278810
- ------------------------------------------ -------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
- ------------------------------------------ -------------------------
(Address of principal executive offices) (Zip Code)
</TABLE>
Registrant's telephone number, including area code: 617-424-2000
------------
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Name of each exchange
Title of each class on which registered
------------------- ---------------------
<S> <C>
Common stock, par value $1 per share New York Stock Exchange
Boston Stock Exchange
Cumulative preferred stock:
7.75% Series, par value $100 per share New York Stock Exchange
(represented by depositary shares-each
represents one-fourth interest in par value)
</TABLE>
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 24, 1998 computed as the average of the high and low
market price of the common stock as reported in the listing of composite
transactions for New York Stock Exchange listed securities in the Wall Street
Journal: $2,019,435,751.
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
Class Outstanding at March 24, 1998
-------------------------- -----------------------------
<S> <C>
Common Stock, $1 par value 48,514,973 shares
</TABLE>
<TABLE>
DOCUMENTS INCORPORATED BY REFERENCE
<CAPTION>
Part Document
- ---- --------
<S> <C>
III Portions of definitive proxy statement dated March 31, 1998 for Annual
Meeting of Stockholders to be held May 5, 1998.
</TABLE>
<PAGE> 1
Boston Edison Company
- -----------------------------------------------------------------------------
Form 10-K Annual Report
- -----------------------------------------------------------------------------
December 31, 1997
- -----------------------------------------------------------------------------
<TABLE>
<CAPTION>
Part I Page
- -----------------------------------------------------------------------------
<S> <C>
Item 1. Business 2
Item 2. Properties and Power Supply 6
Item 3. Legal Proceedings 8
Item 4. Submission of Matters to a Vote of Security Holders 8
Part II
- -----------------------------------------------------------------------------
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 11
Item 6. Selected Financial Data 12
Item 7. Management's Discussion and Analysis 13
Item 8. Financial Statements and Supplementary Financial
Information 24
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 51
Part III
- -----------------------------------------------------------------------------
Item 10. Directors and Executive Officers of the Registrant 52
Item 11. Executive Compensation 52
Item 12. Security Ownership of Certain Beneficial Owners and
Management 53
Item 13. Certain Relationships and Related Transactions 53
Part IV
- -----------------------------------------------------------------------------
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 54
</TABLE>
<PAGE> 2
Part I
------
Item 1. Business
- -----------------
(a) General Development of Business
- -----------------------------------
Boston Edison Company (the Company) is an investor-owned regulated public
utility incorporated in 1886 under Massachusetts law. The Company operates in
the energy, energy services and telecommunications business, which includes
the generation, purchase, transmission, distribution and sale of electric
energy and the development and implementation of electric demand side
management programs. Refer to the Electric Utility Industry Restructuring
section of Item 7 for information regarding the restructuring of the electric
utility industry and its impact on the Company.
The Company also conducts unregulated activities through its wholly owned
subsidiary, Boston Energy Technology Group (BETG). Through BETG and its
subsidiaries, the Company is engaged in certain nonutility businesses,
including energy utilization and conservation, construction management and
district energy. Refer to Note A to the Consolidated Financial Statements in
Item 8 for more information regarding the Company's nonutility business
ventures.
The Company is currently awaiting a decision from the Massachusetts Department
of Telecommunications and Energy (DTE), formerly the Department of Public
Utilities, and the Securities and Exchange Commission regarding its
reorganization plan to form a holding company structure. This plan has been
approved by the Federal Energy Regulatory Commission (FERC), the Nuclear
Regulatory Commission (NRC) and the Company's shareholders. Refer to Note A
to the Consolidated Financial Statements in Item 8 for more information
regarding the holding company structure.
(b) Financial Information about Industry Segments
- -------------------------------------------------
The Company operates primarily as a regulated electric public utility,
therefore industry segment information is not applicable.
(c) Narrative Description of Business
- -------------------------------------
Principal Products and Services
The Company supplies electricity at retail to an area of 590 square miles,
including the city of Boston and 39 surrounding cities and towns. The
population of the area served with electricity at retail is approximately 1.5
million. In 1997 the Company served an average of approximately 660,000
customers. The Company also supplies electricity at wholesale for resale to
other utilities and municipal electric departments. Electric operating
revenues by class for the last three years consisted of the following:
<TABLE>
<CAPTION>
1997 1996 1995
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Retail electric revenues:
Commercial 51% 50% 50%
Residential 27% 27% 28%
Industrial 9% 9% 9%
Other 1% 2% 2%
Wholesale and contract revenues 12% 12% 11%
===========================================================================
</TABLE>
<PAGE> 3
Sources and Availability of Fuel
The Company currently owns two stations whose generating units have the
ability to burn oil, natural gas or both, one nuclear power station and ten
combustion turbine generators. As discussed in Item 2, the Company entered
into an agreement to sell its non-nuclear generating assets in 1997.
Finalization of the sale is expected in mid-1998. The Company's generation by
type of fuel and the cost of fuel for each of the last five years were as
follows:
<TABLE>
<CAPTION>
Percentage of Company Average Cost of Fuel
Generation by Source (%) ($ per Million BTU)
-------------------------------- --------------------------------
1997 1996 1995 1994 1993 1997 1996 1995 1994 1993
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil 32.0 16.1 17.5 27.8 31.3 2.22 3.04 2.66 2.35 2.38
Gas 31.1 33.3 39.9 31.6 24.3 3.23 3.11 2.20 2.28 2.67
Nuclear 36.9 50.6 42.6 40.6 44.4 0.46 0.41 0.43 0.50 0.51
==============================================================================
</TABLE>
The majority of the Company's residual oil purchases consists of imported oil
acquired primarily from international suppliers. Through March 1997, the
Company had a contract with a major oil company to supply most of its
estimated requirements. The Company has been purchasing oil on the spot
market since that contract expired.
A portion of the Company's natural gas is supplied on an interruptible basis
by contract. These contracts permit interruptions in deliveries by the
supplier when natural gas supplies or pipeline capacity is unavailable. The
Company is currently required to fuel New Boston Station exclusively by
natural gas, except in certain emergency circumstances, as part of a 1991
consent order with the Massachusetts Department of Environmental Protection.
The Company has arrangements for a firm supply of natural gas to run the
station at a minimum level and has a least-cost plan for operating beyond this
minimum level which principally utilizes interruptible gas supplies or short-
term capacity purchases.
In order to obtain fuel for use at its nuclear generating unit, the Company
must obtain supplies of uranium concentrates and secure contracts for these
concentrates to go through the processes of conversion, enrichment and
fabrication of nuclear fuel assemblies. The Company currently has contracts
for supplies of uranium concentrates and the processes of conversion,
enrichment and fabrication through 2002, 2000, 2004 and 2012, respectively.
Franchises
Through its charter, which is unlimited in time, the Company has the right to
engage in the business of producing and selling electricity, steam and other
forms of energy, has powers incidental thereto and is entitled to all the
rights and privileges of and subject to the duties imposed upon electric
companies under Massachusetts laws. The locations in public ways for the
Company's electric transmission and distribution lines are obtained from
municipal and other state authorities which, in granting these locations, act
as agents for the state. In some cases the action of these authorities is
subject to appeal to the DTE. The rights to these locations are not limited
in time, but are not vested and are subject to the action of these authorities
and the legislature. Pursuant to the Massachusetts electric utility industry
restructuring legislation enacted in November 1997, the DTE has defined the
service territory of the Company based on the territory actually served on
July 1, 1997, and following, to the extent possible, municipal boundaries.
The legislation further provided that, until terminated by effect of law or
<PAGE> 4
otherwise, the Company shall have the exclusive obligation to provide
distribution service to all retail customers within such service territory.
No other entity shall provide distribution service within this territory
without the written consent of the Company which consent must be filed with
the DTE and the municipality so affected.
Seasonal Nature of Business
The Company's kilowatt-hour (kWh) sales and revenues are typically higher in
the winter and summer than in the spring and fall as sales tend to vary with
weather conditions. In addition, the Company bills higher base rates to
commercial and industrial customers during the billing months of June through
September as authorized by the DTE. Accordingly, greater than half of the
Company's annual earnings typically occurs in the third quarter. Refer to the
Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8.
Competitive Conditions
Refer to the Electric Utility Industry Restructuring section of Item 7 for a
discussion of the competitive conditions affecting the Company.
Environmental Matters
The Company is subject to numerous federal, state and local standards with
respect to the management of wastes, air and water quality and other
environmental considerations. These standards could require modification of
existing facilities or curtailment or termination of operations at these
facilities. They could also potentially delay or discontinue construction of
new facilities and increase capital and operating costs by substantial
amounts. Noncompliance with certain standards can, in some cases, also result
in the imposition of monetary civil penalties.
Environmental-related capital expenditures for the years 1997 and 1996 were
$1.4 million and $2.7 million, respectively. These expenditures are
forecasted to be approximately $2 million in each of the years 1998 and 1999.
The Company believes that its operating facilities are in substantial
compliance with currently applicable statutory and regulatory environmental
requirements. Additional expenditures could be required as changes in
environmental requirements occur.
Refer to the Environmental section of Item 7 for more information.
Number of Employees
As of March 21, 1998, the Company had 3,196 full-time and 33 part-time utility
employees including 2,166 represented by two locals of the Utility Workers
Union of America, AFL-CIO. The locals' labor contracts are effective through
May of the year 2000. Wholly owned subsidiary operations had 27 full-time
employees. Employee relations are considered satisfactory by the Company.
Refer to the Divestiture of Fossil Generating Assets section of Item 7 for
information regarding employees affected by the sale of these assets.
(d) Financial Information about Foreign and Domestic Operations and Export
- --------------------------------------------------------------------------
Sales
- -----
Refer to Principal Products and Services of this item for information
regarding the geographical area served by the Company and revenues by class
for the last three years.
<PAGE> 5
(e) Additional Information
- --------------------------
Regulation
The Company and its wholly owned subsidiary, Harbor Electric Energy Company
(HEEC), operate primarily under the authority of the DTE, whose jurisdiction
includes supervision over retail rates for electricity and financing and
investing activities. In addition, the FERC has jurisdiction over various
phases of the Company's business including rates for power sold at wholesale
for resale, facilities used for the transmission or sale of that power,
certain issuances of short-term debt and regulation of the system of accounts.
The Company's subsidiary BETG and its subsidiaries are not subject to such
regulation.
The NRC has broad jurisdiction over the siting, construction and operation of
nuclear reactors with respect to public health and safety, environmental
matters and antitrust considerations. A license granted by the NRC may be
revoked, suspended or modified for failure to construct or operate a facility
in accordance with its terms. The Company currently holds an operating
license for Pilgrim Station which expires in 2012. Continuing NRC review of
existing regulations and certain operating occurrences at other nuclear plants
have periodically resulted in the imposition of additional requirements for
all nuclear plants in the United States, including Pilgrim Station. NRC
inspections and investigations can result in the issuance of notices of
violation. These notices can also be accompanied by orders directing that
certain actions be taken or by the imposition of monetary civil penalties.
In addition, the Company could undertake certain actions regarding Pilgrim
Station at the request or suggestion of its insurers or the Institute of
Nuclear Power Operations, a voluntary association of nuclear utilities
dedicated to the promotion of safety and reliability in the operation of
nuclear power plants. Nuclear power continues to be a subject of political
controversy and public debate manifested from time to time in the form of
requests for various kinds of federal, state and local legislative or
regulatory action, direct voter initiatives or referenda or litigation. The
Company cannot predict the extent, cost or timing of any modifications to
Pilgrim Station which could be necessary in the future as a result of
additional regulatory or other requirements, nor can it determine the effect
of such future requirements on the continued operation of Pilgrim Station.
The Company continuously evaluates the operation of the station from the
standpoint of safety, reliability and economics.
<PAGE> 6
Capital Expenditures and Financings
The Company's most recent estimates of capital expenditures (excluding nuclear
fuel), allowance for funds used during construction (AFUDC), long-term debt
maturities and mandatory sinking fund requirements for the years 1998 through
2002 are as follows:
<TABLE>
<CAPTION>
(in thousands) 1998 1999 2000 2001 2002
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Capital
expenditures (1) $265,000 $230,000 $185,000 $140,000 $120,000
AFUDC $ 1,500 $ 1,500 $ 1,500 $ 1,500 $ 1,500
Long-term debt $101,600 $101,600 $166,600 $ 1,600 $ 1,600
Preferred stock
sinking fund (2) $ 2,000 $ 2,000 $ 2,000 $ 52,000 $ 2,000
==============================================================================
<FN>
(1) Includes nonutility ventures.
(2) Excludes option to redeem up to $2,000 of additional shares of 7.27%
series cumulative preferred stock each May; the Company will redeem
$4,000 of this series on May 1, 1998.
</TABLE>
The Company continuously reviews its capital expenditure and financing
programs. These programs and, therefore, the estimates included in this Form
10-K are subject to revision due to changes in regulatory requirements,
environmental standards, availability and cost of capital, interest rates and
other assumptions.
Utility plant expenditures in 1997 were $114 million and consisted primarily
of additions to the Company's transmission and distribution systems.
Refer to the Liquidity section of Item 7 for more information regarding the
Company's capital resources.
Item 2. Properties and Power Supply
- ------------------------------------
The Company's total electric generation capacity from Company-owned facilities
consisted of the following:
<TABLE>
<CAPTION>
Year
Unit Location Capacity(a) Type Installed
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Pilgrim Nuclear Plymouth, Mass. 670 Nuclear 1972
Power Station
New Boston Station South Boston, Mass. 760 Fossil 1965-1967
Units 1 and 2
Mystic Station Everett, Mass.
Units 4-5-6 388 Fossil 1957-1961
Unit 7 592 Fossil 1975
Combustion turbine 14 Fossil 1969
generator
Combustion turbine Various 276 Fossil 1966-1971
generators (nine)
==============================================================================
<FN>
(a) In megawatts (MW) based on winter capability audit results.
</TABLE>
<PAGE> 7
The Company also owns approximately 6% of W.F. Wyman Unit 4. The 619 MW oil-
fired unit located in Yarmouth, Maine, began operations in 1978 and is
operated by Central Maine Power Company. Additional electric generation
capacity is available to the Company through its contractual arrangements with
other utilities and nonutilities and its participation in the New England
Power Pool as further described in this item.
In December 1997, the Company entered into a purchase and sale agreement with
Sithe Energies, Inc., a privately-held company headquartered in New York, to
purchase its non-nuclear generating assets. Refer to Note C to the
Consolidated Financial Statements in Item 8 for more information regarding the
Company's fossil divestiture.
The Company's significant items of property consist of electric generating
stations, substations and service centers, and are generally located on
Company-owned land. The Company's high-tension transmission lines are
generally located on land either owned or subject to easements in its favor.
The Company's low-tension distribution lines and fossil fuel pipelines are
located principally on public property under permission granted by municipal
and other state authorities.
As of December 31, 1997, the Company's transmission system consisted of 362
miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and
156 miles of underground circuits operating at 115 and 345 kV. The
substations supported by these lines are 45 transmission or combined
transmission and distribution substations with transformer capacity of 10,281
megavolt amperes (MVA), 61 4 kV distribution substations with transformer
capacity of 1,017 MVA and 18 primary network units with 88 MVA capacity. In
addition, high tension service was delivered to 242 customers' substations.
The overhead and underground distribution systems cover approximately 4,700
and 900 miles of streets, respectively. HEEC, the Company's regulated
subsidiary, has a distribution system that consists principally of a 4.1 mile
115 kV submarine distribution line and a substation which is located on Deer
Island in Boston, Massachusetts. HEEC provides the ongoing support required
to distribute electric energy to its one customer, the Massachusetts Water
Resources Authority, at this location.
The Massachusetts Energy Facilities Siting Board (EFSB) must approve Company
plans for the construction of certain new generation or transmission
facilities based upon findings that such facilities are consistent with state
public health, environmental protection and resource use and development
policies. In December 1997, the Company received approval from the EFSB
regarding proposed transmission and station facilities in Hopkinton and
Milford, Massachusetts. This approval has been appealed to the Massachusetts
Supreme Judicial Court.
Purchased Power Contracts
Information regarding long-term contracts for the purchase of electricity is
included in Note M to the Consolidated Financial Statements in Item 8.
Under the Company's two long-term purchased power contracts with the
Massachusetts Bay Transportation Authority (MBTA), the MBTA retains the right
to utilize the combustion turbines for its own emergency use and for testing
purposes while the Company retains New England Power Pool credit for their
capacity and output.
<PAGE> 8
Sales Contracts
The Company has agreements with Commonwealth Electric Company and Montaup
Electric Company under which each purchase 11% of the capacity and
corresponding energy of Pilgrim Station and pay 11% of the unit's capital and
operating costs including an annual return on investment. The Company has
similar agreements with multiple municipal electric companies for a total of
3.7% of the capacity and corresponding energy of Pilgrim Station.
New England Power Pool
The Company is a member of the New England Power Pool (NEPOOL), a voluntary
association of electric utilities and other electricity suppliers in New
England responsible for the coordination, monitoring and directing of the
operations of the major generating and transmission facilities in the region.
To obtain maximum benefits of power pooling, the electric facilities of all
member companies are directed by an Independent System Operator (ISO - New
England) as if they were a single power system. This is accomplished through
the use of a central dispatching system that uses the lowest cost generation
and transmission equipment available at any given time. As a result of its
participation in NEPOOL, the Company's operating revenues and costs are
affected to some extent by the operations of the other members.
During 1997, the power pool was restructured with changes taking effect to the
membership and governance provisions of the power pooling agreement along with
the transferal of operating responsibility of the integrated transmission and
generation system in New England to the above referenced Independent System
Operator. Rules and procedures for bid-based markets for unbundled energy
services in lieu of the current cost-based pricing mechanism are under
development. A spot market for installed capability is scheduled to be in
effect on April 1, 1998 and the spot markets for other unbundled electric
products are anticipated to be ready in the fourth quarter of 1998.
The Company's net capacity was 3,397 MW at year end 1997 and 3,444 MW at its
summer peak. Its corresponding NEPOOL capacity obligations were estimated to
be 3,036 MW and 3,312 MW, respectively.
Item 3. Legal Proceedings
- --------------------------
Refer to Note L to the Consolidated Financial Statements in Item 8 for a
discussion of legal matters affecting the Company.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
There were no matters submitted to a vote of security holders during the
fourth quarter of 1997.
<PAGE> 9
Executive Officers of the Registrant
- ------------------------------------
The names, ages, positions and business experience during the past five years
of all the executive officers of Boston Edison Company and its subsidiaries as
of March 1, 1998 are listed below. There are no family relationships between
any of the officers of the Company, nor any arrangement or understanding
between any Company officer and another person pursuant to which the position
as officer is held. Officers of the Company hold office until the first
meeting of the directors following the next annual meeting of the stockholders
and until their respective successors are chosen and qualified.
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
Thomas J. May, 50 Chairman of the Board, President
Chairman of the Board, President and Chief Executive Officer (since
and Chief Executive Officer 1995), Chairman of the Board and
Chief Executive Officer (1994-
1995), President and Chief
Operating Officer (1993-1994) and
Executive Vice President (1993);
Director (since 1991)
Chairman of the Board, President
and Chief Executive Officer and
Director, Boston Energy Technology
Group, Inc.; Director, Harbor
Electric Energy Company, Boston
Edison Services, Inc., BecoCom,
Inc., Northwind Boston, LLC and
Coneco Corp.
Ronald A. Ledgett, 59 Executive Vice President (since
Executive Vice President 1997), Senior Vice President -
Fossil, Field Service and Electric
Delivery (1996-1997) and Senior
Vice President - Power Delivery
(1991-1995)
Alison Alden, 49 Senior Vice President - Sales,
Senior Vice President - Sales, Services and Human Resources
Services and Human Resources (since 1996) and Vice President -
Sales & Service (1993-1996)
L. Carl Gustin, 54 Senior Vice President - Corporate
Senior Vice President - Corporate Relations (since 1995) and Senior
Relations Vice President - Marketing &
Corporate Relations (1989-1995)
</TABLE>
<PAGE> 10
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
Douglas S. Horan, 48 Senior Vice President - Strategy
Senior Vice President - Strategy and Law and General Counsel
and Law and General Counsel (since 1995), Vice President and
General Counsel (1994-1995) and
Deputy General Counsel (1991-1994)
Senior Vice President, General
Counsel and Director, Harbor
Electric Energy Company; Senior
Vice President and Director,
BecoCom, Inc.; Director, Boston
Energy Technology Group, Inc.,
Boston Edison Services, Inc. and
Coneco Corp.
James J. Judge, 42 Senior Vice President - Corporate
Senior Vice President - Corporate Services and Treasurer (since
Services and Treasurer 1995), Assistant Treasurer (1989-
1995) and Director - Corporate
Planning (1993-1995)
Senior Vice President, Treasurer
and Director, Harbor Electric
Energy Company and Boston Energy
Technology Group, Inc.; Senior
Vice President and Director,
Boston Edison Services, Inc. and
BecoCom, Inc.; Director, Northwind
Boston, LLC, Coneco Corp. and
EnergyVision, LLC
Robert J. Weafer, Jr., 51 Vice President - Finance,
Vice President - Finance, Controller and Chief Accounting
Controller and Chief Officer (since 1991)
Accounting Officer
Assistant Treasurer, Harbor
Electric Energy Company, Boston
Energy Technology Group, Inc.,
Boston Edison Services, Inc. and
Coneco Corp.
Theodora S. Convisser, 50 Clerk of the Corporation (since
Clerk of the Corporation 1986) and Assistant General
Counsel (since 1984)
Clerk, Harbor Electric Energy
Company, Boston Energy Technology
Group, Inc., Boston Edison
Services, Inc., BecoCom, Inc.,
Northwind Boston, LLC, Coneco
Corp. and EnergyVision, LLC
</TABLE>
<PAGE> 11
Part II
-------
Item 5. Market for the Registrant's Common Stock and Related Stockholder
- -------------------------------------------------------------------------
Matters
- -------
(a) Market Information
- ----------------------
The Company's common stock is listed on the New York and Boston Stock
Exchanges.
The high and low market value per share of the Company's common stock as
reported in the Wall Street Journal for each of the quarters in 1997 and 1996
was as follows:
<TABLE>
<CAPTION>
1997 1996
- ------------------------------------------------------------------------------
High Low High Low
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First quarter $27 3/8 $26 $30 1/8 $26 1/4
Second quarter $26 5/8 $24 5/8 $27 1/8 $23 5/8
Third quarter $30 7/8 $26 1/2 $25 3/8 $21 3/4
Fourth quarter $38 3/8 $30 1/4 $27 $21 3/4
==============================================================================
</TABLE>
(b) Holders
- -----------
As of March 24, 1998, the Company had 32,200 holders of record of its common
stock.
(c) Dividends
- -------------
Dividends declared per share of common stock for each of the quarters in 1997
and 1996 were as follows:
<TABLE>
<CAPTION>
1997 1996
- -----------------------------------------------------------
<S> <C> <C>
First quarter $0.470 $0.470
Second quarter $0.470 $0.470
Third quarter $0.470 $0.470
Fourth quarter $0.470 $0.470
===========================================================
</TABLE>
(d) Other Information
- ---------------------
Ratio of earnings to fixed charges and ratio of earnings to fixed charges and
preferred stock dividend requirements for the year ended December 31, 1997:
<TABLE>
<S> <C>
Ratio of earnings to fixed charges 2.95
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.51
</TABLE>
<PAGE> 12
Item 6. Selected Financial Data
- --------------------------------
The following table summarizes five years of selected consolidated financial
data of the Company (in thousands, except per share data).
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating
revenues $1,776,233 $1,666,303 $1,628,503 $1,544,735 $1,482,159
Net income $ 144,642 $ 141,546 $ 112,310 $ 125,022 $ 118,218
Earnings per
share of
common
stock-basic
and
diluted $ 2.71 $ 2.61 $ 2.08(a) $ 2.41 $ 2.28
Total
assets $3,622,347 $3,729,291 $3,637,170 $3,608,699 $3,468,724
Long-term
debt $1,057,076 $1,058,644 $1,160,223 $1,136,617 $1,272,497
Redeemable
preferred
stock $ 163,093 $ 203,419 $ 206,514 $ 208,514 $ 210,514
Cash
dividends
declared
per common
share $ 1.880 $ 1.880 $ 1.835 $ 1.775 $ 1.715
=============================================================================
<FN>
(a) Includes $0.44 per share restructuring charge. Excluding the
restructuring charge, 1995 earnings per share were $2.52.
</TABLE>
<PAGE> 13
Item 7. Management's Discussion and Analysis
- ---------------------------------------------
Electric Utility Industry Restructuring
The traditionally rate-regulated electric utility industry is rapidly changing
in response to the continuing market pressures for lower-priced electric
energy. These pressures have resulted in regulatory and legislative
proceedings at both federal and state levels designed to foster competition in
the industry. On January 28, 1998, the Massachusetts Department of
Telecommunications and Energy (DTE), formerly the Department of Public
Utilities (DPU), approved our restructuring settlement agreement that was
filed in July 1997. The DTE found that the settlement agreement substantially
complied or was consistent with key provisions of a Massachusetts law enacted
in November 1997 establishing a comprehensive framework for the restructuring
of our industry. Major provisions of our settlement agreement include the
ability for retail electric customers to choose their electricity supplier
(referred to as retail access) as of March 1, 1998 (the retail access date).
Customers who choose not to participate in retail access will have the option
of continuing to buy power from our electric delivery business at "Standard
Offer" prices. Upon the retail access date, customers that continue to buy
electricity under the Standard Offer will realize an average 10% savings from
the rates in effect during 1997. Under the new legislation, Standard Offer
customers will realize another 5% savings in electricity rates, after an
adjustment for inflation, by September 1, 1999. We expect to be able to meet
this additional rate reduction as a result of the divestiture of our fossil
generating assets which is discussed below. As part of our settlement
agreement, the retail delivery rates of our retained distribution business
include a non-bypassable transition charge designed to recover certain costs
incurred by our generation business under the traditional electric ratemaking
structure which cannot be otherwise recovered in a competitive environment.
The rates of our distribution business will continue to be regulated by the
DTE based on the cost of providing distribution service.
In 1997 the Emerging Issues Task Force (EITF) reached consensus on specific
issues raised related to the application of Statement of Financial Accounting
Standards No. 71, Accounting for the Effects of Certain Types of Regulation
(SFAS 71). As part of its consensus, the EITF determined that when
deregulation legislation is passed and regulatory actions have taken place
providing sufficient detail for an enterprise to reasonably determine how the
transition plan will affect the separable portion of its business being
deregulated, the enterprise should stop applying SFAS 71 to that portion of
its business. As a result of the recently passed Massachusetts electric
industry restructuring legislation and the DTE order regarding our related
settlement agreement, we have determined that, as of December 31, 1997, the
provisions of SFAS 71 no longer apply to the generation portion of our
business. The EITF further determined that book values of assets and
liabilities originating in the separable portion of the business no longer
subject to rate-regulation should be evaluated on the basis of where the
regulated cash flows to realize and settle them will be derived. Net
generating assets recoverable from the proceeds of the fossil divestiture and
through the non-bypassable transition charge of our distribution business
which continues to be subject to rate-regulation, therefore, remain on our
consolidated balance sheet at December 31, 1997. In addition, approximately
25% of the operations and capital costs, including a return on investment, of
Pilgrim Nuclear Power Station will continue to be collected under wholesale
life of the unit contracts. These contracts continue to be regulated by the
Federal Energy Regulatory Commission (FERC) and are not impacted by our
settlement agreement.
<PAGE> 14
Divestiture of Fossil Generating Assets
Our restructuring settlement agreement includes a provision for the
divestiture of our fossil generating assets no later than six months after the
retail access date. On December 10, 1997, we entered into a purchase and sale
agreement with Sithe Energies, Inc., a privately-held company headquartered in
New York, to purchase our non-nuclear generating assets. The proceeds from
the sale of these assets will be $657 million. The net book value of these
assets at December 31, 1997 is approximately $450 million. Included in the
purchase price, Sithe Energies will pay $121 million to us in connection with
a six-month transitional power sales agreement under which we will buy power
from the generating plants. Sithe Energies will also be responsible for
obligations resulting from the recently enacted utility restructuring
legislation for property tax payments to communities with non-nuclear power
plants. Net proceeds from the divestiture will be used to reduce the
distribution transition charge.
Implementation of the divestiture plan is subject to certain regulatory
approvals including those of the DTE and the FERC. We anticipate finalization
of the divestiture in mid-1998.
In July 1997, we reached an agreement with our field service union that
requires the buyer of our fossil generating assets to recognize and continue
to honor the provisions of the union's current collective bargaining agreement
through the end of its term, May 2000. As part of a package offered to
employees affected by the fossil divestiture, all eligible fossil and
designated fossil support employees age 55 or older with at least 10 years of
service, or age 65 by July 1, 1998, were offered unreduced retirement and
transition benefits under a voluntary early retirement program (VERP). Under
this program, 40 people elected to retire. Retirement dates are expected to
be the first of the month following the transfer of ownership of our fossil
generating assets. Severance programs were offered to management and field
service union employees affected by the fossil divestiture that did not elect
or were ineligible to retire under the VERP. These severance benefits include
salary payments, education/retraining allowances and outplacement services.
It is anticipated that 48 employees will receive severance benefits under
these programs.
The estimated costs associated with the VERP and severance programs is
approximately $21 million including the effects on the retirement, life and
dental plans. Severance and employee retraining costs related to the
divestiture are recoverable through the distribution transition charge under
our settlement agreement. Therefore, we have established an offsetting
regulatory asset for these obligations on our consolidated balance sheet at
December 31, 1997.
Nuclear Asset Impairment
As part of the settlement agreement, we recover our net investment in Pilgrim
as of December 31, 1995 (adjusted for depreciation through 1997) through the
distribution transition charge. Under the terms of the settlement agreement,
we must perform a market valuation of Pilgrim by 2002. Upon acceptance of the
valuation by the DTE, the resulting dollar amount, net of prudently incurred
post-1995 investments in the plant, will reduce amounts collectible through
the transition charge. If the valuation is not sufficient to allow for the
recovery of these investments, we will seek their recovery through the
transition charge. Due to the market pressures facing us, the ultimate
recovery of these assets is not certain. Therefore, we reduced our investment
in Pilgrim by the $13 million invested in the plant since January 1, 1996 as
<PAGE> 15
an impairment loss. An after tax charge of approximately $8 million due to
this reduction was recorded to non-operating expense on our consolidated
statement of income in the fourth quarter of 1997. A similar uncertainty does
not exist for the ultimate recovery of the fossil generating assets as the
sale proceeds agreed to in the purchase and sale agreement with Sithe Energies
exceeds the net book value of these assets.
BEC Energy
We are currently awaiting a decision from the DTE regarding our reorganization
plan to form a holding company structure. A decision from the Securities and
Exchange Commission is also pending. Approval from the Nuclear Regulatory
Commission was received on February 11, 1998. This plan was approved by the
FERC and our shareholders in 1997. This new structure will clearly separate
our regulated and unregulated operations. It will provide us with greater
organizational flexibility allowing us to take advantage of nonutility
business opportunities in a more timely manner. The holding company structure
is a well-established form of organization for companies conducting multiple
lines of business. In fact, all other investor-owned Massachusetts electric
utilities are currently organized in this manner. Through our holding
company, BEC Energy, we will seek ways to expand our customer base.
Joint Ventures
We continue to conduct unregulated activities through our wholly owned
subsidiary, Boston Energy Technology Group (BETG). During 1997, BETG entered
into two joint venture agreements. BETG has a joint venture agreement with
RCN Telecom Services, Inc. (RCN). The final closing on this joint venture
occurred in June 1997. This limited liability company (LLC) competes directly
with local and long-distance telephone, video and Internet access companies
for telecommunications-related services. BETG owns 49% of the LLC while RCN
owns 51% and maintains day-to-day management responsibility. BETG also has an
energy marketing venture with Williams Energy Services Company (WESCO), a
subsidiary of The Williams Companies, Inc. This LLC, EnergyVision, markets
electricity, natural gas and energy-related services to retail customers in
the six New England states and began operations in February 1997. BETG and
WESCO each own 50% of EnergyVision.
Results of Operations
1997 versus 1996
Earnings per share of common stock were $2.71 in 1997 compared to $2.61 in
1996, a 3.8% increase as described below.
Operating revenues
Operating revenues increased 6.6% over 1996 as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $ 87,252
Demand side management revenues 1,232
Wholesale revenues (765)
Short-term sales and other revenues 22,211
- ------------------------------------------------------
Increase in operating revenues $109,930
======================================================
</TABLE>
Retail base revenues, consistent with the 0.8% increase in kilowatt-hour (kWh)
sales in 1997, were relatively flat compared to 1996. Increases due to warmer
than normal temperatures in June and July, cooler temperatures in October and
<PAGE> 16
December and the stronger local economy were offset by milder than normal
winter conditions during the first quarter of 1997 and lower industrial sales.
Industrial sales continue to be adversely affected by the decline in
manufacturing activity in our service territory. In addition, revenues in
1996 reflect one more day of sales due to the leap year. Total retail
electric revenues increased $87.3 million primarily due to the timing effect
of fuel and purchased power cost recovery. The increase in fuel and purchased
power clause revenues reflect the current recovery of prior year
undercollections. These higher revenues are offset by higher fuel and
purchased power expenses and, therefore, have no net effect on earnings.
Pilgrim performance revenues, which vary annually based on the operating
performance of Pilgrim Station, decreased due to a lower annual capacity
factor effective November 1996 reflecting the refueling and maintenance outage
in the first quarter of 1997.
Short-term sales revenues increased approximately $16 million. This is due to
the continued reduction in available nuclear energy supply in New England
combined with a 42% increase in our fossil generation allowing for increased
sales to the power exchange. Revenues from short-term sales result in a
corresponding reduction to future fuel and purchased power billings to retail
customers and, therefore, have no net effect on earnings.
Operating expenses
Fuel and purchased power expenses increased $90.2 million. This increase
reflects $57 million related to the timing effect of fuel and purchased power
cost recovery. In addition, company fuel expense increased $50 million
primarily due to the 42% increase in fossil generation. These increases were
partially offset by a $22 million decrease in power exchange purchases. Fuel
and purchased power expenses are substantially recoverable through fuel and
purchased power revenues.
Operations and maintenance expense decreased $2.6 million from 1996. The
decrease is the result of lower spending due to overall cost control efforts
and significantly less overhaul activity at our fossil generating units.
These decreases were partially offset by an approximately $5 million
incremental impact associated with service restoration efforts resulting from
a severe snow storm in April 1997 that struck the greater Boston area.
The increase in depreciation and amortization expense is due to the net impact
of two depreciation adjustments. We recorded an $8.7 million nonrecurring
charge to depreciation expense in the third quarter of 1997 to reflect the
removal of specific nuclear-related intangible assets from our balance sheet.
In 1996 we recorded a $5.2 million adjustment to correct the accumulated
depreciation balance of certain large computer equipment.
Income taxes increased as a result of higher net income offset by a lower
effective tax rate. The effective tax rate for 1997 reflects the impact of
the favorable outcome of an Internal Revenue Service (IRS) appeal received in
the third quarter related to investment tax credits (ITC). This also resulted
in an increase in unamortized ITC which will be reflected as a reduction to
income tax expense over the life of the related assets. Refer to Note D to
the Consolidated Financial Statements for more information on income taxes.
Other expense
Other expense, net in 1997 reflects the charge of approximately $8 million,
after tax, from the nuclear asset impairment which is further discussed in
Note C to the Consolidated Financial Statements in addition to BETG equity
<PAGE> 17
losses. These decreases were partially offset by approximately $3 million,
after tax, in interest income from the IRS appeal.
Interest charges
Total interest charges on long-term debt decreased due to the maturing of $100
million of 5.70% debentures in March 1997 and the cessation of amortization of
the associated redemption premiums. This was partially offset by the March
1997 issuance of $100 million of 6.662% bank debt due in 1999. The decrease
also reflects the maturity of $100 million of 5 1/8% debentures in March 1996.
Allowance for borrowed funds used during construction (AFUDC), which
represents the financing costs of construction, decreased primarily due to a
lower average construction work in progress (CWIP) balance in 1997. The 1996
average CWIP balance included nuclear fuel purchased in anticipation of
Pilgrim Station's scheduled refueling outage in the first quarter of 1997.
Preferred stock dividends
The decrease in preferred stock dividends is the result of the redemption of
20,000 of mandatory and 20,000 of optional shares of 7.27% series cumulative
preferred stock in May 1997 and 400,000 shares of 8.25% series in June 1997.
Refer to Note I to the Consolidated Financial Statements.
1996 versus 1995
Earnings per share of common stock were $2.61 in 1996 compared to $2.08 in
1995. Earnings in 1995 reflect a nonrecurring before tax charge of $34
million ($20.7 million after tax, or $0.44 per share) associated with our
corporate restructuring. The restructuring is discussed further in Note F to
the Consolidated Financial Statements. Excluding the nonrecurring
restructuring charge, earnings per common share increased 3.6% over 1995 as
described below.
Operating revenues
Operating revenues increased 2.3% over 1995 as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $48,649
Demand side management revenues (20,545)
Wholesale revenues (2,072)
Short-term sales and other revenues 11,768
- ------------------------------------------------------
Increase in operating revenues $37,800
======================================================
</TABLE>
Retail electric revenues increased $48.6 million. Fuel and purchased power
clause revenues increased approximately $36 million. These higher revenues
are offset by higher fuel and purchased power expenses and, therefore, have no
net effect on earnings. Performance revenues increased $14.5 million as
Pilgrim Station operated at a higher capacity in 1996. Retail kWh sales
increased 2.8% in 1996, primarily due to the positive economic impacts on our
commercial customers.
Demand side management (DSM) revenues decreased primarily due to a decline in
current DSM program expenditures.
The primary reason for the decrease in wholesale revenues is due to Pilgrim
contract customer revenues. These revenues decreased despite increased kWh
sales due to lower operations and maintenance expense related to Pilgrim
<PAGE> 18
Station. Pilgrim contract customers are billed for their proportionate share
of the unit's costs.
Net short-term sales and other revenues increased $11.8 million. Despite
lower kWh sales, short-term sales revenues increased approximately $6 million
due to higher fuel prices. Revenues from short-term sales result in a
corresponding reduction to future fuel and purchased power billings to retail
customers and, therefore, have no net effect on earnings. This increase also
reflects an increase in revenue from non-electric sources in 1996.
Operating expenses
Fuel and purchased power expenses increased $53.1 million. Fuel expense
increased, despite a slight decrease in company generation, due to
significantly higher oil and natural gas prices. Purchased power expense
reflects a higher volume of energy purchases and an overall increase in energy
prices. These increases were partially offset by the timing effect of fuel
and purchased power cost recovery. Fuel and purchased power expenses are
substantially recoverable through fuel and purchased power revenues.
Operations and maintenance expense decreased $40.8 million primarily due to
lower labor costs resulting from our 1995 restructuring and the continuing
cost control efforts of each of our business units. In addition, the
amortization of deferred nuclear outage costs decreased $9 million. As
discussed in Note B to the Consolidated Financial Statements, in the third
quarter of 1995 we made a retroactive change to the amortization period of
these deferred costs from five years to two years, consistent with the
two-year cycle between refueling outages at Pilgrim Station.
The 1995 operating expenses reflect a $34 million nonrecurring charge related
to our corporate restructuring. Refer to Note F to the Consolidated Financial
Statements for additional information regarding our 1995 restructuring.
Depreciation and amortization increased $32.2 million. The increase is
primarily the result of a change in the estimated remaining economic lives of
our Mystic 4, 5 and 6 fossil generating units in the second quarter of 1996,
retroactive to the beginning of the year, and an increase in the depreciable
plant balance. The change in estimated economic lives of Mystic 4, 5 and 6
resulted in a $22 million increase in depreciation expense for the year.
The decrease in DSM programs expense reflects the decline in current DSM
program expenditures.
The increase in income taxes is due to higher net income and a higher
effective tax rate in 1996. The effective tax rate in 1996 is 38.2% versus
37.1% in 1995.
Interest charges
Interest on long-term debt decreased due to the maturity of $100 million
8 7/8% debentures in December 1995 and $100 million 5 1/8% debentures in March
1996. These decreases were partially offset by the issuance of $125 million
7.80% debentures in May 1995 which were outstanding for all of 1996. Other
interest charges increased due to an increase in interest on short-term debt
caused by the higher average short-term debt level partially offset by a lower
average short-term borrowing rate. The short-term debt balance increased as a
result of the debenture maturities and the redemption of $4 million of
preferred stock in 1996. AFUDC decreased due to lower overall construction
<PAGE> 19
activity during 1996, shorter construction periods, and lower short-term
interest rates.
Electric Sales and Revenues
Electric sales
Retail kWh sales increased 0.8% in 1997. This was primarily attributable to
the commercial sector. The commercial increase reflects the impact of a
continued strong economy in the Boston area and very warm temperatures in June
and July and cooler than normal temperatures in the fourth quarter. Hotel
occupancy rates and non-manufacturing employment continued to increase in
1997. The commercial sector represents approximately 50% of our electric
operating revenues. Residential revenues, which represent 27% of electric
revenues, were also positively impacted by the weather. These positive
impacts were offset by milder winter weather in the first quarter of 1997 and
declines in manufacturing employment affecting the industrial sector. In
addition, revenues in 1996 reflect one more day of sales due to the leap year.
The industrial sector represents only 9% of our electric operating revenues.
Total kWh sales increased 3.1% as a result of the continued reduction in
available nuclear energy supply in New England. This reduction, combined with
an increase in our fossil generation allowed for increased sales to the power
exchange.
The 2.8% increase in 1996 retail kWh sales was primarily due to the positive
effect on commercial customers of the strong economy in our retail service
territory. Residential sales decreased slightly primarily due to overall
milder than normal weather conditions. Industrial sales remained relatively
flat. Total kWh sales, including wholesale, increased 3.3%. The increase in
wholesale sales was primarily due to higher sales to our Pilgrim contract
customers as the plant was operating for substantially all of 1996. In
addition, sales to our municipal customers increased due to a reduction in
available energy supply in New England.
Electric revenues
As discussed in the Electric Utility Industry Restructuring section, our
delivery business will provide Standard Offer customers service at rates
designed to give an average 10% savings upon the retail access date. As part
of the recently passed restructuring legislation in Massachusetts, these
customers are to realize an additional 5% average savings, after an adjustment
for inflation, by September 1, 1999. We expect to meet this additional rate
reduction as a result of the proceeds received from the divestiture of our
fossil generating assets and potential securitization or refinancing of our
stranded costs. Under our settlement agreement, the aggregate amount of our
transition charge is reduced by the net proceeds from fossil divestiture.
Under the settlement agreement, the annual performance adjustment charge
ceases and our cost recovery mechanism for Pilgrim Station changes as of the
retail access date. Approximately 25% of the operations and capital costs,
including a return on investment, will continue to be collected under
wholesale life of the unit contracts. The remaining output will be sold in
the competitive energy market. Through December 31, 2000, we will share 25%
of any profit or loss from the sale of Pilgrim's output with distribution
customers through the transition charge. In addition, we will obtain
transition payments up to a maximum of $23 million per year depending on the
level of costs incurred for property taxes, insurance, regulatory fees and
security requirements.
<PAGE> 20
Beginning upon the retail access date, the rates of our distribution business
will remain unchanged through December 31, 2000, subject to a minimum and
maximum return on average common equity (ROE). We will be required to file
with the DTE a computation supporting the ROE of our distribution business
after each calendar year. The ROE is subject to a floor of 6% and a ceiling
of 11.75%. If the ROE is below 6%, we are authorized to add a surcharge to
distribution rates in order to achieve the 6% floor. If the ROE is above 11%,
we are required to adjust distribution rates by an amount necessary to reduce
the calculated ROE between 11% and 12.5% by 50%, and a return above 12.5% by
100%. No adjustment is made if the ROE is between 6% and 11%. The cost of
providing transmission service to distribution customers will be recovered on
a fully reconciling basis.
Liquidity
We ordinarily meet most of our cash requirements for plant expenditures with
internally generated funds. These funds are cash flows from operating
activities, adjusted to exclude changes in working capital and the payment of
dividends. During 1997, 1996 and 1995 our internal generation of cash
provided 211%, 177% and 102%, respectively of our plant expenditures. The
capital spending level, excluding nuclear fuel, forecasted for 1998 is $265
million which includes amounts for utility plant and the capital requirements
of our nonutility ventures. This spending level also includes the 1998
portion of business system replacements discussed below. The capital spending
level over the next five years is forecasted to be approximately $940 million.
In addition to capital expenditures, we have debt and preferred stock payment
requirements of $103.6 million in 1998 and 1999, $168.6 million in 2000, $53.6
million in 2001 and $3.6 million in 2002.
We supplement our internally generated funds as needed, primarily through the
issuance of short-term commercial paper and bank borrowings. We have
authority from the FERC to issue up to $350 million of short-term debt. We
also have a $200 million revolving credit agreement and arrangements with
several banks to provide additional short-term credit on a committed as well
as on an uncommitted and as available basis. At December 31, 1997, we had
$137 million of short-term debt outstanding, none of which was incurred under
the revolving credit agreement. We have $220 million remaining under our
approved long-term financing plan with the DTE which is available through
1998. Proceeds from issuances under this plan are to be used to refinance
short and long-term securities and to fund capital expenditures. Refer to
Notes I and J to the Consolidated Financial Statements for additional
information relating to our financing activities.
At December 31, 1997, BETG had $7.5 million outstanding under a revolving
credit agreement. The purpose of this line is to fund its capital
requirements above our $45 million limited investment. This debt will be
refinanced upon the formation of BEC Energy.
We anticipate using the sale proceeds from our pending fossil divestiture to
adjust our capital structure.
Year 2000 Computer Issue
The year 2000 computer issue is the result of programs written using two
digits instead of four to define an applicable year. Consequently, these
programs will not properly recognize calendar dates beginning in the year
2000. This could cause computers to shut down or yield incorrect results.
<PAGE> 21
We have developed a plan to address the year 2000 issue that includes
modification of certain applications and replacement of systems that are not
year 2000 compliant. The cost associated with modification of existing
applications will be expensed as incurred. In addition, we have made a
decision to use this opportunity to upgrade some of our less efficient
centralized business systems. The full replacement costs associated with
these systems will be capitalized and amortized over future periods. The
total cost of the year 2000 project is expected to be funded through
internally generated funds. We anticipate completion of the year 2000 project
in the third quarter of 1999.
Other Matters
Environmental
We are subject to numerous federal, state and local standards with respect to
waste disposal, air and water quality and other environmental considerations.
These standards can require that we modify our existing facilities or incur
increased operating costs.
We currently own or operate approximately 30 properties where oil or hazardous
materials were previously spilled or released. We also continue to face
possible liability as a potentially responsible party in the cleanup of six
multi-party hazardous waste sites in Massachusetts and other states where we
are alleged to have generated, transported or disposed of hazardous waste at
the sites. Refer to Note L.6. to the Consolidated Financial Statements for
more information regarding hazardous waste issues.
The Accounting Standards Executive Committee of the American Institute of
Certified Public Accountants issued Statement of Position 96-1, Environmental
Remediation Liabilities (SOP 96-1), effective in 1997. This statement
contains authoritative guidance on specific accounting issues related to the
recognition, measurement, display and disclosure of environmental remediation
liabilities. It requires that an accrual for environmental liabilities
include estimates of the costs of compensation and benefits for those
employees expected to devote a significant amount of time directly to that
effort. SOP 96-1 had no material effect on our financial position or results
of operations during 1997.
Uncertainties continue to exist with respect to the disposal of both spent
nuclear fuel and low-level radioactive waste (LLW) resulting from the
operation of Pilgrim Station. The United States Department of Energy (DOE) is
responsible for the ultimate disposal of spent nuclear fuel; however,
uncertainties regarding the DOE's schedule of acceptance of spent fuel for
disposal continue to exist. In 1995 we regained access to the LLW disposal
facility located in Barnwell, South Carolina. Refer to Note E to the
Consolidated Financial Statements for further discussion regarding nuclear
decommissioning and waste disposal.
The 1990 Clean Air Act Amendments (CAAA) require a significant reduction in
nationwide emissions of sulfur dioxide from fossil generating units. Other
provisions of the CAAA involve limitations on emissions of nitrogen oxides
from existing generating units. As discussed in the Divestiture of Fossil
Generating Assets section, we have signed an agreement with Sithe Energies for
the sale of our fossil generating assets. If regulatory approval is not
obtained or is delayed, we could continue to operate these units subject to
the provisions of these amendments. We currently meet the standards of the
CAAA and, depending on the outcome of certain Massachusetts Department of
Environmental Protection air quality modeling studies, our generating units
<PAGE> 22
could continue to operate through at least 1999 before additional emission
reductions would be required.
Public concern continues regarding electromagnetic fields (EMF) associated
with electric transmission and distribution facilities and appliances and
wiring in buildings and homes. Such concerns have included the possibility of
adverse health effects caused by EMF as well as perceived effects on property
values. Some scientific reviews conducted to date have suggested associations
between EMF and potential health effects, while other studies have not
substantiated such associations. The National Research Council previously
reported that there is no conclusive evidence that exposure to EMF from power
lines and appliances presents a health hazard. The panel of scientists,
working with the National Academy of Sciences, report that more than 500
studies over the last several years have produced no proof that EMF causes
leukemia or other cancers or harms human health in other ways. We continue to
support research into the subject and are participating in the funding of
industry-sponsored studies. We are aware that public concern regarding EMF in
some cases has resulted in litigation, in opposition to existing or proposed
facilities in proceedings before regulators or in requests for legislation or
regulatory standards concerning EMF levels. We have addressed issues relative
to EMF in various legal and regulatory proceedings and in discussions with
customers and other concerned persons; however, to date we have not been
significantly affected by these developments. We continue to monitor all
aspects of the EMF issue.
Litigation
In October 1997, the DTE opened a proceeding to investigate our compliance
with the 1993 order which permitted the formation of BETG and authorized us to
invest up to $45 million in unregulated activities. We are unable to
determine the ultimate outcome of this proceeding or its impact on our
operations.
We were named as a party in lawsuits by Subaru of New England, Inc. and Subaru
Distributors Corporation. The plaintiffs claimed certain automobiles stored
on lots in South Boston suffered pitting damage caused by emissions from our
New Boston Station generating unit. In 1997 we settled both lawsuits.
Neither settlement had a material impact on our consolidated results of
operations or financial position.
Refer to Note L.8. to the Consolidated Financial Statements for more
information on other legal matters in which we are involved.
Industry restructuring legal proceedings/referendum campaign
The DTE order approving our settlement agreement has been appealed by certain
parties to the Massachusetts Supreme Judicial Court. In addition, along with
other Massachusetts investor-owned utilities, we have been named as a
defendant in a class action suit seeking to declare certain provisions of the
Massachusetts electric industry restructuring legislation unconstitutional.
We are currently unable to determine the outcome of these proceedings or their
impact on us.
Opponents of the electric industry restructuring legislation that was enacted
in November 1997 have mounted a referendum campaign to repeal that law. A
coalition of business, industry and public interest groups that supported the
legislation, along with the electric utility industry, is opposed to the
referendum and is prepared to mount an aggressive campaign to defeat it. We
<PAGE> 23
are currently unable to predict the eventual outcome of this referendum or its
impact on us.
Safe harbor cautionary statement
We occasionally make forward-looking statements such as forecasts and
projections of expected future performance or statements of our plans and
objectives. These forward-looking statements may be contained in filings with
the Securities and Exchange Commission, press releases and oral statements.
Actual results could potentially differ materially from these statements.
Therefore, no assurances can be given that the outcomes stated in such
forward-looking statements and estimates will be achieved.
The preceding sections include certain forward-looking statements about the
effects of the industry restructuring process and our related settlement
agreement, the divestiture of our fossil generating assets, operating results,
year 2000 and environmental and legal issues.
The effects of electric utility industry restructuring could differ from our
expectations. This could occur as regulatory decisions and negotiated
settlements between utilities and intervenors are finalized. In addition, the
development of a competitive electric generation market, the impacts of actual
electric supply and demand in New England and further legislative action may
affect the ultimate results of the industry restructuring and our settlement
agreement.
The divestiture plan could differ from our expectations. This could occur if
required regulatory approvals are delayed or not obtained.
The impacts of our continued cost control procedures on our operating results
could differ from our expectations. The effects of changes in economic
conditions, tax rates, interest rates, technology and the prices and
availability of operating supplies could materially affect our projected
operating results.
The timing and total costs related to our year 2000 plan could differ from our
expectations. Factors that may cause such differences include the ability to
locate and correct all relevant computer codes and the availability of
personnel trained in this area. In addition, we cannot predict the nature or
impact on operations of third party noncompliance.
The impacts of various environmental and legal issues could differ from our
expectations. New regulations or changes to existing regulations could impose
additional operating requirements or liabilities other than expected. The
effects of changes in specific hazardous waste site conditions and cleanup
technology could affect our estimated cleanup liabilities. The impacts of
changes in available information and circumstances regarding legal issues
could affect our estimated litigation costs.
<PAGE> 24
Item 8. Financial Statements and Supplementary Financial Information
- ---------------------------------------------------------------------
<TABLE>
Consolidated Statements of Income
<CAPTION>
years ended December 31,
(in thousands, except earnings per share) 1997 1996 1995
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $1,776,233 $1,666,303 $1,628,503
- ---------------------------------------------------------------------------
Operating expenses:
Fuel and purchased power 679,131 588,893 535,806
Operations and maintenance 414,779 417,372 458,196
Restructuring costs 0 0 34,000
Depreciation and amortization 188,687 185,494 153,339
Demand side management programs 29,790 30,825 45,125
Taxes-property and other 107,975 107,086 106,361
Income taxes 95,021 88,703 68,276
- ---------------------------------------------------------------------------
Total operating expenses 1,515,383 1,418,373 1,401,103
- ---------------------------------------------------------------------------
Operating income 260,850 247,930 227,400
Other income (expense), net (10,498) 698 (575)
- ---------------------------------------------------------------------------
Operating and other income 250,352 248,628 226,825
- ---------------------------------------------------------------------------
Interest charges:
Long-term debt 92,489 94,823 106,640
Other 14,410 14,551 12,642
Allowance for borrowed funds used
during construction (1,189) (2,292) (4,767)
- ---------------------------------------------------------------------------
Total interest charges 105,710 107,082 114,515
- ---------------------------------------------------------------------------
Net income 144,642 141,546 112,310
Preferred stock dividends 13,149 15,365 15,571
- ---------------------------------------------------------------------------
Earnings available for common
shareholders $ 131,493 $ 126,181 $ 96,739
===========================================================================
Weighted average common shares outstanding 48,515 48,265 46,592
Earnings per share of common stock-basic
and diluted $ 2.71 $ 2.61 $ 2.08
===========================================================================
</TABLE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
years ended December 31,
(in thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at the beginning of the year $ 292,191 $ 257,749 $ 247,409
Net income 144,642 141,546 112,310
- ---------------------------------------------------------------------------
Subtotal 436,833 399,295 359,719
- ---------------------------------------------------------------------------
Dividends declared:
Preferred stock 13,149 15,365 15,571
Common stock 91,208 90,834 86,399
- ---------------------------------------------------------------------------
Subtotal 104,357 106,199 101,970
- ---------------------------------------------------------------------------
Provision for preferred stock
redemption and issuance costs (a) 3,674 905 0
- ---------------------------------------------------------------------------
Balance at the end of the year $ 328,802 $ 292,191 $ 257,749
===========================================================================
<FN>
(a) Refer to Note B.7. to the Consolidated Financial Statements.
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 25
<TABLE>
Consolidated Balance Sheets
<CAPTION>
December 31,
(in thousands) 1997 1996
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Assets
Utility plant in service, at
original cost $4,457,868 $4,387,887
Less: accumulated depreciation 1,713,079 $2,744,789 1,550,317 $2,837,570
- ------------------------------------------------------------------------------
Nuclear fuel 351,722 351,453
Less: accumulated amortization 283,787 67,935 268,509 82,944
- ------------------------------------------------------------------------------
Construction work in progress 41,403 30,376
- ------------------------------------------------------------------------------
Net utility plant 2,854,127 2,950,890
Nuclear decommissioning trust 151,634 132,076
Equity investments 35,455 28,752
Other investments 7,107 7,630
Current assets:
Cash and cash equivalents 4,140 5,651
Accounts receivable 192,220 233,024
Accrued unbilled revenues 30,048 34,922
Fuel, materials and supplies,
at average cost 60,834 57,075
Prepaids and other 31,283 318,525 45,146 375,818
- ------------------------------------------------------------------------------
Deferred debits:
Regulatory assets 220,403 202,026
Other 35,096 32,099
- ------------------------------------------------------------------------------
Total assets $3,622,347 $3,729,291
==============================================================================
Capitalization and Liabilities
Common stock equity $1,073,454 $1,036,424
Cumulative preferred stock 161,093 201,419
Long-term debt 1,057,076 1,058,644
Current liabilities:
Long-term debt/preferred
stock due within one year $ 102,667 $ 102,667
Notes payable 137,013 201,454
Accounts payable 87,015 134,083
Accrued interest 24,289 24,378
Dividends payable 24,748 25,343
Other 128,061 503,793 115,812 603,737
- ------------------------------------------------------------------------------
Deferred credits:
Accumulated deferred income taxes 485,738 498,718
Accumulated deferred investment
tax credits 60,736 58,899
Nuclear decommissioning liability 155,182 133,388
Power contracts 71,445 88,963
Other 53,830 49,099
Commitments and contingencies
- ------------------------------------------------------------------------------
Total capitalization and liabilities $3,622,347 $3,729,291
==============================================================================
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 26
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating activities:
Net income $144,642 $141,546 $112,310
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 223,529 228,259 202,294
Deferred income taxes and investment tax
credits (21,664) (4,057) (25,193)
Allowance for borrowed funds used during
construction (1,189) (2,292) (4,767)
Net changes in:
Accounts receivable and accrued
unbilled revenues 45,678 (11,719) (34,626)
Fuel, materials and supplies (5,486) (2,171) 7,202
Accounts payable (47,068) 609 2,978
Other current assets and liabilities 25,428 (44,514) 26,485
Other, net (4,640) 50,815 26,993
- -----------------------------------------------------------------------------
Net cash provided by operating activities 359,230 356,476 313,676
- -----------------------------------------------------------------------------
Investing activities:
Plant expenditures (excluding AFUDC) (114,110) (145,347) (180,822)
Nuclear fuel expenditures (4,089) (52,967) (13,621)
Investments in joint ventures (7,859) (5,698) 0
Other investments (19,830) (28,616) (19,005)
- -----------------------------------------------------------------------------
Net cash used in investing activities (145,888) (232,628) (213,448)
- -----------------------------------------------------------------------------
Financing activities:
Issuances:
Common stock 144 12,559 64,888
Long-term debt 100,000 0 125,000
Redemptions:
Preferred stock (44,000) (4,000) (2,000)
Long-term debt (101,600) (101,600) (100,600)
Net change in notes payable (64,441) 75,013 (88,345)
Dividends paid (104,956) (106,010) (100,152)
- -----------------------------------------------------------------------------
Net cash used in financing activities (214,853) (124,038) (101,209)
- -----------------------------------------------------------------------------
Net decrease in cash and cash equivalents (1,511) (190) (981)
Cash and cash equivalents at the
beginning of the year 5,651 5,841 6,822
- -----------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $ 4,140 $ 5,651 $ 5,841
=============================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized $100,795 $100,810 $104,011
Income taxes $ 99,326 $ 98,668 $ 96,180
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 27
Notes to Consolidated Financial Statements
Note A. Nature of Operations
Boston Edison Company (the Company) is an investor-owned regulated public
utility operating in the energy, energy services and telecommunications
business. This includes the generation, purchase, transmission, distribution
and sale of electric energy and the development and implementation of electric
demand side management programs. A portion of our generation is produced by
our wholly owned nuclear generating unit, Pilgrim Nuclear Power Station. We
supply electricity at retail to an area of 590 square miles, including the
city of Boston and 39 surrounding cities and towns. We also supply
electricity at wholesale for resale to other utilities and municipal electric
departments. Electric operating revenues were 88% retail and 12% wholesale in
1997. We also conduct unregulated activities through our wholly owned
subsidiary, Boston Energy Technology Group (BETG).
Through BETG and its subsidiaries, we are engaged in certain nonutility
businesses, including energy utilization and conservation, construction
management and district energy. BETG has a joint venture with RCN Telecom
Services, Inc. (RCN) that provides certain telecommunications-related
services. The limited liability company (LLC) formed from this joint venture
is owned 51% by RCN and 49% by BETG, with RCN having the day-to-day management
responsibility. BETG also has a joint venture with Williams Energy Services
Company (WESCO). This joint venture markets electricity, natural gas and
energy-related services to retail customers in the six New England states.
BETG and WESCO each own 50% of this LLC, EnergyVision.
We are currently awaiting a decision from the Massachusetts Department of
Telecommunications and Energy (DTE), formerly the Department of Public
Utilities, regarding our plan to form a holding company structure. This
structure will clearly separate our regulated and unregulated lines of
business. Through our holding company, BEC Energy, we will seek ways to
expand our customer base. After the corporate reorganization, Boston Edison
will be a wholly owned subsidiary of BEC Energy. BETG will cease being a
subsidiary of Boston Edison and become a wholly owned subsidiary of BEC
Energy. The common shareholders of Boston Edison will become shareholders of
BEC Energy. The existing debt and preferred stock of Boston Edison will
remain obligations of the regulated utility business.
Refer also to Note C to these Consolidated Financial Statements for changes in
the nature of our operations as a result of the electric utility industry
restructuring and our related settlement agreement.
Note B. Significant Accounting Policies
1. Basis of Consolidation and Accounting
The consolidated financial statements include the activities of our wholly
owned subsidiaries, Harbor Electric Energy Company (HEEC) and BETG. All
significant intercompany transactions have been eliminated. Certain
reclassifications have been made to the prior year data to conform with the
current presentation.
We follow accounting policies prescribed by the Federal Energy Regulatory
Commission (FERC) and the DTE. We are also subject to the accounting and
reporting requirements of the Securities and Exchange Commission. The
consolidated financial statements conform with generally accepted accounting
principles (GAAP). As a rate-regulated company we have been subject to
<PAGE> 28
Statement of Financial Accounting Standards No. 71, Accounting for the Effects
of Certain Types of Regulation (SFAS 71), under GAAP. The application of SFAS
71 results in differences in the timing of recognition of certain expenses
from that of other businesses and industries. As a result of the recently
passed Massachusetts electric industry restructuring legislation and the DTE
order regarding our related settlement agreement, as of December 31, 1997, we
are no longer applying the provisions of SFAS 71 to our generation business.
Our distribution business remains subject to rate-regulation and continues to
meet the criteria for application of SFAS 71. Refer to Note C to these
Consolidated Financial Statements for more information on the accounting
implications of the electric utility industry restructuring.
The preparation of financial statements in conformity with GAAP requires us to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these
estimates.
2. Revenues
We record estimates of retail base revenues for electricity used by our
customers but not yet billed at the end of each accounting period.
3. Forecasted Fuel and Purchased Power Rates
The rate charged to retail customers for fuel and purchased power allows for
fuel and purchased power costs which are not included in our base rates to be
billed to customers using a forecasted rate. The difference between actual
costs and the amounts billed to customers is recorded as an adjustment to fuel
and purchased power expenses and is included in accounts receivable on the
consolidated balance sheet until subsequent rates are adjusted.
4. Utility Plant
Utility plant is stated at original cost of construction. The costs of
replacements of property units are capitalized. Maintenance and repairs and
replacements of minor items are expensed as incurred. The original cost of
property retired, net of salvage value, and the related costs of removal are
charged to accumulated depreciation.
5. Depreciation and Nuclear Fuel Amortization
Depreciation of our utility plant is computed on a straight-line basis using
composite rates based on the estimated useful lives of the various classes of
property. Excluding the effect of the adjustment discussed below, the overall
composite depreciation rates were 3.30%, 3.33% and 3.28% in 1997, 1996 and
1995, respectively.
Upon the completion of a review of our electric generating units, we
determined that our oldest and least efficient fossil units (Mystic 4, 5 and
6) were unlikely to provide competitively-priced power beyond the year 2000.
Therefore we revised the estimated remaining economic lives of these units to
five years in 1996.
The cost of decommissioning Pilgrim Station is excluded from our depreciation
rates. Refer to Note E to these Consolidated Financial Statements for a
discussion of nuclear decommissioning. The cost of nuclear fuel is amortized
based on the amount of energy Pilgrim Station produces. Nuclear fuel expense
<PAGE> 29
also includes an amount for the estimated costs of ultimately disposing of
spent nuclear fuel and for assessments for the decontamination and
decommissioning of United States Department of Energy nuclear enrichment
facilities. These costs are recovered from our customers through fuel rates.
6. Deferred Nuclear Outage Costs
We defer the incremental costs associated with nuclear refueling outages when
incurred and amortize them over Pilgrim Station's operating cycle. In 1995 we
changed the amortization period from five years to two years. The two-year
amortization period is consistent with the two-year cycle between nuclear
refueling outages at Pilgrim Station.
7. Costs Associated with Issuance and Redemption of Debt and Preferred Stock
Consistent with our recovery in electric rates, we defer discounts, redemption
premiums and related costs associated with the redemption and issuance of
long-term debt and preferred stock. The costs related to long-term debt are
recognized as an addition to interest expense over the life of the original or
replacement debt. Beginning in 1996, consistent with an accounting order
received from the FERC, we reflect costs related to preferred stock
redemptions and issuances as a direct reduction to retained earnings upon
redemption or over the average life of the replacement preferred stock series
as applicable.
8. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction.
In accordance with regulatory accounting, AFUDC is included as a cost of
utility plant and a reduction of current interest charges. Although AFUDC is
not a current source of cash income, the costs are recovered from customers
over the service life of the related plant in the form of increased revenues
collected as a result of higher depreciation expense. Our AFUDC rates in
1997, 1996 and 1995 were 6.04%, 5.87% and 6.35%, respectively, and represented
only the cost of short-term debt.
9. Cash and Cash Equivalents
Cash and cash equivalents are comprised of highly liquid securities with
maturities of 90 days or less when purchased. Outstanding checks are included
in cash and accounts payable until they are presented for payment.
10. Allowance for Doubtful Accounts
Our accounts receivable are substantially recoverable. This recovery occurs
both from customer payments and from the portion of customer charges that
provides for the recovery of bad debt expense. Accordingly, we do not
maintain a significant allowance for doubtful accounts balance.
11. Regulatory Assets
Regulatory assets represent costs incurred which are expected to be collected
from customers through future charges in accordance with agreements with our
regulators. These costs are expensed when the corresponding revenues are
received in order to appropriately match revenues and expenses. The majority
of these costs is currently being recovered from customers over varying time
periods. Refer to Note C to these Consolidated Financial Statements for
information regarding the recovery of regulatory assets related to our
generation business.
<PAGE> 30
Regulatory assets consisted of the following:
<TABLE>
<CAPTION>
December 31,
1997 1996
- --------------------------------------------------------------------
<S> <C> <C>
Fossil divestiture $ 21,248 $ 0
Power contracts 71,445 88,963
Income taxes, net 51,096 47,483
Redemption premiums 27,019 31,052
Postretirement benefits costs 22,441 15,009
Decontamination and decommissioning 12,282 13,190
Nuclear outage costs 10,160 3,432
Other 4,712 2,897
- --------------------------------------------------------------------
$220,403 $202,026
====================================================================
</TABLE>
12. Earnings Per Share of Common Stock
Basic earnings per share (EPS) of common stock is calculated by dividing net
income, after the payment of preferred stock dividends, by the weighted
average common shares outstanding during the year. Statement of Financial
Accounting Standards No. 128, Earnings per Share, requires the disclosure of
diluted EPS effective for periods ending after December 15, 1997. Diluted EPS
is similar to the computation of basic EPS except that the weighted average
common shares is increased to include the number of dilutive potential common
shares. Diluted EPS, which includes the effect of deferred (nonvested) shares
and stock options granted under the Stock Incentive Plan in the calculation of
weighted average common shares, is the same as basic EPS displayed on the
consolidated statement of income.
Note C. Electric Utility Industry Restructuring
1. Accounting Implications
Under the traditional revenue requirements model, our electric rates have been
based on the cost of providing electric service. As such, we have been
subject to certain accounting standards that are not applicable to other
businesses and industries in general. The application of SFAS 71 requires us
to defer the recognition of certain costs when incurred if future rate
recovery of these costs is expected. Based on a consensus reached by the
Emerging Issues Task Force (EITF) regarding specific issues raised related to
the application of SFAS 71, we have determined that, as of December 31, 1997,
the provisions of SFAS 71 no longer apply to the generation portion of our
business. In its consensus, the EITF determined that when deregulation
legislation is passed and regulatory actions have taken place providing
sufficient detail for an enterprise to reasonably determine how the transition
plan will affect the separable portion of its business being deregulated, the
enterprise should stop applying SFAS 71 to that portion of its business. On
January 28, 1998, the DTE approved our restructuring settlement agreement that
was filed in July 1997. The DTE found that the settlement agreement
substantially complied or was consistent with key provisions of a
Massachusetts law enacted in November 1997 establishing a comprehensive
framework for the restructuring of our industry. The EITF further determined
that book values of assets and liabilities originating in the separable
portion of the business no longer subject to rate-regulation should be
evaluated on the basis of where the regulated cash flows to realize and settle
them will be derived. Net utility plant and other related assets on our
consolidated balance sheet as of December 31, 1997 include approximately $700
million related to nuclear generation and approximately $450 million related
to fossil generation. As part of our settlement agreement, approximately 75%
of these nuclear assets are fully recoverable through the non-bypassable
<PAGE> 31
transition charge of our distribution business which continues to be subject
to rate-regulation. The remaining 25% will be collected under Pilgrim's
wholesale life of the unit contracts. These contracts continue to be
regulated by the FERC and are not impacted by our settlement agreement. These
fossil assets will be recovered from the proceeds from their sale as discussed
in part 2 below.
The implementation of our approved settlement agreement has certain accounting
implications. The highlights of these include:
Depreciation
The composite depreciation rate for distribution utility plant increases from
2.38% to 2.98% as of March 1, 1998 (the retail access date).
Generation related plant and regulatory assets
Plant and regulatory assets related to our generation business, except for
those related to Pilgrim's wholesale life of the unit contracts, will be
recovered through the transition charge. This recovery, which includes a
return, will occur over a twelve-year period.
Storm fund
Under the settlement agreement, we are authorized to establish a storm
contingency fund to use for the incremental costs of any major storm (in
excess of $1 million). The settlement required that we initially establish
the fund with $8 million of proceeds received from the sale of Clean Air Act
emission allowances. As costs are charged against the fund, the balance will
be restored to the original level from distribution charges up to a maximum of
$3 million per year.
Fuel and purchased power charge
The fuel and purchased power charge ceases as of the retail access date. Net
remaining over or under collection of fuel and purchased power costs will be
reflected in future customer billings.
Standard offer charge
Customers will have the option of continuing to buy power from our electric
delivery business at "Standard Offer" prices as of the retail access date.
The Standard Offer charge begins at 2.8 cents at retail access and increases
to 5.1 cents by 2004. The cost of providing Standard Offer service, which
includes fuel and purchased power costs, will be recovered from Standard Offer
customers on a fully reconciling basis.
Distribution and transmission charges
Distribution rates will be subject to a minimum and maximum return on average
common equity (ROE) through December 31, 2000. The ROE is subject to a floor
of 6% and a ceiling of 11.75%. If the ROE is below 6%, we are authorized to
add a surcharge to distribution rates in order to achieve the 6% floor. If
the ROE is above 11%, we are required to adjust distribution rates by an
amount necessary to reduce the calculated ROE between 11% and 12.5% by 50%,
and a return above 12.5% by 100%. No adjustment is made if the ROE is between
6% and 11%. In addition, distribution rates will be adjusted for any changes
in tax laws or accounting principles that result in a change in our costs of
<PAGE> 32
more than $1 million. The cost of providing transmission service to
distribution customers will be recovered on a fully reconciling basis.
Nuclear generation
Under the settlement agreement, the annual performance adjustment charge
ceases and our cost recovery mechanism for Pilgrim Station changes as of the
retail access date. Approximately 25% of the operations and capital costs,
including a return on investment, will continue to be collected under
wholesale life of the unit contracts. The remaining output will be sold in
the competitive energy market. Through December 31, 2000, we will share 25%
of any profit or loss from the sale of Pilgrim's output with distribution
customers through the transition charge. In addition, we will obtain
transition payments up to a maximum of $23 million per year depending on the
level of costs incurred for property taxes, insurance, regulatory fees and
security requirements.
Nuclear decommissioning
Approximately 25% of Pilgrim's decommissioning costs will continue to be
collected under wholesale life of the unit contracts. The remaining portion
will be recovered through the transition charge. Amounts collected for
decommissioning will be adjusted as decommissioning cost studies are updated.
Refer to Note E to these Consolidated Financial Statements for more
information on nuclear decommissioning costs.
2. Divestiture of Fossil Generating Assets
Included in our settlement agreement is a provision for the divestiture of our
fossil generating assets. On December 10, 1997, we entered into a purchase
and sale agreement with Sithe Energies, Inc., a privately-held company
headquartered in New York, to purchase our non-nuclear generating assets. The
proceeds from the sale of these assets will be $657 million. The net book
value of these assets at December 31, 1997 is approximately $450 million.
Included in the purchase price, Sithe Energies will pay $121 million to us in
connection with a six-month transitional power sales agreement under which we
will continue to buy power from the generating plants. Sithe Energies will
also be responsible for obligations resulting from the recently enacted
utility restructuring legislation for property tax payments to communities
with non-nuclear power plants.
In July 1997, we reached an agreement with our field service union that
requires the buyer of our fossil generating assets to recognize and continue
to honor the provisions of the union's current collective bargaining agreement
through the end of its term, May 2000. As part of a package offered to
employees affected by the fossil divestiture, all eligible fossil and
designated fossil support employees age 55 or older with at least 10 years of
service, or age 65 by July 1, 1998, were offered unreduced retirement and
transition benefits under a voluntary early retirement program (VERP). Under
this program, 40 people elected to retire. Retirement dates are expected to
be the first of the month following the transfer of ownership of our fossil
generating assets. Severance programs were offered to management and field
service union employees affected by the fossil divestiture that did not elect
or were ineligible to retire under the VERP. These severance benefits include
salary payments, education/retraining allowances and outplacement services.
It is anticipated that 48 employees will receive severance benefits under
these programs.
<PAGE> 33
The estimated costs associated with the VERP and severance programs is
approximately $21 million including the effects on the retirement, life and
dental plans. Severance and employee retraining costs related to the
divestiture are recoverable through the distribution transition charge under
our settlement agreement. Therefore, we have established an offsetting
regulatory asset for these obligations on our consolidated balance sheet at
December 31, 1997.
3. Nuclear Asset Impairment
As part of the settlement agreement, we recover our net investment in Pilgrim
Station as of December 31, 1995 (adjusted for depreciation through 1997)
through the distribution transition charge. Under the terms of the settlement
agreement, we must perform a market valuation of Pilgrim by 2002. Upon
acceptance of the valuation by the DTE, the resulting dollar amount, net of
prudently incurred post-1995 investments in the plant, will reduce amounts
collectible through the transition charge. If the valuation is not sufficient
to allow for the recovery of these investments, we will seek their recovery
through the transition charge. Due to the market pressures facing us, the
ultimate recovery of these assets is not certain. Therefore, we reduced our
investment in Pilgrim by the $13 million invested in the plant since
January 1, 1996 as an impairment loss under Statement of Financial Accounting
Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of (SFAS 121). An after tax charge of
approximately $8 million due to this reduction was recorded to non-operating
expense on our consolidated statement of income in the fourth quarter of 1997.
A similar uncertainty does not exist for the ultimate recovery of the fossil
generating assets as the sale proceeds agreed to in the purchase and sale
agreement with Sithe Energies exceeds the net book value of these assets.
Note D. Income Taxes
Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS
109 requires the recognition of deferred tax assets and liabilities for the
future tax effects of temporary differences between the carrying amounts and
the tax basis of assets and liabilities. In accordance with SFAS 109 we
recorded net regulatory assets of $51.1 million and $47.5 million and
corresponding net increases in accumulated deferred income taxes as of
December 31, 1997, and December 31, 1996, respectively. The regulatory assets
represent the additional future revenues to be collected from customers for
deferred income taxes.
Accumulated deferred income taxes consisted of the following:
<TABLE>
<CAPTION>
December 31,
(in thousands) 1997 1996
- ------------------------------------------------------------------------------
<S> <C> <C>
Deferred tax liabilities:
Plant-related $535,460 $532,390
Other 79,930 95,642
- ------------------------------------------------------------------------------
615,390 628,032
- ------------------------------------------------------------------------------
Deferred tax assets:
Plant-related 11,926 8,406
Investment tax credits 33,125 38,005
Other 84,601 82,903
- ------------------------------------------------------------------------------
129,652 129,314
- ------------------------------------------------------------------------------
Net accumulated deferred income taxes $485,738 $498,718
==============================================================================
</TABLE>
<PAGE> 34
No valuation allowances for deferred tax assets are deemed necessary.
Previously deferred investment tax credits are amortized over the estimated
lives of the property giving rise to the credits.
Components of income tax expense were as follows:
<TABLE>
<CAPTION>
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current income tax expense $116,685 $92,760 $93,469
Deferred income tax expense (14,104) 14 (21,115)
Investment tax credit amortization (7,560) (4,071) (4,078)
- -----------------------------------------------------------------------------
Income taxes charged to operations 95,021 88,703 68,276
- -----------------------------------------------------------------------------
Taxes on other income:
Current (12,566) (721) (1,729)
- -----------------------------------------------------------------------------
Total income tax expense $ 82,455 $87,982 $66,547
=============================================================================
</TABLE>
The effective income tax rates reflected in the consolidated financial
statements and the reasons for their differences from the statutory federal
income tax rate were as follows:
<TABLE>
<CAPTION>
1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 4.5 4.3 4.3
Investment tax credit amortization (3.3) (1.8) (2.3)
Other 0.1 0.7 0.1
- -----------------------------------------------------------------------------
Effective tax rate 36.3% 38.2% 37.1%
=============================================================================
</TABLE>
The 1997 effective tax rate declined by 0.8% as a result of the favorable
outcome of an Internal Revenue Service appeal related to investment tax
credits.
Note E. Nuclear Decommissioning and Nuclear Waste Disposal
1. Nuclear Decommissioning
When Pilgrim Station's operating license expires in 2012 we will be required
to decommission the plant. Decommissioning means to remove nuclear facilities
from service safely and reduce residual radioactivity to a level that permits
termination of the Nuclear Regulatory Commission (NRC) license and release of
the property for unrestricted use. We record an estimate of decommissioning
costs in depreciation expense on the consolidated statements of income over
Pilgrim's expected service life. Decommissioning expense is approximately $14
million per year. The estimate used to determine our annual expense is based
on a 1991 study that documents a cost of approximately $328 million to
decommission the plant using the "green field" method, which provides for the
plant site to be completely restored to its original state. The cost estimate
was incorporated in our 1992 retail settlement agreement. We receive recovery
of the annual expense through charges to our retail customers and from other
utility companies and municipalities which purchase a contracted amount of
Pilgrim's electric generation. The funds we collect from decommissioning
charges are deposited in an external trust and are restricted to use for
decommissioning and related expenses. The net earnings on the trust funds,
which are also restricted, increase the nuclear decommissioning trust balance,
thus reducing the amount to be collected from customers.
The 1991 decommissioning study was partially updated for internal planning
purposes in order to evaluate the potential impact of long-term spent fuel
storage options resulting from delays in the United States Department of
<PAGE> 35
Energy (DOE) spent fuel removal program. Refer to part 2 for a discussion of
spent fuel removal. The partial update indicated an estimated decommissioning
cost of $400 million in 1991 dollars based upon a revised spent fuel removal
schedule and utilization of dry spent fuel storage technology. We are in the
process of updating this study. No final cost estimate is currently
available; however, we continue to monitor DOE spent fuel removal schedules
and developments in spent fuel storage technology along with their impact on
the decommissioning estimate.
Certain financial reporting considerations related to nuclear decommissioning
costs have not been fully resolved. In 1996 the Financial Accounting
Standards Board (FASB) issued proposed new rules for accounting for
liabilities related to closure and removal of long-lived assets, which include
decommissioning of nuclear generating facilities. If these proposed rules are
adopted we would be required to retroactively recognize the entire estimated
liability for decommissioning costs on the balance sheet, offset by an
addition to utility plant. The plant addition would be depreciated over
Pilgrim's remaining expected service life. The liability would be measured
based on the present value of estimated future cash flows. The cumulative
effect of adoption of these proposed rules could result in the recognition of
a regulatory asset to be recovered from customers to the extent that the
present value difference in the liability between when the liability was
incurred and when the rules are adopted exceeds the depreciation expense
previously recognized for decommissioning. In addition, trust fund earnings
would be reported on the income statement. The FASB recently resumed its
deliberations on this project. No date has been set for the issuance of
either a final statement or revised proposed rules.
2. Spent Nuclear Fuel
The spent fuel storage facility at Pilgrim Station is expected to provide
storage capacity through approximately 2003. We have a license amendment from
the NRC to modify the facility to provide sufficient room for spent nuclear
fuel generated through the end of Pilgrim's operating license in 2012;
however, any further modifications are subject to review by the DTE. We are
actively exploring the feasibility of other spent fuel storage facilities and
technologies.
Delays in identifying a permanent storage site have continually postponed
plans for the DOE's long-term storage and disposal site for spent nuclear
fuel. The DOE's current estimate for an available site is 2010. In November
1997, the U.S. Court of Appeals for the District of Columbia Circuit ruled
that the lack of an interim storage facility does not excuse the DOE from
meeting its contract obligation to begin accepting spent nuclear fuel no later
than January 31, 1998. This decision was in response to petitions filed by us
and other interested parties seeking declaratory rulings concerning
enforcement and remedies for the DOE's failure to accept spent fuel in a
timely manner. The court directed the plaintiffs to pursue relief under terms
of their contracts with the DOE. Based on this ruling, the DOE may have to
pay contract damages if it does not take the spent nuclear fuel as scheduled.
Under the Nuclear Waste Policy Act of 1982, it is the ultimate responsibility
of the DOE to permanently dispose of spent nuclear fuel. We currently pay a
fee of $1.00 per net megawatthour sold from Pilgrim Station generation under a
nuclear fuel disposal contract with the DOE. The fee is collected from
customers through fuel charges. We cannot predict at this time whether or on
what schedule the DOE will eventually construct a spent fuel repository or
what the effect will be of any delays in such construction.
<PAGE> 36
The DOE recently denied our petition to suspend payments made to the Nuclear
Waste Fund based on its interpretation of the U.S. Court of Appeal's decision
made in November 1997. The DOE has, however, made an offer to consider
amendments to existing contracts to address the hardships the anticipated
delay in accepting spent fuel may cause individual contract holders. We
continue to monitor this situation and consult with legal counsel as to our
next course of action.
3. Low-Level Radioactive Waste
We regained access to low-level radioactive waste (LLW) disposal facilities
located in Barnwell, South Carolina, in 1995. This site is currently the only
disposal facility available to us. Legislation has been enacted in
Massachusetts establishing a regulatory process for managing LLW, including
the possible siting, licensing and construction of a disposal facility within
the state, or, alternatively, an agreement with one or more other states.
Pending the construction of a disposal facility within the state or the
adoption by the state of some other LLW management procedure, we will continue
to monitor the situation and investigate other available options.
Note F. 1995 Corporate Restructuring
In 1995 we streamlined the corporate organization and reorganized the company
into separate business units in order to strengthen our competitiveness in the
changing electric energy market. In conjunction with this reorganization we
offered enhanced retirement programs and implemented a special severance
program to reduce employee staffing levels. Under the enhanced retirement
programs 330 employees elected to retire, and 149 employees whose positions
were eliminated became eligible for benefits under the special severance
program. These programs resulted in a $34 million pre-tax charge ($20.7
million after tax) over the third and fourth quarters of 1995. The charge
consisted of $24 million for the retirement programs and $10 million for the
severance program.
Note G. Pensions and Other Postretirement Benefits
1. Pensions
We have a defined benefit funded retirement plan with certain contributory
features that covers substantially all employees. Benefits are based upon an
employee's years of service and highest eligible average compensation during
the last ten years of credited employment. Our funding policy is to
contribute an amount each year that is not less than the minimum required
contribution under federal law or greater than the maximum tax deductible
amount. The retirement plan assets consist of equities, bonds, money market
funds, insurance contracts and real estate funds.
We also have an unfunded supplemental retirement plan for certain management
employees. Benefits under this plan are based upon an employee's years of
service and highest eligible average compensation during years of credited
employment.
<PAGE> 37
Net pension cost consisted of the following components:
<TABLE>
<CAPTION>
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current service cost - benefits earned $12,625 $13,452 $11,339
Interest cost on projected benefit
obligation 31,537 32,325 31,789
Actual return on plan assets (60,602) (40,335) (72,192)
Net amortization and deferral 33,912 17,064 49,557
- -----------------------------------------------------------------------------
Net pension cost $17,472 $22,506 $20,493
=============================================================================
</TABLE>
In accordance with our 1992 retail rate settlement agreement we deferred the
difference between the net pension cost of the retirement plan and its annual
funding amount through 1995. Net pension cost recognized in 1995 was $28
million.
We experienced a high number of employee retirements from 1994 to 1996. A
large number of these retirements were as a direct result of our 1995
corporate restructuring. In 1997, a review of the accounting for the pension
expense related to the retirements revealed that an adjustment to the pension
costs related to these employees was necessary. Therefore, we increased our
pension regulatory asset by $8.6 million in 1997 for the adjustment related to
the period of our 1992 settlement agreement. The remaining adjustment did not
have a material impact on our consolidated results of operations or financial
position.
We used the following assumptions for calculating pension cost:
<TABLE>
<CAPTION>
1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 7.75% 7.25% 8.25%
Expected long-term rate of return on assets 10.00% 10.00% 10.00%
Compensation increase rate 3.90% 3.90% 3.90%
- -----------------------------------------------------------------------------
</TABLE>
<PAGE> 38
The plans' funded status were as follows:
<TABLE>
<CAPTION>
December 31,
(in thousands) 1997 1996
- -----------------------------------------------------------------------------
Supplemental Supplemental
Retirement Retirement Retirement Retirement
Plan Plan Plan Plan
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Actuarial present value of
accumulated benefit
obligation:
Vested $361,484 $ 8,571 $316,101 $ 7,576
Non-vested 10,578 1,192 10,867 943
- -----------------------------------------------------------------------------
Total $372,062 $ 9,763 $326,968 $ 8,519
=============================================================================
Plan assets at fair value $401,182 $ 0 $331,299 $ 0
Projected obligation for
service rendered to date (446,360) (11,076) (400,561) (9,199)
- -----------------------------------------------------------------------------
Projected benefit
obligation in excess of
plan assets (45,178) (11,076) (69,262) (9,199)
Unrecognized prior service
cost 9,385 9,736 11,238 9,436
Unrecognized net loss/(gain) 50,673 (27) 78,853 (1,141)
Unrecognized net obligation 5,704 0 7,130 0
Additional minimum
liability (a) 0 (8,396) 0 (7,615)
- -----------------------------------------------------------------------------
Net pension prepayment/
(liability) (b) $ 20,584 $ (9,763) $ 27,959 $ (8,519)
=============================================================================
<FN>
(a) Statement of Financial Accounting Standards No. 87, Employers' Accounting
for Pensions (SFAS 87), requires the recognition of an additional minimum
liability for the excess of accumulated benefits over the fair value of
plan assets and accrued pension costs. In accordance with SFAS 87 we
recorded additional minimum liabilities and corresponding intangible
assets of $8.4 million and $7.6 million on our consolidated balance
sheets at December 31, 1997 and 1996, respectively.
(b) The prepaid pension amount at December 31, 1997 reflects the impact of
$8 million related to the fossil workforce reduction as discussed in
Note C to these Consolidated Financial Statements.
</TABLE>
We used the following assumptions for calculating the plans' year-end funded
status:
<TABLE>
<CAPTION>
1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C>
Discount rate 7.25% 7.75%
Compensation increase rate 4.25% 3.90%
- -----------------------------------------------------------------------------
</TABLE>
We also provide defined contribution 401(k) plans for substantially all of our
employees. We match a portion of employees' voluntary contributions to the
plans. We made matching contributions of $8 million in 1997 and 1996 and $9
million in 1995.
2. Other Postretirement Benefits
In addition to pension benefits, we also provide health care and other
benefits to our retired employees who meet certain age and years of service
eligibility requirements. These postretirement benefits other than pensions
(PBOPs) are accounted for in accordance with Statement of Financial Accounting
<PAGE> 39
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions (SFAS 106). Our 1992 retail rate settlement agreement provided
us with a phase-in to full expense of the PBOP costs incurred under SFAS 106.
This settlement agreement allowed us to defer any costs in excess of the
specified phase-in amounts to the extent that we funded an external trust.
Our funding policy is to generally contribute 100% of PBOP costs to external
trusts. Therefore, we recognized $23 million of PBOP costs in 1995 in
accordance with the 1992 settlement agreement. Beginning in 1996 we
recognized the full PBOP costs incurred under SFAS 106. The net deferred PBOP
costs of $15 million resulting from the delayed phase-in are included in
regulatory assets as these costs will be recovered from customers in future
periods.
Net postretirement benefits cost consisted of the following components:
<TABLE>
<CAPTION>
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current service cost - benefits earned $ 3,543 $ 4,616 $ 3,408
Interest cost on accumulated benefit
obligation 17,006 16,815 13,521
Actual return on plan assets (18,852) (9,584) (7,151)
Amortization of transition obligation 9,151 9,151 9,151
Net other amortization and deferral 12,417 5,209 3,017
- -----------------------------------------------------------------------------
Net postretirement benefits cost $23,265 $26,207 $21,946
=============================================================================
</TABLE>
We used the following assumptions for calculating postretirement benefits
cost:
<TABLE>
<CAPTION>
1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 7.75% 7.25% 8.25%
Expected long-term rate of return on assets 9.00% 9.00% 9.00%
Health care cost trend rate 6.00% 7.00% 7.00%
- -----------------------------------------------------------------------------
</TABLE>
The health care cost trend rate is assumed to decrease by 1% in 1998 and to
remain at 5% in years thereafter. Changes in the health care cost trend rate
will affect our cost and obligation amounts. A 1% increase in the assumed
health care cost trend rate would increase the total service and interest cost
components by 7.4% and would increase the accumulated benefit obligation at
December 31, 1997 by 6.6%.
<PAGE> 40
The PBOP program's funded status was as follows:
<TABLE>
<CAPTION>
December 31,
(in thousands) 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Trust assets at fair value $ 103,989 $ 72,702
Accumulated obligation for service
rendered to date from:
Retirees $(166,035) $(156,694)
Active employees eligible to retire (16,484) (12,644)
Active employees not eligible to
retire (55,097) (237,616) (61,567) (230,905)
- -----------------------------------------------------------------------------
Accumulated benefit obligation in
excess of trust assets (133,627) (158,203)
Unrecognized prior service cost (14,128) (16,274)
Unrecognized net loss 12,916 26,663
Unrecognized transition obligation 127,107 146,413
- -----------------------------------------------------------------------------
Net postretirement benefits
liability (a) $ (7,732) $ (1,401)
=============================================================================
<FN>
(a) The postretirement benefits liability at December 31, 1997 reflects an
$8 million additional PBOP obligation related to the fossil workforce
reduction as discussed in Note C to these Consolidated Financial
Statements.
</TABLE>
The weighted average discount rates used to measure the program's year-end
funded status were 7.25% in 1997 and 7.75% in 1996. The trust assets consist
of equities, bonds and money market funds.
Note H. Stock-Based Compensation
In 1997, we initiated a Stock Incentive Plan (the Plan) which was adopted by
the Board of Directors and approved by our stockholders. The Plan permits a
variety of stock and stock-based awards, including stock options and deferred
(nonvested) stock to be granted to certain key employees. The Plan limits the
terms of awards to ten years. Subject to adjustment for stock-splits and
similar events, the aggregate number of shares of common stock that may be
delivered under the Plan is 2,000,000, including shares issued in lieu of or
upon reinvestment of dividends arising from awards. During 1997, we granted
73,820 shares of deferred stock and 298,400 ten-year non-qualified stock
options under the Plan. The weighted average grant date fair value of the
deferred stock is $27.26. The options were granted at the full market price
of the stock on the date of the grant. Both awards vest ratably over a three-
year period.
We recognize compensation cost for our stock-based awards under the provisions
of APB Opinion 25, which requires compensation cost to be measured by the
quoted stock market price at the measurement date less the amount, if any, an
employee is required to pay. The required fair value method disclosures
related to our stock-based compensation are as follows:
<TABLE>
<CAPTION>
(in thousands, except per share amounts) 1997
- ---------------------------------------------------
<S> <C>
Net income
Actual $144,642
Pro forma $144,572
Earnings per share
Actual $2.71
Pro forma $2.71
</TABLE>
<PAGE> 41
Stock option activity of the Plan was as follows:
<TABLE>
- ---------------------------------------------------------------------------
<S> <C>
Options outstanding at January 1, 1997 0
Options granted 298,400
Options forfeited (25,400)
- ---------------------------------------------------------------------------
Options outstanding at December 31, 1997 273,000
===========================================================================
</TABLE>
Summarized information regarding stock options outstanding at December 31,
1997:
<TABLE>
<CAPTION>
Weighted
Range of Average Remaining Weighted Average
Exercise Prices Contractual Life (Years) Exercise Price
- --------------- ------------------------ ----------------
<S> <C> <C>
$25.75-$26.00 9.44 $25.84
</TABLE>
No stock options were exercisable at December 31, 1997.
The stock options were granted with a weighted average grant date fair value
of $2.22. The fair value was estimated using the Black-Scholes option pricing
model with the following weighted average assumptions:
<TABLE>
<S> <C>
Expected life (years) 4.0
Risk-free interest rate 6.44%
Volatility 16%
Dividends 7.28%
</TABLE>
Compensation cost recognized in income for our stock-based compensation awards
in 1997 was $275,000.
<PAGE> 42
Note I. Capital Stock
<TABLE>
<CAPTION>
December 31,
(dollars in thousands, except per share amounts) 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C>
Common stock equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 48,514,973
and 48,509,537 shares issued and
outstanding: $ 48,515 $ 48,510
Premium on common stock 696,137 695,723
Retained earnings 328,802 292,191
- -----------------------------------------------------------------------------
Total common stock equity $1,073,454 $1,036,424
=============================================================================
</TABLE>
Dividends declared per share of common stock were $1.88 in 1997 and 1996 and
$1.835 in 1995.
<TABLE>
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares
authorized; issued and outstanding:
Nonmandatory redeemable series:
<CAPTION>
Current Shares Redemption
Series Outstanding Price/Share
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
4.25% 180,000 $103.625 $ 18,000 $ 18,000
4.78% 250,000 $102.800 25,000 25,000
7.75% 400,000 - 40,000 40,000
8.25% - - 0 40,000
- -----------------------------------------------------------------------------
83,000 123,000
Less: redemption and issuance costs 0 (3,046)
- -----------------------------------------------------------------------------
Total nonmandatory redeemable series $ 83,000 $ 119,954
=============================================================================
</TABLE>
<TABLE>
Mandatory redeemable series:
<CAPTION>
Current Shares Redemption
Series Outstanding Price/Share
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
7.27% 360,000 $102.420 $ 36,000 $ 40,000
8.00% 500,000 - 50,000 50,000
- -----------------------------------------------------------------------------
86,000 90,000
Less: redemption and issuance costs (5,907) (6,535)
due within one year (2,000) (2,000)
- -----------------------------------------------------------------------------
Total mandatory redeemable series $ 78,093 $ 81,465
=============================================================================
</TABLE>
1. Common Stock
Common stock issuances in 1995 through 1997 were as follows:
<TABLE>
<CAPTION>
Number Total Premium on
(in thousands) of Shares Par Value Common Stock
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at December 31, 1994 45,535 $45,535 $622,803
Dividend reinvestment plan 468 468 11,404
New issuances 2,000 2,000 49,479
- -----------------------------------------------------------------------------
Balance at December 31, 1995 48,003 48,003 683,686
Dividend reinvestment plan 507 507 12,037
- -----------------------------------------------------------------------------
Balance at December 31, 1996 48,510 48,510 695,723
Dividend reinvestment plan 5 5 414
- -----------------------------------------------------------------------------
Balance at December 31, 1997 48,515 $48,515 $696,137
=============================================================================
</TABLE>
<PAGE> 43
2. Cumulative Mandatory Redeemable Preferred Stock
The 360,000 shares of 7.27% sinking fund series cumulative preferred stock are
currently redeemable at our option at $102.420. The redemption price declines
annually each May to par value in May 2002. The stock is subject to a
mandatory sinking fund requirement of 20,000 shares each May at par plus
accrued dividends. We also have the noncumulative option each May to redeem
additional shares, not to exceed 20,000, through the sinking fund at $100 per
share plus accrued dividends. We redeemed, at par value, 40,000 shares in
1997 and 1996 and 20,000 shares in 1995.
We are not able to redeem any part of the 500,000 shares of 8% series
cumulative preferred stock prior to December 2001. The entire series is
subject to mandatory redemption in December 2001 at $100 per share plus
accrued dividends.
Note J. Indebtedness
<TABLE>
<CAPTION>
December 31,
(in thousands) 1997 1996
- -----------------------------------------------------------------------------
<S> <C> <C>
Long-term debt:
Debentures:
5.700%, due March 1997 $ 0 $ 100,000
5.950%, due March 1998 100,000 100,000
6.800%, due February 2000 65,000 65,000
6.050%, due August 2000 100,000 100,000
6.800%, due March 2003 150,000 150,000
7.800%, due May 2010 125,000 125,000
9.875%, due June 2020 100,000 100,000
9.375%, due August 2021 115,000 115,000
8.250%, due September 2022 60,000 60,000
7.800%, due March 2023 200,000 200,000
- -----------------------------------------------------------------------------
Total debentures 1,015,000 1,115,000
Less: due within one year (100,000) (100,000)
- -----------------------------------------------------------------------------
Net long-term debentures 915,000 1,015,000
- -----------------------------------------------------------------------------
Sewage facility revenue bonds 32,500 34,100
Less: due within one year (667) (667)
Less: funds held by trustee (4,757) (4,789)
- -----------------------------------------------------------------------------
Net long-term sewage facility revenue bonds 27,076 28,644
- -----------------------------------------------------------------------------
Massachusetts Industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000
6.662% bank loan, due 1999 100,000 0
- -----------------------------------------------------------------------------
Total long-term debt $1,057,076 $1,058,644
=============================================================================
Short-term debt:
Notes payable:
Bank loans $ 94,013 $ 129,631
Commercial paper 43,000 71,823
- -----------------------------------------------------------------------------
Total notes payable $ 137,013 $ 201,454
=============================================================================
</TABLE>
<PAGE> 44
1. Long-term Debt
The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a
redemption price of 104.483%, the 9 3/8% series due 2021 are first redeemable
in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in
September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable
in March 2003 at 103.730%. No other series are redeemable prior to maturity.
There is no sinking fund requirement for any series of our debentures.
Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt,
subject to annual mandatory sinking fund redemption requirements and mature
through 2015. In both May 1996 and 1997, we redeemed $1.6 million as
scheduled. The weighted average interest rate of the bonds is 7.3%. A
portion of the proceeds from the bonds is in reserve with the trustee. If
HEEC should have insufficient funds to pay for extraordinary expenses, we
would be required to make additional capital contributions or loans to the
subsidiary up to a maximum of $1 million.
The 5.75% tax-exempt unsecured bonds due 2014 are redeemable beginning in
February 2004 at a redemption price of 102%. The redemption price decreases
to 101% in February 2005 and to par in February 2006.
In March 1997, we obtained $100 million of 6.662% notes in the form of a bank
loan. This note matures in 1999.
The aggregate principal amounts of our long-term debt (including HEEC sinking
fund requirements) due through 2002 are $101.6 million in 1998 and 1999,
$166.6 million in 2000 and $1.6 million in 2001 and 2002.
2. Short-term Debt
We have arrangements with certain banks to provide short-term credit on both a
committed and an uncommitted and as available basis. We currently have
regulatory authority to issue up to $350 million of short-term debt.
We have a $200 million revolving credit agreement with a group of banks. This
agreement is intended to provide a standby source of short-term borrowings.
Under the terms of this agreement we are required to maintain a common equity
ratio of not less than 30% at all times. Commitment fees must be paid on the
unused portion of the total agreement amount.
Information regarding our utility short-term borrowings, comprised of bank
loans and commercial paper, is as follows:
<TABLE>
<CAPTION>
(dollars in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Maximum short-term borrowings $316,100 $272,500 $327,769
Weighted average amount outstanding $212,663 $208,914 $165,720
Weighted average interest rates excluding
commitment fees 5.85% 5.65% 6.21%
- -----------------------------------------------------------------------------
</TABLE>
In addition, at December 31, 1997, BETG had $7.5 million outstanding under a
revolving credit agreement.
<PAGE> 45
Note K. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each class of securities for which it is practicable to estimate the value:
Nuclear decommissioning trust:
The cost of $151.6 million approximates fair value based on quoted market
prices of securities held.
Cash and cash equivalents:
The carrying amount of $4.1 million approximates fair value due to the
short-term nature of these securities.
Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds
and unsecured debt:
The fair values of these securities are based upon the quoted market prices of
similar issues. Carrying amounts and fair values as of December 31, 1997, are
as follows:
<TABLE>
<CAPTION>
Carrying Fair
(in thousands) Amount Value
- ------------------------------------------------------------------------------
<S> <C> <C>
Mandatory redeemable cumulative preferred stock $ 80,093 $ 91,720
Sewage facility revenue bonds $ 32,500 $ 35,084
Unsecured debt $1,030,000 $1,073,982
- ------------------------------------------------------------------------------
</TABLE>
Note L. Commitments and Contingencies
1. Contractual Commitments
At December 31, 1997, we had estimated contractual obligations for plant and
equipment of approximately $18 million.
We have leases for certain facilities and equipment. Our estimated minimum
rental commitments under both transmission agreements and noncancellable
leases for the years after 1997 are as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
1998 $ 21,938
1999 18,958
2000 16,738
2001 12,356
2002 11,194
Years thereafter 91,874
- ------------------------------------------------------
Total $173,058
======================================================
</TABLE>
Amounts above include $2.7 million which is expected to be assumed by Sithe
Energies as part of our pending fossil divestiture discussed in Note C to
these Consolidated Financial Statements.
The total of future minimum rental income to be received under noncancellable
subleases related to the above leases is $300,921.
We will capitalize a portion of these lease rentals as part of plant
expenditures in the future. The total expense for both lease rentals and
transmission agreements was $27.5 million in 1997, $26.3 million in 1996 and
<PAGE> 46
$24.5 million in 1995, net of capitalized expenses of $1.2 million in 1997,
$2.9 million in 1996 and $2.7 million in 1995.
We previously entered into various take or pay and throughput agreements,
primarily to supply our New Boston fossil generating station with natural gas.
The fixed and determinable portions of the obligations associated with these
agreements are $19.5 million in 1998 and 1999 and $14.6 million in 2000. As
part of our fossil divestiture agreement, Sithe Energies has agreed to assume
these obligations. The total expense under these agreements was $47.1 million
in 1997, $49.5 million in 1996 and $13.9 million in 1995.
2. Electric Company Investments
We have an approximately 11% equity investment in two companies which own and
operate transmission facilities to import electricity from the Hydro-Quebec
system in Canada. As an equity participant we are required to guarantee, in
addition to our own share, the total obligations of those participants who do
not meet certain credit criteria. At December 31, 1997, our portion of these
guarantees was $16.6 million.
We have a 9.5% equity investment of approximately $2 million in Yankee Atomic
Electric Company (Yankee Atomic). In 1992 the board of directors of Yankee
Atomic decided to discontinue operations of the Yankee Atomic nuclear
generating station permanently and decommission the facility.
Yankee Atomic received approval from the FERC to continue to collect its
investment and decommissioning costs through 2000, the period of the plant's
operating license. The estimate of our share of Yankee Atomic's investment
and costs of decommissioning is approximately $13 million as of December 31,
1997. This estimate is recorded on our consolidated balance sheet as a power
contract liability and an offsetting regulatory asset.
We also have a 9.5% equity investment in Connecticut Yankee Atomic Power
Company (CYAPC) of approximately $11 million. In December 1996, the board of
directors of CYAPC, which owns and operates the Connecticut Yankee nuclear
electric generating unit (Connecticut Yankee), unanimously voted to retire the
unit. The decision was based on an economic analysis of the costs of
operating the unit through 2007, the period of its operating license, compared
to the costs of closing the unit and incurring replacement power costs for the
same period.
The current estimate of the sum of future payments for the closing,
decommissioning and recovery of the remaining investment in Connecticut Yankee
is approximately $615 million. Our share of these remaining estimated costs
is $58 million. This estimate is recorded on our consolidated balance sheet
as a power contract liability and an offsetting regulatory asset similar to
Yankee Atomic.
In early 1997, CYAPC filed a rate case at the FERC seeking to recover certain
post-operating costs, including decommissioning. The Connecticut Department
of Public Utility Control (DPUC) has raised concerns to the FERC regarding
CYAPC's estimate of these costs and the plant operator's prudency prior to the
shutdown decision. The FERC set CYAPC's request for hearing before an
Administrative Law Judge. The DPUC subsequently filed testimony in the
proceeding asserting the position that the FERC should deny recovery of
substantial post-operating costs, including a significant amount related to
decommissioning and the return on CYAPC's undepreciated investment. We are
currently unable to determine the ultimate outcome of this proceeding or its
impact.
<PAGE> 47
3. Nuclear Insurance
The federal Price-Anderson Act currently provides $8.9 billion of financial
protection for public liability claims and legal costs arising from a single
nuclear-related accident. The first $200 million of nuclear liability is
covered by commercial insurance. Additional nuclear liability insurance up to
$8.7 billion is provided by a retrospective assessment of up to $79.3 million
per incident levied on each of the 110 nuclear generating units currently
licensed to operate in the United States, with a maximum assessment of $10
million per reactor per accident in any year.
We have purchased insurance from Nuclear Electric Insurance Limited (NEIL) to
cover some of the costs to purchase replacement power during a prolonged
accidental outage and the cost of repair, replacement, decontamination or
decommissioning of our utility property resulting from covered incidents at
Pilgrim Station. Our maximum potential total assessment for losses which
occur during current policy years is $10.4 million under both the replacement
power and excess property damage, decontamination and decommissioning
policies.
4. Hazardous Waste
We are an owner or operator of approximately 30 properties where oil or
hazardous materials were spilled or released. As such, we are required to
clean up these properties in accordance with a timetable developed by the
Massachusetts Department of Environmental Protection. We continue to evaluate
the costs associated with site cleanup. There are uncertainties associated
with these costs due to the complexities of cleanup technology, regulatory
requirements and the particular characteristics of the different sites. We
also continue to face possible liability as a potentially responsible party in
the cleanup of six multi-party hazardous waste sites in Massachusetts and
other states where we are alleged to have generated, transported or disposed
of hazardous waste at the sites. We are one of many potentially responsible
parties and currently expect to have only a small percentage of the potential
liability. Through December 31, 1997, we have accrued approximately $7
million related to our cleanup liabilities. We are unable to fully determine
a range of reasonably possible cleanup costs in excess of the accrued amount,
although based on our assessments of the specific site circumstances, we do
not believe that it is probable that any such additional costs will have a
material impact on our financial condition. However, it is reasonably
possible that additional provisions for cleanup costs that may result from a
change in estimates could have a material impact on the results of a reporting
period in the near term.
5. Generating Unit Performance Program
Our recovery of the incremental purchased power costs resulting from outages
at our generating units occurring through the retail access date is subject to
review by the DTE. We are unable to fully determine a range of reasonably
possible disallowance costs in excess of amounts accrued, although, based on
the information currently available, we do not believe that it is probable
that any such additional costs will have a material impact on our financial
condition. However, it is reasonably possible that additional disallowance
costs that may result from a change in estimates could have a material impact
on the results of a reporting period in the near term.
<PAGE> 48
6. Litigation
In October 1997, the DTE opened a proceeding to investigate our compliance
with the 1993 order which permitted the formation of BETG and authorized us to
invest up to $45 million in unregulated activities. We are unable to
determine the ultimate outcome of this proceeding or its impact on our
operations.
In the normal course of our business we are involved in certain other legal
matters. We are unable to fully determine a range of reasonably possible
litigation costs in excess of amounts accrued, although, based on the
information currently available, we do not believe that it is probable that
any such additional costs will have a material impact on our financial
condition. However, it is reasonably possible that additional litigation
costs that may result from a change in estimates could have a material impact
on the results of a reporting period in the near term.
7. Industry Restructuring Legal Proceedings/Referendum Campaign
The DTE order approving our settlement agreement has been appealed by certain
parties to the Massachusetts Supreme Judicial Court. In addition, along with
other Massachusetts investor-owned utilities, we have been named as a
defendant in a class action suit seeking to declare certain provisions of the
Massachusetts electric industry restructuring legislation unconstitutional.
We are currently unable to determine the outcome of these proceedings or their
impact on us.
Opponents of the electric industry restructuring legislation that was enacted
in November 1997 have mounted a referendum campaign to repeal that law. A
coalition of business, industry and public interest groups that supported the
legislation, along with the electric utility industry, is opposed to the
referendum and is prepared to mount an aggressive campaign to defeat it. We
are currently unable to predict the eventual outcome of this referendum or its
impact on us.
<PAGE> 49
Note M. Long-Term Power Contracts
1. Long-Term Contracts for the Purchase of Electricity
We purchase electric power under several long-term contracts for which we pay
a share of a generating unit's capital and fixed operating costs through the
contract expiration date. The total cost of these contracts is included in
purchased power expense on our consolidated income statements. Information
relating to these contracts as of December 31, 1997, is as follows:
<TABLE>
<CAPTION>
proportionate share (in thousands)
Units of -------------------------------------
Capacity Debt
Contract Purchased(a) Minimum Outstanding
Expiration ------------ Debt Through Cont. Annual
Generating Unit Date % MW Service Exp. Date Cost
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Canal Unit 1 2002 25.0 141 $ 1,475 $ 5,172 $ 28,997
Mass. Bay Trans-
portation
Authority - 1 2005 100.0 34 - - 2,166
Ocean State Power -
Unit 1 2010 23.5 72 4,256 17,962 21,778
Ocean State Power -
Unit 2 2011 23.5 72 3,592 15,951 23,969
Northeast Energy
Associates (b) (b) 219 - - 134,023
L'Energia (c) 2013 73.0 63 - - 21,902
MassPower 2013 44.3 117 11,227 70,660 54,215
Mass. Bay Trans-
portation
Authority - 2 2019 100.0 34 - - 577
- ------------------------------------------------------------------------------
Total 752 $20,550 $109,745 $287,627
==============================================================================
<FN>
(a) The Northeast Energy Associates contract represents 6.5% of our total
system generation capability. The remaining units listed above represent
approximately 16% in total.
(b) We purchase 75.5% of the energy output of this unit under two contracts.
One contract represents 135MW and expires in the year 2015. The other
contract is for 84MW and expires in 2010. We pay for this energy based
on a price per kWh actually received. We do not pay a proportionate
share of the unit's capital and fixed operating costs.
(c) We pay for this energy based on a price per kWh actually received.
</TABLE>
Our total fixed and variable costs associated with these contracts in 1997,
1996 and 1995 were approximately $288 million, $281 million and $262 million,
respectively. Our minimum fixed payments under these contracts for the years
after 1997 are as follows:
<TABLE>
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
1998 $ 88,406
1999 88,501
2000 89,853
2001 90,365
2002 92,768
Years thereafter 959,981
- ------------------------------------------------------
Total $1,409,874
======================================================
Total present value $ 783,975
======================================================
</TABLE>
<PAGE> 50
Under our settlement agreement, by July 1998 we are required to file a plan
with the DTE describing the actions we intend to take to sell, assign or
otherwise dispose of our purchased power contracts.
2. Long-Term Power Sales Contracts
In addition to other wholesale power sales, we sell a percentage of Pilgrim
Station's output to other utilities and municipalities under long-term
contracts. Information relating to these contracts is as follows:
<TABLE>
<CAPTION>
Contract Units of Capacity Sold
Expiration ----------------------
Contract Customer Date % MW
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Commonwealth Electric Company 2012 11.0 73.7
Montaup Electric Company 2012 11.0 73.7
Various municipalities 2000(a) 3.7 25.0
- ------------------------------------------------------------------------------
Total 25.7 172.4
==============================================================================
<FN>
(a) Subject to certain adjustments.
</TABLE>
Under these contracts, the utilities and municipalities pay their
proportionate share of the costs of operating Pilgrim Station and associated
transmission facilities. These costs include operation and maintenance
expenses, insurance, local taxes, depreciation, decommissioning and a return
on investment.
<PAGE> 51
<TABLE>
Selected Consolidated Quarterly Financial Data (Unaudited)
<CAPTION>
(in thousands, except earnings per share)
Earnings
Available Earnings
Operating Operating Net for Common Per Average
Revenues Income Income Shareholders Common Share(a)
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1997
- ----
First quarter $422,725 $ 47,589 $20,935 $17,118 $0.35
Second quarter 426,735 60,487 33,978 30,484 0.63
Third quarter 519,513 108,060 81,418 78,499 1.62
Fourth quarter 407,260 44,714 8,311 5,392 0.11
1996
- ----
First quarter $387,849 $ 52,093 $25,203 $21,313 $0.44
Second quarter 389,756 55,232 27,926 24,086 0.50
Third quarter 497,968 105,353 80,011 76,194 1.58
Fourth quarter 390,730 35,252 8,406 4,588 0.09
<FN>
(a) Based on the weighted average number of common shares outstanding during
each quarter.
</TABLE>
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure
- --------------------
Not applicable.
<PAGE> 52
Part III
--------
Item 10. Directors and Executive Officers of the Registrant
- ------------------------------------------------------------
(a) Identification of Directors
- ---------------------------------
See "Election of Directors - Information about Nominees and Incumbent
Directors" on pages 1 through 4 of the definitive proxy statement dated
March 31, 1998, incorporated herein by reference.
(b) Identification of Executive Officers
- -----------------------------------------
The information required by this item is included at the end of Part I of this
Form 10-K under the caption Executive Officers of the Registrant.
(c) Identification of Certain Significant Employees
- ----------------------------------------------------
Not applicable.
(d) Family Relationships
- -------------------------
Not applicable.
(e) Business Experience
- ------------------------
For information relating to the business experience during the past five years
and other directorships (of companies subject to certain SEC requirements)
held by each person nominated to be a director, see "Election of Directors -
Information about Nominees and Incumbent Directors" on pages 1 through 4 of
the definitive proxy statement dated March 31, 1998, incorporated herein by
reference.
For information relating to the business experience during the past five years
of each person who is an executive officer, see Executive Officers of the
Registrant in this Form 10-K.
(f) Involvement in Certain Legal Proceedings
- ---------------------------------------------
Not applicable.
(g) Promoters and Control Persons
- ----------------------------------
Not applicable.
Item 11. Executive Compensation
- --------------------------------
See "Executive Compensation" on pages 5 through 12 of the definitive proxy
statement dated March 31, 1998, incorporated herein by reference.
<PAGE> 53
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners
- ----------------------------------------------------
To the knowledge of management, no person owns beneficially more than five
percent of the outstanding voting securities of the Company.
(b) Security Ownership of Management
- -------------------------------------
See "Stock Ownership by Directors and Executive Officers" on pages 4 through 5
of the definitive proxy statement dated March 31, 1998, incorporated herein by
reference.
(c) Changes in Control
- -----------------------
Not applicable.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Not applicable.
<PAGE> 54
Part IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
(a) The following documents are filed as part of this Form 10-K:
<TABLE>
<CAPTION>
1. Financial Statements:
Page
----
<S> <C>
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995 24
Consolidated Statements of Retained Earnings for the
years ended December 31, 1997, 1996 and 1995 24
Consolidated Balance Sheets as of December 31, 1997 and 1996 25
Consolidated Statements of Cash Flows for the years
ended December 31, 1997, 1996 and 1995 26
Notes to Consolidated Financial Statements 27
Selected Consolidated Quarterly Financial Data (Unaudited) 51
Report of Independent Accountants 65
</TABLE>
2. Financial Statement Schedules:
No financial statement schedules are included as they are either not required
or not applicable.
3. Exhibits:
Refer to the exhibits listing beginning on the following page.
(b) Reports on Form 8-K:
A Form 8-K dated November 25, 1997, was filed during the fourth quarter of
1997 disclosing that a Massachusetts electric utility industry restructuring
bill was signed into law in November 1997. In addition, the 8-K announced
that Sithe Energies, Inc. won the bid to purchase the Company's non-nuclear
generating assets.
<PAGE> 55
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 3 Articles of Incorporation and By-Laws
- --------- -------------------------------------
Incorporated herein by reference:
<S> <C> <C> <C>
3.1 Restated Articles of Organization 3.1 1-2301
Form 10-Q
for the
quarter ended
June 30, 1994
3.2 Boston Edison Company Bylaws 3.1 1-2301
April 19, 1977, as amended Form 10-Q
January 22, 1987, January 28, 1988, for the
May 24, 1988 and November 22, 1989 quarter ended
June 30, 1990
Exhibit 4 Instruments Defining the Rights of
- --------- ----------------------------------
Security Holders, Including Indentures
--------------------------------------
Incorporated herein by reference:
4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301
dated September 1, 1988, between Form 10-Q
Boston Edison Company and Bank of for the
Montreal Trust Company quarter ended
September 30,
1988
4.1.1 First Supplemental Indenture 4.1 1-2301
dated June 1, 1990 to Form 8-K
Indenture dated September 1, 1988 dated
with Bank of Montreal Trust Company - June 28, 1990
9 7/8% debentures due June 1, 2020
4.1.2 Indenture of Trust and Agreement among 4.1.26 1-2301
the City of Boston, Massachusetts Form 10-K
(acting by and through its Industrial for the
Development Financing Authority) and year ended
Harbor Electric Energy Company and December 31,
Shawmut Bank, N.A., as Trustee, dated 1991
November 1, 1991
4.1.3 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 5, 1991 re for the
9 3/8% debentures due August 15, 2021 year ended
December 31,
1991
</TABLE>
<PAGE> 56
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301
February 12, 1993 Form 10-K
for the
year ended
December 31,
1992
4.1.4.1 First Amendment to Revolving Credit 4.1.10 1-2301
Agreement dated May 19, 1995 Form 10-K
for the
year ended
December 31,
1995
4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken September 10, 1992 re for the
8 1/4% debentures due September 15, 2022 year ended
December 31,
1992
4.1.6 Votes of the Pricing Committee of the 4.1.26 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken January 27, 1993 re for the
6.80% debentures due February 1, 2000 year ended
December 31,
1992
4.1.7 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken March 5,1993 re for the
6.80% debentures due March 15, 2003, year ended
7.80% debentures due March 15, 2023 December 31,
1992
4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 18, 1993 re for the
6.05% debentures due August 15, 2000 year ended
December 31,
1993
4.1.9 Votes of the Pricing Committee of the 4.1.9 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken May 10, 1995 re for the
7.80% debentures due May 15, 2010 year ended
December 31,
1995
</TABLE>
<PAGE> 57
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Filed herewith:
<S> <C>
4.1.4.2 Second Amendment to Revolving Credit
Agreement dated July 1, 1997
</TABLE>
The Company agrees to furnish to the Securities and Exchange Commission, upon
request, a copy of any agreements or instruments defining the rights of
holders of any long-term debt whose authorization does not exceed 10% of the
Company's total assets.
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 10 Material Contracts
- ---------- ------------------
Incorporated herein by reference:
<S> <C> <C> <C>
10.1 Key Executive Benefit Plan 10.3.1 1-2301
Standard Form of Agreement, May Form 10-K
1986, with modifications for the
year ended
December 31,
1991
10.2 Executive Annual Incentive 10.5 1-2301
Compensation Plan Form 10-K
for the
year ended
December 31,
1988
10.2.1 Supplemental Executive Retirement 10.1 1-2301
Plan Form 10-Q
for the
quarter ended
June 30, 1997
10.2.2 1997 Stock Incentive Plan 10.2 1-2301
Form 10-Q
for the
quarter ended
June 30, 1997
10.3 1991 Director Stock Plan 10.1 1-2301
Form 10-Q
for the
quarter ended
March 31, 1991
</TABLE>
<PAGE> 58
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
10.4 Directors Retirement Benefit 10.8.1 1-2301
(1993 Plan) Form 10-K
for the
year ended
December 31,
1993
10.5 Boston Edison Company Deferred 10.11 1-2301
Fee Plan dated January 14, 1993 Form 10-K
for the
year ended
December 31,
1992
10.6 Deferred Compensation Trust 10.10 1-2301
between Boston Edison Company Form 10-K
and State Street Bank and for the
Trust Company dated year ended
February 2, 1993 December 31,
1992
10.6.1 Amendment No. 1 to Deferred 10.5.1 1-2301
Compensation Trust dated Form 10-K
March 31, 1994 for the
year ended
December 31,
1994
10.7 Boston Edison Company Deferred 10.9 1-2301
Compensation Plan, Amendment and Form 10-K
Restatement dated January 31, 1995 for the
year ended
December 31,
1994
10.8 Employment Agreement applicable to 10.10 1-2301
Ronald A. Ledgett dated April 30, 1987 Form 10-K
for the
year ended
December 31,
1994
10.9 Retention Agreement applicable to 10.1 1-2301
Ronald A. Ledgett dated May 15, 1996 Form 10-Q
for the
quarter ended
June 30, 1996
</TABLE>
<PAGE> 59
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
10.9.1 Retention Agreement applicable to 10.13 1-2301
Douglas S. Horan dated May 15, 1996 Form 10-K
for the
year ended
December 31,
1996
10.10 Change in Control Agreement applicable 10.2 1-2301
to Thomas J. May dated July 8, 1996 Form 10-Q
for the
quarter ended
June 30, 1996
10.11 Form of Change in Control Agreement 10.3 1-2301
applicable to Ronald A. Ledgett, Form 10-Q
L. Carl Gustin, Douglas S. Horan, for the
James J. Judge and certain other quarter ended
officers dated July 8, 1996 June 30, 1996
Filed herewith:
10.9.2 Retention Agreement applicable to
James J. Judge dated May 15, 1996
10.12 Boston Edison Company Restructuring
Settlement Agreement dated July 1997
</TABLE>
<PAGE> 60
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 12 Statement re Computation of Ratios
- ---------- ----------------------------------
Filed herewith:
<S> <C>
12.1 Computation of Ratio of Earnings
to Fixed Charges for the Year
Ended December 31, 1997
12.2 Computation of Ratio of Earnings
to Fixed Charges and Preferred Stock
Dividend Requirements for the Year
Ended December 31, 1997
Exhibit 21 Subsidiaries of the Registrant
- ---------- ------------------------------
21.1 Harbor Electric Energy Company
(incorporated in Massachusetts),
a wholly owned subsidiary of Boston
Edison Company
21.2 Boston Energy Technology Group, Inc.
(incorporated in Massachusetts),
a wholly owned subsidiary of Boston
Edison Company
</TABLE>
<PAGE> 61
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 23 Consent of Independent Accountants
- ---------- ----------------------------------
Filed herewith:
<S> <C> <C> <C>
23.1 Consent of Independent Accountants
to incorporate by reference their
opinion included with this Form
10-K in the Form S-3 Registration
Statements filed by the Company on
February 3, 1993 (File No. 33-57840),
May 31, 1995 (File No. 33-59693) and
in the Form S-8 Registration Statements
filed by the Company on October 10, 1985
(File No. 33-00810), July 28, 1986
(File No. 33-7558), December 31,
1990 (File No. 33-38434), June 5,
1992 (33-48424 and 33-48425), March 17,
1993 (33-59662 and 33-59682) and April 6,
1995 (33-58457) and in the Form S-4
Registration Statement filed by Boston
Edison Holdings, currently known as BEC
Energy, on March 17, 1997 (File No.
333-23439)
Exhibit 27 Financial Data Schedule
- ---------- -----------------------
Filed herewith:
27.1 Schedule UT
Exhibit 99 Additional Exhibits
- ---------- -------------------
Incorporated herein by reference:
99.1 Settlement Agreement between Boston 28.1 1-2301
Edison Company and Commonwealth Form 8-K
Electric Company, Montaup Electric dated
Company and the Municipal December 21,
Light Department of the Town of 1989
Reading, Massachusetts, dated
January 5, 1990
99.2 Settlement Agreement Between Boston 28.2 1-2301
Edison Company and City of Holyoke Form 10-Q
Gas and Electric Department et. al., for the
dated April 26, 1990 quarter ended
March 31, 1990
</TABLE>
<PAGE> 62
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C>
99.3 Information required by SEC Form 1-2301
11-K for certain Company employee Form 10-K/A
benefit plans for the years ended Amendments to
December 31, 1996, 1995 and 1994 Form 10-K for
the years ended
December 31,
1996, 1995 and
1994 dated
June 26,1997,
June 27, 1996
and June 29,
1995,
respectively
</TABLE>
<PAGE> 63
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
BOSTON EDISON COMPANY
By: /s/ James J. Judge
---------------------------------------
James J. Judge
Senior Vice President and Treasurer
(Principal Financial Officer)
Date: March 24, 1998
Pursuant to the requirements of the Securities Exchange Act of 1934 this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on the 24th day of March 1998.
<TABLE>
<S> <C>
/s/ Thomas J. May Chairman of the Board, President
- ---------------------------------- and Chief Executive Officer
Thomas J. May
/s/ Robert J. Weafer, Jr. Vice President - Finance,
- ---------------------------------- Controller and Chief Accounting
Robert J. Weafer, Jr. Officer
/s/ Gary L. Countryman Director
- ----------------------------------
Gary L. Countryman
/s/ Thomas G. Dignan, Jr. Director
- ----------------------------------
Thomas G. Dignan, Jr.
/s/ Richard J. Egan Director
- ----------------------------------
Richard J. Egan
/s/ Charles K. Gifford Director
- ----------------------------------
Charles K. Gifford
/s/ Nelson S. Gifford Director
- ----------------------------------
Nelson S. Gifford
/s/ Matina S. Horner Director
- ----------------------------------
Matina S. Horner
<PAGE> 64
/s/ Sherry H. Penney Director
- ----------------------------------
Sherry H. Penney
/s/ Herbert Roth, Jr. Director
- ----------------------------------
Herbert Roth, Jr.
/s/ Stephen J. Sweeney Director
- ----------------------------------
Stephen J. Sweeney
</TABLE>
<PAGE> 65
Report of Independent Accountants
To the Stockholders and Directors of Boston Edison Company:
We have audited the consolidated financial statements of Boston Edison Company
and subsidiaries (the Company) listed in Item 14(a) of this Form 10-K. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position
of the Company as of December 31, 1997 and 1996, and the consolidated results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
January 22, 1998
<PAGE> 1
SECOND AMENDMENT TO
REVOLVING CREDIT AGREEMENT
This SECOND AMENDMENT, dated as of July 1, 1997, by and among (a) Boston
Edison Company (the "Borrower"), a Massachusetts corporation, (b) each of the
Banks named on the signature pages hereof (collectively, the "Banks"), (c)
BankBoston, N.A. (f/k/a The First National Bank of Boston) and Citibank,
N.A., as co-agents (collectively, the "Agents") and (d) BankBoston, N.A. as
administrative agent (the "Administrative Agent").
WHEREAS, the Borrower, the Banks, the Agents and the Co-Agents are
parties to that certain Revolving Credit Agreement dated as of February 12,
1993, as amended and in effect on the date hereof (the "Credit Agreement");
and
WHEREAS, the Borrower has requested and the Banks have agreed, subject to
the terms and conditions set forth herein, to modify certain provisions of the
Credit Agreement;
WHEREAS, the Borrower wishes to appoint Citibank, N.A. as the
Documentation Agent under the Credit Agreement and Citibank wishes to accept
such appointment;
NOW, THEREFORE, the Borrower, the Banks, the Agents and the
Administrative Agent hereby covenant and agree as follows:
1. Defined Terms. Capitalized terms which are used herein without
-------------
definition and which are defined in the Credit Agreement shall have the same
meanings herein as in the Credit Agreement.
2. Citibank as Documentation Agent. The Borrower hereby appoints
-------------------------------
Citibank, N.A. to act as Documentation Agent under the Credit Agreement and
Citibank, N.A. hereby accepts such appointment. All references to the
"Agents" in the Credit Agreement shall be deemed to include a reference to
Citibank, N.A. in its capacity as Documentation Agent.
3. Amendment to Section 1 - Definitions. Section 1 of the Credit
------------------------------------
Agreement is hereby amended as follows:
(a) The definition of "Balance Sheet Date" is hereby amended by
substituting "December 31, 1996" for "December 31, 1994" therein.
(b) The definition of "DPU Approval" is hereby amended and restated in
its entirety as follows:
<PAGE> 2
DPU Approval. An appropriate order of the DPU authorizing the
--- --------
incurrence of indebtedness (i) after December 31, 1998 (for
purposes of satisfying the Extension Conditions) or (ii) after
the DPU Final Incurrence Date, in each case payable more than one
year after the date of incurrence, such order to contain no
condition inconsistent with the provisions hereof or reasonably
unacceptable to the Majority Banks.
(c) The definition of "Eurodollar Rate" is hereby amended by
substituting the phrase "the Applicable Margin then applicable" for the phrase
"the applicable margin determined pursuant to 2.6 hereof, for such period".
(d) The definition of "Extension Conditions" is hereby amended by
substituting the date "December 31, 1998" for the date "December 31, 1996"
therein;
(e) The definition of "Extension Date" is hereby amended by
substituting the date "December 31, 1998" for the date "December 31, 1996"
therein;
(f) The definition of "Facility Fee Rate" is hereby amended and
restated in its entirety to read as follows:
Facility Fee Rate. For each day prior to the Termination Date,
-----------------
the Facility Fee Rate shall be that rate set forth in the table
below beneath the unsecured debt rating of Standard & Poor's
Corporation and Moody's Investor Service, Inc. applicable on such
date to the Borrower's outstanding unsecured debentures or other
unsecured debt; provided that (a) if one of Standard & Poor's
--------
Corporation or Moody's Investor Service, Inc. does not rate such
debentures or other debt, the Facility Fee Rate for such date
shall be determined in accordance with the table below by
reference to the unsecured debt rating of the other referenced
rating company and if Duff & Phelps Corporation rates such
debentures or other debt, the comparable unsecured debt rating of
Duff & Phelps Corporation applicable to such debentures or other
debt and (b) in the event of a split rating between the Standard
& Poor's Corporation and Moody's Investor Service, Inc. or, if
applicable, between one of such rating companies and Duff & Phelps
Corporation, the lower rating shall apply:
<TABLE>
<CAPTION>
Unsecured Debt
Rating equal Unsecured Debt Unsecured Debt
to or better Rating equal Rating
than: to lower than:
S&P: BBB S&P: BBB- S&P: BBB-
Moody's: Baa2 Moody's: Baa3 Moody's: Baa3
-------------- -------------- --------------
<S> <C> <C> <C>
Facility Fee Rate 0.125% 0.150% 0.200%
</TABLE>
<PAGE> 3
(g) The definition of "FERC Approval" is hereby amended and restated
in its entirety to read as follows:
FERC Approval. The order of the FERC dated June 4, 1996
---- --------
authorizing the Borrower to incur, on or before December 31, 1998,
short-term indebtedness with a final maturity date not later than
December 31, 1999.
(h) The definition of "Termination Date" is hereby amended and
restated in its entirety to read as follows:
Termination Date. May 15, 2000; provided that if all of the
----------- ---- --------
Extension Conditions have not been complied with on or prior to
December 31, 1998, the Termination Date shall be December 30,
1999; provided, further, that if the Extension Conditions have
--------- -------
been complied with but the DPU Approval delivered to satisfy the
Extension Conditions provides for a DPU Final Incurrence Date
prior to May 15, 2000, the Termination Date shall be the earlier
to occur of the date which is 364 days following the DPU Final
Incurrence Date specified in such DPU Approval or May 15, 2000;
provided, further, that if the Second Extension Conditions have
--------- -------
been complied with but the DPU Approval delivered to satisfy the
Second Extension Conditions provides for a Second DPU Final
Incurrence Date prior to May 15, 2000, the Termination Date shall
be the earlier to occur of the date which is 364 days following
the Second DPU Final Incurrence Date specified in such DPU
Approval or May 15, 2000. Notwithstanding the foregoing, the
Termination Date shall be May 15, 2000 with respect to any
outstanding Loans incurred pursuant to a DPU Approval authorizing
such Loans.
(i) Section 1 of the Credit Agreement is hereby amended by inserting
the following new definition in appropriate alphabetical order:
Applicable Margin. For each day during which any Eurodollar Loan
-----------------
is outstanding, the Applicable Margin shall be that rate set forth
in the table below beneath the unsecured debt rating of Standard
& Poor's Corporation and Moody's Investor Service, Inc. applicable
on such date to the Borrower's outstanding unsecured debentures or
other unsecured debt, provided that (a) if one of Standard &
--------
Poor's Corporation or Moody's Investor Service, Inc. does not rate
such debentures or other debt, the Applicable Margin for such
date shall be determined in accordance with the table below by
reference to the unsecured debt rating of the other referenced
rating company and if Duff & Phelps Corporation rates such
debentures or other debt, the comparable unsecured debt rating of
Duff & Phelps Corporation applicable to such debentures or other
debt and (b) in the event of a split rating between the Standard
& Poor's Corporation and Moody's Investor Service, Inc. or, if
applicable, between one of such rating companies and Duff & Phelps
Corporation, the lower rating shall apply:
<PAGE> 4
<TABLE>
<CAPTION>
Unsecured Debt
Rating equal Unsecured Debt Unsecured Debt
to or better Rating equal Rating
than: to lower than:
S&P: BBB S&P: BBB- S&P: BBB-
Moody's: Baa2 Moody's: Baa3 Moody's: Baa3
-------------- -------------- --------------
<S> <C> <C> <C>
Applicable Margin 0.25% 0.30% 0.40%
</TABLE>
4. Amendment to Section 2.1. - Commitment to Lend Syndicated Loans.
--------- -- ------- ---- ---------- -- ---- ---------- ------
Section 2.1(c) of the Credit Agreement is hereby amended and restated in its
entirety as follows:
(c) Each Bank's Commitment Percentage and, subject to the
provisions of 2.1(a) above, the amount of its Commitment, shall be
as follows:
<TABLE>
<CAPTION>
Amount of Commitment
Bank Commitment Percentage
---- ---------- ----------
<S> <C> <C>
BankBoston, N.A. $40,000,000 20.0%
(f/k/a The First National Bank of Boston)
Citibank, N.A. $40,000,000 20.0%
The First National Bank of Chicago $25,000,000 12.5%
The Bank of New York $20,000,000 10.0%
Fleet National Bank $30,000,000 15%
Bank of Montreal $10,000,000 5.0%
The Bank of Nova Scotia $20,000,000 10.0%
State Street Bank and Trust Company $15,000,000 7.5%
------------ ------
Total $200,000,000 100%
</TABLE>
5. Amendment to Section 2.6 - Interest Period. Section 2.6 of the
--------- -- ------- --- -------- ------
Credit Agreement is hereby amended and restated in its entirety as follows:
2.6. Interest. Except as otherwise increased pursuant
--------
to 2.7, the unpaid principal amount of the Loans outstanding from
time to time shall bear interest, and the Borrower absolutely and
unconditionally promises to pay interest on the Loans extended to
the Borrower, calculated as follows:
(a) for Alternate Base Rate Loans, at a rate per annum
equal to the Alternate Base Rate in effect from time to time;
<PAGE> 5
(b) for the Eurodollar Loans, at a rate per annum equal
to the sum of (A) the Euro Rate for the relevant Interest Period
plus (B) the Applicable Margin then in effect;
----
(c) with respect to Competitive Bid Loans, at the rate
per annum specified in the applicable Competitive Bid Quote with
respect to such Competitive Bid Loan.
Any change in the interest rate resulting from a change in
the Alternate Base Rate is to be effective at the beginning of the
day of such change. Changes in the interest rate occasioned by
changes in the Applicable Margin shall be effective as of the day
of the applicable changes in the debt ratings on which the
Applicable Margin is based. So long as any Alternate Base Rate
Loan is outstanding, the Administrative Agent will give the
Borrower and each of the Banks prompt notice in writing of each
change in the Alternate Base Rate. Interest with respect to each
Fixed Rate Loan shall be payable in arrears on the last day of the
Interest Period relating thereto and also, in the case of any
Fixed Rate Loan having an Interest Period of more than three
months, at the end of each three-month period during such Interest
Period. Interest with respect to each Alternate Base Rate Loan
shall be payable quarterly in arrears on the last Business Day of
each March, June, September and December and at maturity.
6. Amendment to Section 4.2 - Government Approvals. Section 4.2 of
--------- -- ------- --- ---------- ---------
the Credit Agreement is hereby amended and restated in its entirety as
follows:
Except for (i) obtaining DPU approval authorizing the incurring of
indebtedness after December 31, 1998 (or such later date as shall
be specified therefor in the DPU Approval) pursuant to this
Agreement payable more than one year after the date of incurrence
thereof and (ii) obtaining approval of the Federal Energy
Regulatory Commission ("FERC") authorizing the incurring of short-
term indebtedness pursuant to this Agreement after December 31,
1998 (or such later date as shall be specified therefor in any
extension of the FERC Approval), the execution, delivery and
performance by the Borrower of this Agreement and the notes and
the transactions contemplated hereby and thereby do not require
the approval or consent of, or filing with, any governmental
agency or authority other than those already obtained or made and
in full force and effect.
7. Amendment to Section 4.3 - Financial Statements. Section 4.3 of
--------- -- ------- --- --------- ----------
the Credit Agreement is hereby amended by substituting the date "December 31,
1996" for the date "December 31, 1994" therein and by deleting the second
sentence thereof.
8. Amendment to Section 4.6 - Litigation. Section 4.6 of the Credit
--------- -- ------- --- ----------
Agreement is hereby amended by substituting the date "December 31, 1996" for
the date "December 31, 1994" therein.
<PAGE> 6
9. Amendment to Section 4.7 - Compliance with Other Instruments,
--------- -- ------- --- ---------- ---- ----- ------------
Laws, Etc. Section 4.7 of the Credit Agreement is hereby amended by
- ----- ----
substituting the date "December 31, 1996" for the date "December 31, 1994"
therein.
10. Amendment to Section 4.11 - Holding Company and Investment
--------- -- ------- ---- ------- ------- --- ----------
Company Acts. Section 4.11 of the Credit Agreement is hereby amended by
- ------- ----
substituting the phrase "registered holding company" for the phrase "holding
company" in the second sentence thereof.
11. Amendment to Section 5.8 - Compliance with Laws, Contracts,
--------- -- ------- --- ---------- --- ------ ----------
Licenses, and Permits. Section 5.8 of the Credit Agreement is hereby amended
- --------- --- -------
by substituting the date "December 31, 1996" for the date "December 31, 1994"
therein.
12. Amendment to Section 7.3 - Borrowings After December 31, 1998.
--------- -- ------- --- ---------- ----- -------- --- ----
Section 7.3 of the Credit Agreement is hereby amended and restated in its
entirety as follows:
7.3 Borrowings After December 31, 1998. (i) In the case of
---------- ----- -------- -- ----
each Loan made after December 31, 1998 and prior to the Extension
Date, the Borrower shall have received an extension of the FERC
Approval authorizing the Borrower to incur indebtedness on the
Drawdown Date for such Loan, (ii) if the Extension Conditions
shall have been satisfied, in the case of each Loan made after the
DPU Final Incurrence Date but prior to the Second Extension Date,
the Borrower shall have received an extension of the FERC Approval
authorizing the Borrower to incur indebtedness on the Drawdown
Date for such Loan, (iii) if the Second Extension Conditions shall
have been satisfied, in the case of each Loan made after the
Second DPU Final Incurrence Date, the Borrower shall have received
an extension of the FERC Approval authorizing the Borrower to
incur indebtedness on the Drawdown Date for such Loan, and (iv)
notwithstanding the foregoing, in the case of each Loan made after
May 15, 1999, the Borrower shall have received an extension of the
FERC Approval authorizing the Borrower to incur short-term
indebtedness on the Drawdown Date for such Loan, and, in the case
of each clause (i), (ii), (iii) and (iv), the Borrower shall
have delivered a copy of the applicable FERC Approval to the
Administrative Agent, or shall have delivered to the
Administrative Agent an opinion of Ropes & Gray, Borrower's
counsel, that such approval is not required.
13. Amendment to Section 15 - Notices. Section 15 of the Credit
--------- -- ------- -- -------
Agreement is hereby amended by substituting the name and title "Robert J.
Weafer, Jr., Vice President - Finance and Controller" for the name and title
"Marc S. Alpert, Treasurer" therein.
14. Conditions to Effectiveness. This Amendment shall become
---------- -- -------------
effective as of the date set forth above upon satisfaction of the following
conditions:
(a) the execution of this Amendment by the Company, the Agents
and the Banks;
(b) evidence satisfactory to the Agent and the Banks, that the
Board of Directors of the Borrower has approved this Amendment;
<PAGE> 7
(c) the delivery to the Banks from Messrs. Ropes & Gray,
counsel to the Borrower, a favorable legal opinion, dated as of the date
hereof, addressed to the Banks and substantially in the form of Exhibit A
------- -
hereto;
(d) the delivery to the Administrative Agent of an Assignment
and Acceptance, substantially in the form attached hereto as Exhibit B
------- -
and pursuant to which Swiss Bank Corporation has assigned its Commitment
Percentage, Commitment and any outstanding loans in equal parts to
BankBoston, N.A. and Citibank, N.A., together with the Notes held by
Swiss Bank Corporation; and
(e) the delivery to the Administrative Agent of an Assignment
and Acceptance substantially in the form attached as Exhibit C and
------- -
pursuant to which Bank of Montreal has assigned to Bank of Nova Scotia
one-third of its Commitment Percentage which equals $5,000,000 of its
Commitment and any related loans, together with the Syndicated Note,
held by Bank of Montreal.
15. No Other Amendments. Except as expressly provided in this
-- ----- ----------
Amendment, all of the terms and conditions of the Credit Agreement remain
unchanged, and the terms and conditions of the Credit Agreement as amended
hereby remain in full force and effect.
16. Execution in Counterparts. This Amendments may be executed in
--------- -- ------------
any number of counterparts and by each party on a separate counterpart, each
of which when so executed and delivered shall be an original, but all of which
together shall constitute one instrument. In proving this Amendment, it shall
not be necessary to produce or account for more than one such counterpart
signed by the party against whom enforcement is sought.
17. Miscellaneous. This Amendment shall be deemed to be a contract
-------------
under seal under the laws of The Commonwealth of Massachusetts and shall for
all purposes be construed in accordance with and governed by the laws of The
Commonwealth of Massachusetts. The captions in this Amendment are for
convenience of reference only and shall not define or limit the provisions
hereof.
<PAGE> 8
IN WITNESS WHEREOF, the parties have executed this Amendment as of the
date first above written.
BOSTON EDISON COMPANY
By: /s/ Donald Anastasia
---------------------------------------
Name: Donald Anastasia
Title: Assistant Treasurer
BANKBOSTON, N.A.
(f/k/a The First National Bank of Boston)
as Co-Agent and Administrative Agent
Exhibit 10.9.2
May 15, 1996
Mr. James J. Judge
Senior Vice President
and Treasurer
Boston Edison Company
800 Boylston Street
Boston, MA 02199
Dear Jim:
At its April 25, 1996 meeting, the Board of Directors voted to adopt a Special
Retention Program to provide particularly valued employees with an incentive
to remain in the employment of the Company during the next three-year period.
I am pleased to inform you that the directors agreed with my assessment that
your contributions will be very important to the success of the Company during
this critical time.
Under the terms of the Agreement adopted by the Board, if you remain
continuously in the employment of the Company through December 31, 1998, the
Company will pay you an amount equal to the difference between the Performance
Share Plan award which the Board determines to award you in January, 1999, if
any, and $50,000. The net effect of this program is to guarantee you, if you
stay for the required period, a long-term incentive plan bonus in January of
1999 which will be no less than $50,000.
I look forward to, and depend upon, your assistance over the next three years
in positioning the Company to thrive in the new industry environment.
Sincerely,
/s/ Thomas J. May
- --------------------------
Thomas J. May
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF PUBLIC UTILITIES
)
Electric Utility Industry ) D.P.U. Docket Nos.
Restructuring ) 96-100 and 96-23
)
BOSTON EDISON COMPANY
RESTRUCTURING SETTLEMENT AGREEMENT
DATED: JULY 1997
<PAGE>
BOSTON EDISON
Executive Offices
800 Boylston Street
Boston, Massachusetts 02199
Douglas S. Horan (617) 424-2635
Senior Vice President and General Counsel Fax (617) 424-2733
July 8, 1997
Ms. Mary L. Cottrell
Secretary
Department of Public Utilities
100 Cambridge Street - 12th flr
Boston, Massachusetts 02202
Re: Boston Edison Company
DPU 96-100 and DPU 96-23
Dear Secretary Cottrell:
I am pleased to forward to you for filing with the Department a
Restructuring Settlement Agreement entered into between Boston Edison Company,
Massachusetts Attorney General Scott Harshbarger, the Massachusetts Division
of Energy Resources, and Alternate Power Source, American National Power,
Citizens Power, Competitive Power Coalition, Conservation Law Foundation,
Consumer Advisory Panel, Greater Boston Chamber of Commerce, Intercontinental
Energy Corp., Massachusetts High Technology Council, Northeast Energy and
Commerce Association, Northeast Energy Efficiency Council, Polaroid
Corporation, Retailers Association of Massachusetts, The Energy Consortium,
U.S. Generating Company. Also enclosed for filing is a Joint Motion of the
Parties to the Settlement requesting that the Department approve this
Settlement by September 15, 1997. I have provided a brief description of the
key elements of the Settlement below. We assume the Department will hold
public hearings on this Settlement. At that time we will make available
various individuals to address the provisions of this Settlement in more
detail.
General Overview
The Settlement is designed to provide a resolution of issues presented in
the industry restructuring Docket Nos. D.P.U. 96-100 and D.P.U. 96-23. Once
approved by the Department, this Settlement will require a restructuring of
Boston Edison in furtherance of the competitive market structure objectives of
the Department and will implement, Consumers First, the restructuring plan of
the Attorney General as applied to Boston Edison. The Settlement includes a
commitment by Boston Edison to voluntarily
<PAGE>
Ms. Mary L. Cottrell
July 8, 1997
Page 2
divest its generation business, except for Pilgrim Station, through a sale or
spin-off of 100 percent of that business. It also requires the Company to use
its best efforts to dispose of its above-market purchase power contracts. In
consideration for these and other commitments the Settlement assures Boston
Edison's recovery of 100% of its stranded costs.
This Settlement also resolves certain ratemaking issues before the
Department for Boston Edison and assures that Boston Edison's rates to retail
customers comply fully with the requirements of the Attorney General's
principles. In particular, each customer will receive a 10 percent decrease
in rates. Boston Edison also maintains its strong commitment to Demand Side
Management and renewables by fixing budgets totaling nearly $210 million over
the next four years. Finally, this Settlement resolves certain other issues
necessary to implement retail choice for Boston Edison's customers on the
Retail Access Date, which is defined as the later of January 1, 1998 or the
date when retail access is made available to all customers of the investor-
owned utilities in Massachusetts.
Generation Assets and Purchased Power Contracts
The Settlement sets out a comprehensive approach for the valuation and
divestiture of the Company's generation assets, including its purchased power
contracts.
In regards to its fossil generating facilities the Settlement requires
that the Company divest those assets. Within ten days of filing this
Settlement Agreement with the Department, the Company will file with the
Department, for informational purposes only, a detailed plan for the sale of
it non-nuclear generation assets. The plan calls for the Company to hold an
auction of its various facilities, with the Department reviewing and approving
the final sales agreement when they are executed. It is the Company's goal to
close on these sales before the end of 1997.
There is no requirement that the Company divest Pilgrim, its only nuclear
asset. However, the Company has agreed to submit a plan to the Department by
January 1, 1999, establishing a process by which a market valuation of Pilgrim
will be completed by the end of 2002. During the first three years of
operation following the Retail Access Date, Boston Edison will assume 75% of
the risk of Pilgrim's operation. Following that period the Company will
assume 100% of that risk. In addition, various performance standards will be
imposed on Pilgrim's operation.
<PAGE>
Ms. Mary L. Cottrell
July 8, 1997
Page 3
In regards to power purchase contracts, the Company has agreed to
endeavor to try to terminate or to reduce its obligations under these
contracts. To this end it will file a plan with the Department by July 1,
1998, setting forth its strategies for achieving this objective.
RETAIL RATES
Boston Edison will freeze its base rates until the Retail Access Date,
provided that date occurs prior to January 1, 2001. Prior to the Retail
Access Date, Boston Edison will unbundle its retail rates in accordance with
its filing and the Department's order in Docket No. DPU 97-40. The fuel
charge will remain in effect on a fully reconciling basis and the Company's
New Performance Adjustment Charge and Generating Unit Performance Program
requirements also will remain in effect.
Following the Retail Access Date, the Company's rates will consist of a
distribution charge, a transmission charge, an access charge and a standard
offer service charge.
The distribution charge will remain in effect until at least January 1,
2001. It will contain provisions for performance based penalties based on
customer satisfaction and distribution system reliability. The Company has
created a storm fund of $8 million, which will be funded initially from the
proceeds of the sale of certain clean air credits. There also is a rate of
return collar. The Company is able to increase its ROE should it fall below
6% and will share with customers any amount in excess of 11%. The low income
discount of 40% will remain in effect and the Company will protect against
redlining by paying suppliers of low income customers directly for power
delivered up to the standard offer prices.
The transmission charge will be designed to collect all of the Company's
FERC approved transmission costs. It will be collected on a fully reconciling
basis. In addition, the Company will be allowed to collect transmission
congestion costs, so long as they are not accounted for in other charges.
The access charge is designed to collect 100% of the Company's stranded
costs. It will consist of fixed and variable components. The fixed
components include primarily unrecovered net book value of generation plant
and generation-related regulatory assets. The net proceeds of fossil
divestiture, Pilgrim valuation and transfer of purchase power contracts will
be credited to the fixed portion of the access charge. The variable component
of the access charge will include primarily nuclear decommissioning costs,
above-market purchased power contracts, above market fuel transportation
contracts,
<PAGE>
Ms. Mary L. Cottrell
July 8, 1997
Page 4
payments in lieu of property taxes and employee severance and retirement
costs. The access charge will remain in effect for 12 years, except that
above market purchase power contracts and nuclear decommissioning will be
collected over a longer period, as costs are incurred. It will be fixed at
3.51 cents per kWh for 1998 and will decline thereafter, with a maximum charge
in 1999 and 2000 of 3.35 cents per kWh. The charge will be updated annually
effective January 1 of each year.
Standard Offer Service will be available to retail customers as of the
Retail Access Date and will remain available for 7 years. Once a customer
leaves the Standard Offer he or she may not return, except for residential and
small commercial customers, who may return within 90 days of leaving during
the first year following the Retail Access Date. The Standard Offer Rates are
fixed at the following levels for the years indicated:
<TABLE>
<CAPTION>
Calendar Year Average Price per kilowatthour
------------- ------------------------------
<S> <C>
1998 2.8 cents
1999 3.1 cents
2000 3.4 cents
2001 3.8 cents
2002 4.2 cents
2003 4.7 cents
2004 5.1 cents
</TABLE>
The Company will put the Standard Offer out to bid. If the bid is not
100% subscribed, the Company will back up the standard offer using the
following resources on a least cost basis: existing power supply contracts,
its own fossil units so long as they are still available to the Company,
Pilgrim, and short-term market purchases. Differences between the market
price and the Standard Offer price will be reconciled through a surcharge to
the Standard Offer. The Standard Offer is available to all retail customers,
except for those retail customers currently being served under a special
contract.
PROTECTING THE ENVIRONMENT AND CONSERVATION
The Settlement requires the Company to impose more stringent standards
on its fossil units. In addition it commits the Company to spend over $200
million on DSM programs over the next four years. This amount includes
approximately $98 million for new DSM and $38.7 million for renewables. Also
included in these budgets is a commitment to spend at least 15% of the
residential budget on low income customers and to increase weatherization
and fuel assistance budgets from $935,000 in 1998 to $2.3
<PAGE>
Ms. Mary L. Cottrell
July 8, 1997
Page 5
million in 2001. The parties agree to work collaboratively on all DSM matters
and will file a plan with the Department consistent with these budgets on
September 1, 1997.
OTHER PROVISIONS
As part of the Settlement the Company agrees to support NEPOOL reform
consistent with the proposal filed at the FERC by NEPOOL in December 1996. We
also agree to support efforts to develop a fully functioning wholesale market
in New England. The Settlement calls upon the Department to make the
necessary findings to permit Boston Edison to attain EWG status. The parties
also agree to support Boston Edison's request, if and when made to the
Department, to invest up to an additional $150 million in Boston Edison's
subsidiary BETG. In addition the parties have developed an informal dispute
resolution mechanism which calls for the exchange of relevant information
prior to the Company' filing for a change in the access charge.
ATTACHMENTS
Included in this filing are the following documents:
A Joint Motion Requesting Approval of the Settlement
Restructuring Settlement Agreement
Attachment 1 Retail Delivery Rates and Supporting Documentation
Attachment 2 Storm Fund Protocols
Attachment 3 Formula for Calculating Access Charges
Attachment 4 Term Sheet for Bidding Standard Offer Service including
Fuel Index
Attachment 5 Performance Standards Under Retail Access Tariffs
Attachment 6 Environmental Plan
Attachment 7 Jurisdictional Separation of Transmission and Distribution
Facilities Pursuant to FERC Order 888
<PAGE>
Ms. Mary L. Cottrell
July 8, 1997
Page 6
For the convenience of the Department and other interested parties,
we have also posted a copy of this filing on our web site at
http://www1.bedison.com. To read the filing, you will have to download
the Free Adobe Acrobat Reader available at the web site.
The parties urge the Department to approve the Settlement as
expeditiously as possible. We look forward to discussing this in more
detail with you and other interested parties.
Thank you for your attention to this matter. If you have any questions,
please do not hesitate to call.
Very truly yours,
/s/ Douglas S. Horan
cc: John B. Howe, Chairman
Janet Gail Besser, Commissioner
Alicia Matthews, Hearing Officer
George B. Dean, Esq.
David L. O'Connor, Commissioner DOER
Mary Beth Gentleman, Esq.
<PAGE>
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF PUBLIC UTILITIES
)
Electric Utility Industry ) D.P.U. Docket Nos.
Restructuring ) 96-100 and 96-23
)
BOSTON EDISON COMPANY
RESTRUCTURING SETTLEMENT AGREEMENT
DATED: JULY 1997
<PAGE> 001
TABLE OF CONTENTS
<TABLE>
<S> <C>
Joint Motion for Approval of Offer of Settlement 002
Restructuring Settlement Agreement 020
Attachment 1 Unbundled Rates and Supporting Documentation 073
Attachment 2 Storm Fund 223
Attachment 3 Formula for Calculating Access Charges 226
Attachment 4 Term Sheet For Bidding Standard Offer 257
Service Including Fuel Index
Attachment 5 Performance Standards Under Retail Access Tariffs 265
Attachment 6 Environmental Plan for Industry Restructuring 269
Attachment 7 Jurisdictional Separation of Transmission and 276
Distribution Facilities Pursuant to FERC Order 888
</TABLE>
<PAGE>
JOINT MOTION FOR APPROVAL OF OFFER OF SETTLEMENT
<PAGE> 002
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF PUBLIC UTILITIES
_________________________________________
)
Electric Utility Industry Restructuring ) D.P.U. Docket Nos. 96-100
_________________________________________ ) and 96-23
JOINT MOTION FOR
APPROVAL OF OFFER OF SETTLEMENT
-------------------------------
The undersigned hereby move that the Department of Public Utilities
approve by September 15, 1997, the attached Offer of Settlement
("Settlement"). The Settlement has been agreed to by the undersigned
parties. To the extent that the Department or members of the staff have
questions concerning any terms of the Settlement, the undersigned parties
request a hearing and Boston Edison Company agrees to make witnesses
available.
Respectfully submitted,
\s\ Douglas S. Horan
-----------------------------------------
Douglas S. Horan, Esq.
Senior Vice President and General Counsel
Boston Edison Company
800 Boylston Street
Boston, Massachusetts 02199
July 8, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ George B. Dean
----------------------------------------------
Name: George B. Dean
Title: Assistant Attorney General,
Chief, Regulated Industries Division
Address: Office of the Attorney General
200 Portland Street
Boston, MA 02114
July 9, 1997
<PAGE> 004
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ David L. O'Connor
----------------------------------------------
Name: David L. O'Connor
Title: Commissioner
Address: Commonwealth of Massachusetts
Division of Energy Resources
100 Cambridge Street, Room 1500
Boston, MA 02202
July 8, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Stephen M. Tulega
----------------------------------------------
Name: Stephen M. Tulega
Title: President
Address: Alternate Power Source
200 Clarendon St. - T-32
Boston, MA 02116
June 26, 1997
<PAGE> 006
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Joseph S. Fitzpatrick
----------------------------------------------
Name: Joseph S. Fitzpatrick
Title: Senior Vice President
Address: American National Power
108 National Street
Milford, MA 01757
June 25, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Eugenia Balodimas
----------------------------------------------
Name: Eugenia Balodimas
Title: Associate Counsel - Director of
Regulatory and Legislative Affairs
Address: Citizens Power - The Energy Group
160 Federal Street
Boston, MA 02110-1766
June 26, 1997
<PAGE> 008
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Neal B. Costello
----------------------------------------------
Name: Neal B. Costello, Esq.
Title: Executive Director
Address: Competitive Power Coalition
9 Park Street - 5th flr.
Boston, MA 02108
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Lewis Milford
----------------------------------------------
Name: Lewis Milford
Title: Director, Energy Project
Address: Conservation Law Foundation
21 East State Street
Montpelier, VT -5602
June 26, 1997
<PAGE> 010
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Judy Massey
----------------------------------------------
Name: Judy Massey
Title: Chair, Consumer Advisory Panel
Address: c/o Boston Edison Company
800 Boylston Street
Boston, MA 02199
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Paul Guzzi
----------------------------------------------
Name: Paul Guzzi
Title: President and Chief
Executive Officer
Address: Greater Boston
Chamber of Commerce
One Beacon Street
Boston, MA 02108
June 26, 1997
<PAGE> 012
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Ellen S. Roy
----------------------------------------------
Ellen S. Roy
Executive Vice President
Intercontinental Energy Corporation
350 Lincoln Place
Hingham, MA 02043
June 27, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Howard Foley
----------------------------------------------
Name: Howard Foley
Title: President
Address: Massachusetts High Technology Council
1601 Trapelo Road
Waltham, MA 02154
June 26, 1997
<PAGE> 014
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ William C. Sheehan
----------------------------------------------
Name: William C. Sheehan
Title: President
Address: Northeast Energy and Commerce Association
c/o Financial Management Group
P.O. Box 9116-165
Concord, MA 91742-9116
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Paul W. Gromer
----------------------------------------------
Name: Paul W. Gromer
Title: Attorney for
Address: Northeast Energy Efficiency Council
77 North Washington Street
Boston, MA 02114
June 25, 1997
<PAGE> 016
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Roger Borghesani
----------------------------------------------
Name: Roger Borghesani
Title: Chairman, Corporate Energy Council
Address: Polaroid Corporation
1265 Main Street, W2-MA
Waltham, MA 02254
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Jon B. Hurst
----------------------------------------------
Name: Jon B. Hurst
Title: President
Address: Retailers Association of Massachesetts
18 Tremont Street, Suite 702
Boston, MA 02108
June 26, 1997
<PAGE> 018
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Bruce Paul
----------------------------------------------
Name: Bruce Paul
Title: Chairperson
Address: The Energy Consortium
42 Labor in Vain Road
Ipswich, MA 01938
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Motion for Approval of Settlement 96-23
\s\ Douglas F. Egan
----------------------------------------------
Name: Douglas F. Egan
Title: Sr. Vice President
Address: U. S. Generating Company
One Bowdoin Square
Boston, MA 02114
June 26, 1997
<PAGE>
RESTRUCTURING SETTLEMENT AGREEMENT
<PAGE> 020
COMMONWEALTH OF MASSACHUSETTS
DEPARTMENT OF PUBLIC UTILITIES
)
Electric Utility Industry Restructuring ) D.P.U. Docket Nos. 96-100
) and 96-23
RESTRUCTURING SETTLEMENT AGREEMENT
This Restructuring Settlement Agreement ("Settlement") is jointly
sponsored by the Office of the Attorney General ("Attorney General"), the
Massachusetts Division of Energy Resources ("DOER"), Alternate Power Source,
American National Power, Citizens Power, Competitive Power Coalition,
Conservation Law Foundation, Consumer Advisory Panel, Greater Boston Chamber
of Commerce, Intercontinental Energy Corp., Massachusetts High Technology
Council, Northeast Energy and Commerce Association, Northeast Energy
Efficiency Council, Polaroid Corporation, Retailers Association of
Massachusetts, The Energy Consortium, U.S. Generating Company and Boston
Edison Company ("Boston Edison"). The Settlement is designed to provide a
resolution of some issues presented in the industry restructuring Docket Nos.
D.P.U. 96-100 (the Massachusetts Department of Public Utilities'
("Department")) generic
<PAGE>
proceeding on electric utility restructuring) and D.P.U. 96-23 (Boston
Edison's own restructuring proceeding). This Settlement, once approved by
the Department, would require a restructuring of Boston Edison in furtherance
of the competitive market structure objectives of the Department and would
implement, Consumers First, the restructuring plan of the Attorney General as
applied to Boston Edison. The Settlement includes a commitment by Boston
Edison to voluntarily divest its generation business, except as provided in
section V.C.2.(b) and subject to the provisions of section V.C.3 of this
Settlement, through a sale or spin-off of 100 percent of that business, and
the assurance of stranded cost recovery by Boston Edison. This Settlement
also resolves certain ratemaking issues before the Department for Boston
Edison and assures that Boston Edison's rates to retail customers comply fully
with the requirements of the Attorney General's principles. Finally, this
Settlement resolves certain other issues necessary to implement retail choice
for Boston Edison's customers on the Retail Access Date, which is defined as
the later of January 1, 1998 or the date when retail access is made available
to all customers of the investor-owned utilities in Massachusetts.
The parties to this Settlement recognize and fully understand that their
mutual promises in this Settlement evidence the consideration they have
extended to each other in their efforts to settle the issues of D.P.U. 96-23
in accordance with the principles articulated in D.P.U. 96-100. The
willingness and ability of Boston Edison to commit to and fulfill any and all
of its obligations under this Settlement, including in particular the full
divestiture of its generating business, except as provided in section
V.C.2.(b) and subject to the provisions of section V.C.3 of this Settlement,
are predicated and conditioned upon the commitments by the Attorney General
and the Department to the recovery in full of Boston Edison's stranded costs,
as set forth in this Settlement. The Settlement is designed to implement the
Attorney General's principles for
<PAGE> 022
electric industry restructuring in Massachusetts in a manner that is
consistent with the proposals articulated by the Department in its orders in
D.P.U. 96-100. It is further designed to insure recovery of Boston Edison's
access charge as part of its transition from a fully bundled, completely
regulated electric utility to an unbundled delivery company in an emerging
competitive industry.
The Settlement follows the outline of the Attorney General's principles. The
parties have agreed on the following:
I. Price Reductions for Customers
------------------------------
Implementation of the Attorney General's principles will produce reduced rates
for all retail customers on the Retail Access Date. Under the Settlement,
Boston Edison will freeze base rates prior to the Retail Access Date and will
collect from or credit to retail customers any increases or decreases in New
Performance Adjustment Clause ("NPAC") recovery authorized by DPU 89-100. In
addition, Boston Edison will credit to customers any decreases that may arise
out of refunds from Boston Edison's generating unit performance ("GUPP")
review cases, both those cases currently pending before the Department (Docket
Nos. DPU 96-1-A and DPU 97-1-A) and those future GUPP cases covering the
period from November 1, 1996 to the Retail Access Date pursuant to
G.L. c. 164, 94G. Subject to the provisions of Section I.B.2(f), effective
on the Retail Access Date, Boston Edison will reduce its rates to all
customers by 10 percent and will provide retail delivery tariffs with a
standard offer option. Such tariffs are included in Attachment 1.
<PAGE>
I.A. The Unbundled Rates Effective Until the Retail Access Date
----------------------------------------------------------
Effective July 1, 1997 Boston Edison will unbundle its retail rates in
accordance with the filing it made with the Department on March 3, 1997 in
Docket No. DPU 97-40.
I.A.1. Boston Edison's fuel and purchased power clause will continue to
be subject to the requirements of G.L. c. 164, 94G and operate as a fully
reconciling charge during the effective period of the unbundled rates.
I.A.2. Boston Edison's unbundled rates will be used for billing
purposes to provide information to customers. Further information, including
market price estimates based upon estimates of variable energy and capacity
costs will be made available to any customer upon request.
I.A.3. The unbundled rates shall remain in effect for all usage prior
to the Retail Access Date, subject to refunds from Boston Edison's GUPP review
cases, Section I.C, below, and any authorized NPAC charges. The fuel
adjustment factor shall be applied to billings after the Retail Access Date
for usage occurring before the Retail Access Date. The final fuel factor
balances remaining after the Retail Access Date shall be returned to or
collected from customers in the first quarter after the Retail Access Date
such final balances shall include any adjustments required to be made as the
result of the Department's issuance of a GUPP order or orders covering the
period from November 1, 1995 though the Retail Access Date.
I.A.4. Effective on April 1, 1997, Boston Edison shall close, or cease
to offer, to new customers its Manufacturing Retention Rate.
<PAGE> 024
I.B. Retail Delivery Rates and the Standard Offer Effective from the
---------------------------------------------------------------
Retail Access Date Through December 31, 2000
--------------------------------------------
The retail delivery rates included in Attachment 1 shall become effective
for usage on and after the Retail Access Date on the following terms.
I.B.1. Retail Delivery Charges
-----------------------
Boston Edison's retail delivery rates included in Attachment 1 include
four components. The distribution and access charges will be included in a
delivery service charge, the transmission charges will be billed in a separate
transmission cost adjustment charge, and the standard offer charges will be
billed separately to customers taking standard offer service. The four
components are as follows:
I.B.1.(a) Distribution charges These charges will remain in
--------------------
place through December 31, 2000 and may be superseded by a filing that becomes
effective, after suspension, on January 1, 2001. Performance standards are
also established for reliability and customer satisfaction in the distribution
component of the rate with credits to customers if the standards are not
achieved;
I.B.1.(b) Transmission charges These charges will recover on a
--------------------
fully reconciling basis the transmission charges to Boston Edison's retail
customers under Boston Edison's FERC approved transmission tariffs, together
with the charges, if any, billed to Boston Edison by or for the benefit of a
Regional Transmission Group, an Independent System Operator, any other
transmission provider, or any regional entity that may be created or allowed
to implement rates and tariffs for transmission or reliability related
operating services under FERC accepted tariffs and shall include any other
charges relating to the stability of the transmission system which Boston
Edison is authorized to recover from retail customers by order of the
<PAGE>
regulatory agency having jurisdiction over such charges. However, under no
circumstances shall the amount included in these charges recover costs which
are collected by Boston Edison in some other rate or charge.
I.B.1.(c) Access Charges These charges are designed to recover
--------------
on a fully reconciling basis all of Boston Edison's stranded costs. As set
forth more fully below, the access charges for each rate class will total 3.51
cents per kilowatthour for 1998, and 3.35 cents per kilowatthour for 1999 and
2000, subject to the residual value credit as provided for in Attachment 3,
and will decline thereafter. The access charges are subject to adjustment for
various factors included in Section I.B.4, below.
I.B.1.(d) Standard Offer A standard offer for service during a
--------------
transition period is fixed on the following schedule for the period from the
Retail Access Date through December 31, 2004, subject only to the conditions
contained in Section I.B.5, and Attachment 4.
<TABLE>
<CAPTION>
Calendar Year Average Price per kilowatthour
------------- ------------------------------
<S> <C>
1998 2.8 cents
1999 3.1 cents
2000 3.4 cents
2001 3.8 cents
2002 4.2 cents
2003 4.7 cents
2004 5.1 cents
</TABLE>
Together, the charges in paragraphs (a) through (d) of Section I.B.1
comply with the Attorney General's principles relating to rates and prices.
The details of each charge included in the rates and the changes to the terms
and conditions are set forth in the paragraphs below.
<PAGE> 026
I.B.2. Distribution Charges
--------------------
The distribution charges in the retail delivery rates will become
effective on the Retail Access Date and will remain in effect through
December 31, 2000 on the following terms.
I.B.2.(a) The distribution depreciation rates approved in DPU
92-92 of 2.38% shall be increased to 2.98% as of the Retail Access Date.
I.B.2.(b) Boston Edison shall be authorized to establish a
storm fund to pay for all of the incremental costs of any major storm, which
is defined as any storm with incremental costs of over $1.0 million occurring
after the date this Settlement is approved by the Department. The storm fund
will be prefunded with $8.0 million within 30 days of Department's approval of
this Settlement. The distribution charge contains an accrual of up to $3
million per year, as set forth in Attachment 2 and Boston Edison shall begin
to accrue this amount to the storm fund on an annual basis commencing on the
date when the retail delivery rates become effective. The accrual shall
continue at up to $3.0 million per year until a modification is approved by
the Department following a filing by Boston Edison. Boston Edison is
authorized to charge all incremental costs of major storms against the fund
and to pay or accrue interest on the fund balance whether positive or negative
in accordance with the protocols for the fund set forth in Attachment 2.
I.B.2.(c) This Settlement is based on the existing separation
of distribution and transmission facilities on the Boston Edison system.
Approval of the jurisdictional separation of facilities without change is not
a condition of the Settlement. In the event that facilities or costs are
transferred from transmission to distribution or from distribution to
transmission, the parties agree that appropriate adjustments to the
transmission and distribution components of the rates will be made to reflect
the transfer.
<PAGE>
I.B.2.(d) By April 1 of each year, Boston Edison shall file
with the Department to adjust rates to recover or refund revenues necessary to
assure that Boston Edison's annual return on average common equity associated
with distribution operations from the prior calendar year averaged between six
percent and eleven percent before any incentives earned on demand side
programs as authorized by the Department pursuant to section III.B, below.(1)
Boston Edison's return on equity for the prior year shall be calculated using
the earnings available for common equity as reported to the Securities and
Exchange Commission in Boston Edison's annual report, to the extent such
earnings are contained in that report, as adjusted in the preceding sentence,
divided by the average of the thirteen monthly common equity balances on
Boston Edison's books for the same period. If Boston Edison's return on
equity for distribution operations is below six percent, it shall be
authorized to increase its rates by a uniform per kilowatthour surcharge
calculated to provide sufficient revenues to increase Boston Edison's return
on equity to six percent. If Boston Edison's calculated return on equity as
described above is above eleven percent, it shall be required to reduce its
rates by a uniform per kilowatthour surcharge to refund revenues necessary to
reduce the calculated return on equity between eleven and 12.5 percent by 50
percent and the earnings above 12.5 percent by 100 percent. If Boston
Edison's calculated return on equity as described above falls between six and
eleven percent, then no further adjustment shall be authorized or required.
I.B.2.(e) Boston Edison shall also adjust its retail delivery
rates for the effects of any changes in the federal or state income, revenue,
sales, or franchise tax rates or laws,
[FN]
____________________
(1) Boston Edison's earnings available for common equity and common equity
balances on its distribution operations shall also be adjusted to
eliminate the effects of any writedown and to restore expenses associated
with any such writedown that may result from the implementation of
industry restructuring or this Settlement
<PAGE> 028
or any externally imposed accounting changes, if they affect Boston Edison's
costs, by more than $1.0 million per year or any other charges under the
retail delivery rates in Attachment 1.
I.B.2.(f) The retail delivery rates in Attachment 1 include
fully reconciling charges for Boston Edison's access charges and transmission
payments. Any amount of over or under collection of the total, allowed,
access and transmission charges will be applied to all customers as a uniform
cents per kilowatthour credit or charge to the applicable access or
transmission charge.
For billing purposes the access charges shall be rolled into the
distribution rates and shall not be shown separately on bills to customers.
I.B.2.(g) The discount for the R-2 Rate that is available for
Boston Edison's low income customers is designed to reduce the total bill of
a customer taking standard offer service by 40 percent in accordance with the
Attorney General's principles. To assure that the same level of discount is
available regardless of the supplier and to allow the operation of the
reconciling access and transmission charges, the discount is applied
exclusively to the distribution component of the rate. The recovery of the
discount from Boston Edison's other customers is based on distribution rate
base in accordance with the practice in prior cases.
I.B.2.(h) Boston Edison's conservation services charge and
conservation charge factors are included in the retail delivery charges in
Attachment 1, and separate Energy Conservation Service and conservation cost
factors will be discontinued on the effective date of the retail delivery
rates. Any outstanding balances, whether positive or negative, will be
accounted for as provided in section III.B of this Settlement.
I.B.2.(i) Boston Edison shall implement the performance
standards for reliability and customer satisfaction set forth in Attachment 5,
and Boston Edison shall be
<PAGE>
required to credit customers with an amount calculated in accordance with the
schedules in Attachment 5 during the year following any year that it failed to
meet the indicated performance standard. In addition, Boston Edison shall
propose, by July 1, 1997 a performance standard for the effective management
of line losses.
I.B.3. Transmission Charges
--------------------
The transmission cost adjustment shall recover the costs charged to
Boston Edison retail customers under Boston Edison's FERC approved tariffs,
or billed to Boston Edison by any other transmission provider, and by other
regional transmission or operating entities, such as NEPOOL, a regional
transmission group ("RTG"), an independent system operator ("ISO"), or other
regional body, in the event that they are authorized to bill Boston Edison
directly for their services and shall include any other charges relating to
the stability of the transmission system which Boston Edison is authorized to
recover from retail customers by order of the regulatory agency having
jurisdiction over such charges. However, under no circumstances shall the
amount included in these charges recover costs which are collected by Boston
Edison in some other rate or charge. The transmission charges shall be
recoverable under the transmission cost adjustment provisions included in
Attachment 1.
The transmission cost adjustment shall be established annually based on
a forecast of transmission costs, and shall include a full reconciliation and
adjustment for any over or under-recoveries occurring under the prior year's
adjustment. As set forth below, the parties have agreed to support the
implementation of NEPOOL reforms, including the formation of an RTG and ISO
to the extent consistent with this Settlement. These reforms are desirable,
but are neither a condition to retail access by Boston Edison nor of the
approval of this Settlement.
I.B.4. Access Charges
--------------
<PAGE> 030
The uniform cents per kilowatthour access charges shall be calculated in
accordance with Attachment 3 and shall remain in effect until Boston Edison
has collected all amounts subject to collection under the access charge. The
access charge shall be recoverable under the access cost adjustment provisions
included in the tariffs in Attachment 1. The access cost adjustment factor
will recover on a fully reconciling basis all of Boston Edison's stranded
investment as set forth in this Settlement.
I.B.5. Standard Offer
--------------
Consistent with the Attorney General's principles and subject to the
conditions set forth herein and in Attachment 4, Boston Edison shall arrange
to provide standard offer service through a transition period ending on
December 31, 2004, by putting it out to bid. Standard offer service shall be
available to all of Boston Edison's retail customers on the Retail Access
Date.(2) After the Retail Access Date, Boston Edison's retail customers are
free to leave the standard offer at any time to purchase from an alternative
supplier in the market; but, once the market option is selected, a retail
customer may not return to service at standard offer prices; provided,
however, that standard offer service shall be available to all residential,
G-1 or T-1 retail customers, who have previously taken service from an
alternative supplier for the first year after the Retail Access Date, if such
residential, G-1 or T-1 retail customer elects to return to standard offer
service within 90 days of first taking service from the alternative supplier.
The terms and conditions for the bids by potential suppliers for standard
offer service are set forth in Attachment 4.
In the event the standard offer can not be supplied from the bids
received in accordance with the provisions of Attachment 4, Boston Edison
shall supply the remaining standard offer
[FN]
____________________
(2) Retail customers include all customers of Boston Edison with the exception
of those customers which at the time of the approval of this Settlement
are being served by Boston Edison pursuant to contracts approved by the
Federal Energy Regulatory Commission.
<PAGE>
requirements using the following resources, to the extent they are still
available to Boston Edison, in the order of least incremental cost to
customers:
(1) existing purchased power contracts,
(2) its fossil units, but, if sold, only to the extent that
the purchaser of the units has an obligation to supply
back up to the standard offer,
(3) Pilgrim Station, and
(4) short-term purchases at market prices.
Boston Edison's standard offer prices are guaranteed, subject to the
conditions set out in paragraphs (a), (b), (c) and (d) of this Section I.B.5.
Under the tariffs included in Attachment 1, Boston Edison's charges for
standard offer service are included as a separate surcharge to the rates for
retail delivery service that apply to all retail customers. Boston Edison
shall reconcile the revenues billed to retail customers taking standard offer
service with payments to suppliers of standard offer service and recover or
refund any under or overcollections on the following terms:
I.B.5.(a) The standard offer shall be subject to the Fuel Index
set forth in Attachment 4.
I.B.5.(b) Any revenues billed by Boston Edison for standard
offer service in excess of payments to suppliers of that service shall be
accumulated in an account and credited with interest calculated using the
methodology for calculating interest on retail customer deposits specified
in Boston Edison's terms and conditions. The accumulated balance at the end
of each calendar year shall be credited to all of Boston Edison's retail
customers through a uniform cents per kilowatthour factor in the following
year.
I.B.5.(c) In the event that the revenues billed by Boston
Edison do not recover Boston Edison's payments to suppliers or Boston Edison
defers expenses to meet the
<PAGE> 032
inflation cap established in Section I.B.9, Boston Edison shall be authorized
to accumulate the deficiencies in the account together with interest
calculated as above and recover those amounts by implementing a uniform cents
per kilowatthour surcharge on the rates for standard offer service, if and to
the extent that the access charges billed by Boston Edison to its retail
customers are for any reason below the unadjusted access charge listed in
Attachment 3. Under-recoveries, if any, that remain after the standard offer
transition period ends on December 31, 2004 shall be recovered from all retail
customers by a uniform surcharge not exceeding $0.005 per kilowatthour
commencing on January 1, 2005.
I.B.5.(d) Notwithstanding any other provision in this
Settlement, in the event the deferred costs under the standard offer at any
time accumulate to an amount in excess of $50 million, Boston Edison shall be
authorized to fully recover the amount of deferred costs in excess of $50
million by filing with the Department a standard offer surcharge. Such
standard offer surcharge will be designed to recover the deferred excess costs
forecast for the next twelve (12) months on an annual basis and shall go into
effect sixty (60) days following the filing with the Department. The
collection of deferred excess costs will be through a uniform cents per kWh
surcharge to the standard offer until such time as the amount of energy
consumed by retail customers receiving standard offer service reduces to 15
percent of the energy delivered to all retail customers. At that point, the
surcharge will be billed to all retail customers through the delivery charge.
I.B.6. Safety Net Service
------------------
In recognition that electricity is an essential service, and that there
is a risk that in a competitive market some low-income customers may be unable
to obtain or retain service on reasonable terms on account of a credit profile
that would not create a barrier to service under the
<PAGE>
current regulated monopoly supply, Boston Edison shall arrange to provide
electric supply for low-income customers who are no longer eligible to receive
service under the standard offer and not adequately supplied by the market
because they are unable to obtain or retain electric service from competitive
power suppliers. Service under this provision shall be made available under
rates, terms and conditions approved by the Department. Boston Edison shall
fully recover the reasonable costs it incurs in arranging this service.
I.B.7. Basic Service
-------------
In recognition that retail customers may face an occasional hiatus
between competitive suppliers, and in an effort to prevent such retail
customers from losing power because they do not have a contractual
relationship with a viable supplier, Boston Edison shall facilitate the
continued delivery of power, such as by providing supply through the short-
term wholesale power market, to such retail customers and allow them to have
a reasonable opportunity to make other supply arrangements, and shall fully
recover its reasonable costs of providing such service. Such supply shall be
provided on terms and conditions approved by the Department.
I.B.8. Terms and Conditions
--------------------
On July 1, 1997, Boston Edison shall file with the Department for its
approval retail customer terms and conditions and supplier terms and
conditions and settlement procedures modified to reflect the changes in Boston
Edison's operations after the Retail Access Date. These filings are not a
condition of the Settlement.
I.B.9. Inflation Cap for Standard Offer Customers
------------------------------------------
Boston Edison shall assure that the economic value of the ten percent
rate reduction for retail customers is maintained through the period of the
standard offer by capping average revenues per kilowatthour for retail
delivery service plus the standard offer, adjusted to exclude
<PAGE> 034
the effect of: (1) the fuel price index in Attachment 4 and the standard
offer deferral cap in Section I.B.5.(d); (2) any adjustments caused by the
return on equity floor under Section I.B.2(d); and (3) changes in tax laws or
accounting under Section I.B.2(e), at the rates in Attachment 1 adjusted for
percentage changes in the Consumer Price Index occurring between October 1,
1996 and the effective date of any adjustment to the standard offer price
under Section I.B.1(d). This calculation shall be performed annually in
conjunction with the annual update to the access charge pursuant to the
provisions of Section V.E.
I.C. Right to File for Rate Change in the Event that Retail Access
-------------------------------------------------------------
Date Postponed
--------------
Nothing in this Settlement shall prevent the parties from seeking a rate
change to become effective, after suspension, on January 1, 2001 in the event
that the Retail Access Date has not occurred by that time.
II. Benefits of Competition Extended to All Retail Customers
--------------------------------------------------------
The Attorney General's principles require utilities to extend the
benefits of competition to all retail customers. This Settlement achieves
that requirement by providing all retail customers with the opportunity to
choose alternative suppliers on the Retail Access Date and by guaranteeing
significant rate reductions for retail customers who take standard offer
service prior to choosing an alternative supplier under the ratemaking portion
of this Settlement. Specifically, the parties agree that Boston Edison shall
implement retail access on the following terms:
II.A. Prior Commitments with Retail Customers
---------------------------------------
Prior commitments under Boston Edison's retail rates or contracts will
be treated as follows:
II.A.1. Notice Provisions in Boston Edison's Tariffs
--------------------------------------------
<PAGE>
Boston Edison's General Service rate tariffs include a provision
requiring all customers to provide one year's prior written notice before
purchasing from an alternative source or installing additional on-site
generation capacity for the customer's own use. After the Retail Access Date,
Boston Edison shall waive this notice requirement for purchases from
alternative suppliers under the terms of Boston Edison's retail delivery rates
included in Attachment 1. Nothing in this Settlement shall require Boston
Edison to waive the advance written notice required before the retail customer
may install additional on-site, non-emergency generation for its own use or to
allow bypass of Boston Edison's distribution system.
II.A.2. Special Retail Contracts
------------------------
<PAGE> 036
Retail customers receiving service under special contracts approved by
the Department are not eligible for standard offer service. However, Boston
Edison will waive the notice provisions contained in any special contracts
with retail customers so long as the customer continues to take delivery
services, which include access and transmission charges, from Boston Edison
under a delivery rate approved by the Department and applicable to the
customer. Nothing in this Settlement shall require Boston Edison to waive
the advance written notice required before the retail customer may install
additional on-site, non-emergency generation for its own use or to allow
bypass of Boston Edison's distribution system.
II.A.3. Conservation and Load Management Program Terms and Conditions
-------------------------------------------------------------
Many of Boston Edison's nonresidential retail customers have participated
in Boston Edison's conservation and load management programs that require
repayment of Boston Edison's incentive payments if the customer purchases
electricity from an alternative supplier. Boston Edison shall waive this
repayment obligation insofar as it would limit the customer's ability to
purchase electricity from an alternative supplier. Nothing in this Settlement
shall require Boston Edison to waive the requirement for repayment before the
retail customer may install on-site, non-emergency generation for its own use
or to allow bypass of Boston Edison's distribution system.
II.B. Implementation of Retail Access
-------------------------------
This Settlement requires Boston Edison to provide retail access and to
implement the retail delivery rates in Attachment 1 on the Retail Access Date,
which is the later of January 1, 1998 or the date on which retail access is
made available to all retail customers of the investor-owned utilities in
Massachusetts. Under this Settlement, this condition will be achieved when
legislation, final regulatory or court action, or unchallenged settlements
approved by the Department in a final order with all other investor-owned
utilities in Massachusetts are in place.
<PAGE>
In the event that retail access is not yet available to all retail customers
of investor-owned utilities in Massachusetts by January 1, 1998, Boston Edison
in its sole discretion, on or after that date, shall have the option to file
for the Department's approval to accelerate the Retail Access Date under this
Settlement, implement retail access for its retail customers, and make the
tariffs in Attachment 1 effective by providing the Department and the parties
with 90 days advance notice in writing.
III. Protect the Environment and Promote Conservation
------------------------------------------------
The third element of the Attorney General's plan requires the
restructuring plans of utilities to protect the environment and to promote
conservation. This Settlement complies with these requirements by limiting
emissions from Boston Edison's units, and by continuing funding for demand
side programs including clean renewable resources. The parties have agreed
to the following terms:
III.A. Emissions Reductions
--------------------
Boston Edison or its successors in interest shall achieve the level of
emissions of NOx and S02 from its New Boston Units 1 and 2 and its Mystic
Station Units 4, 5, 6 and 7 on the schedule and terms set forth in Attachment
6. Nothing in this Settlement shall affect Boston Edison's obligations to
comply with environmental regulations lawfully imposed or to restrict the
environmental regulators' authority to impose new environmental standards.
III.B. Conservation and Load Management and Renewables
-----------------------------------------------
By September 1, 1997, or a subsequent date ordered by the Department,
Boston Edison shall develop in a collaborative process and shall file with
the Department plans to implement the budgets for demand side programs and
clean renewables for the period 1998 through 2001 in the
<PAGE> 038
amount of $54.2 million per year.(3) At least 15 percent of the amount
budgeted for residential programs in any given year shall be spent on low
income residential programs. Funds shall be allocated within the budget to
commercialize and develop fuel cells and a diverse group of clean renewables
in a manner approved by the Department, with collaborative input, based on
the following table:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
1998 1999 2000 2001
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C>
IRM $1.6 $14.2 $13.9 $1.6
New DSM $26.1 $19.1 $22.4 $30.8
Subtotal $27.7 $33.3 $36.3 $32.4
Amortizations $15.9 $6.7 $0.0 $0.0
Existing Commitments $7.3 $6.9 $6.6 $5.0
Renewables(4) $3.3 $7.3 $11.3 $16.8
TOTAL $54.2 $54.2 $54.2 $54.2
</TABLE>
Overcollection of conservation charges in 1996 and 1997 shall be used as part
of the funding for support of the DSM budgets set out in the Table above
rather than to reduce conservation charges through the full reconciliation.
However, to the extent the overcollection for 1997 differs from Boston
Edison's current projection of $10 million, that difference will carry over
into 1998
[FN]
____________________
(3) These dollar totals will not vary whether or not the retail access date
occurs on January 1, 1998.
(4) These renewables dollar amounts will not vary with usage but are
equivalent to the mills/kWh amounts (ranging from .25 mills in 1998,
.55 mills in 1999, .85 mills in 2000, and 1.25 mills in 2001) set forth
in settlement approved by the Department in D.P.U. 96-25.
<PAGE>
to adjust the amounts shown on the table above for IRM or new DSM.(5) Boston
Edison will continue collecting the 1997 conservation charge at 1996 levels
and will not file a new conservation charge for implementation in 1997.
During any year after 1997, Boston Edison shall reconcile actual spending and
earned incentive to the approved budget, with separate reconciliations for
renewables and DSM, and shall carry forward any balance, positive or negative,
into the following year through an adjustment to the approved budget. The
parties agree to work collaboratively to ensure that actual expenditures
deviate from the above table as little as possible. Boston Edison shall not
allow DSM spending to fall short of budget by more than ten percent in the
aggregate for all IRM and new DSM programs, in any two consecutive years from
1998-2001. If spending for DSM falls below that level, Boston Edison and
members of the DSM collaborative shall file separate or joint reports to the
Department explaining the reasons the budget levels were not achieved. If
the Retail Access Date does not occur on January 1, 1998, the fully
reconciling conservation charge shall recommence on January 1, 1998 and shall
remain in effect until the Retail Access Date. Boston Edison commits to use
its best efforts to execute with entities other than Boston Edison all pending
IRM DSM contracts within thirty (30) days of the filing of this Settlement
with the Department.
The budgets shall also include expenditures for support of a
collaborative effort regarding energy efficiency and renewables, the energy
conservation service ("ECS") program, Boston Edison's demand side and market
transformation programs, overhead costs,(6) recovery of amortized investment
and the incentive earned from programs implemented prior to the Retail
[FN]
____________________
(5) For example, if the 1997 overcollection is $11 million instead of $10
million, the 1998 subtotal for IRM and new DSM would be $28.7 million
instead of $27.7 million.
(6) DSM overhead costs shall be allocated among IRM and new DSM, pro rata
based on dollars.
<PAGE> 040
Access Date and the new incentive(7) to be earned on the demand side programs
implemented after the Retail Access Date pursuant to this paragraph. Boston
Edison shall also propose to include in its DSM budget reasonable levels for
conservation voltage regulation initiatives and the installation of
sophisticated metering and control systems as presented at least thirty (30)
days prior to filing to stakeholders in a DSM collaborative as provided for
in the Department's December 30, 1996 order in D.P.U. 96-100, at, p.190, and
subject to Department approval. Within thirty (30) days of the Department's
approval of this Settlement, Boston Edison will pay $350,000 from conservation
charge overcollections relating to periods prior to 1998 to the DSM Transition
Funding Board.(8) This money will be used beginning in 1997 to support
collaborative research on market transformation and other conservation issues.
In addition Boston Edison will provide funding for the DSM spending levels in
1998, 1999, 2000 and 2001 provided for in this Settlement. In return for
foregoing future lost base revenues and lost delivery revenues, a new
incentive for DSM implementation which reduces administrative costs, will
begin in 1998. The incentive will be a flat dollar amount reflecting
performance against a specified standard and lost revenue. The Company shall
earn an annual incentive of $4 million if the projected kWh savings are found
by the Department to exceed a threshold of 90%, $3 million per year if the
Department finds that the achievement is between 70 and 90 percent of the
projected amounts, $1 million if the Department finds that the achievement is
between 50% and 70%, and the Company shall receive no incentive payments if
the Department finds that the kWh savings achieved are below
[FN]
____________________
(7) The new DSM incentives shall be fairly allocated among IRM and new DSM.
(8) The fund shall be administered by the DSM Transition Funding Board which
shall consist of signatories to this Settlement that are interested in
the development and implementation of the DSM and renewables plans. The
DSM Transition Funding Board shall provide a full accounting of these
expenditures to both the Department and all of its members.
<PAGE>
50%. The parties recognize that performance measures may need to be revised
to reflect changes during the transition, and will work with the Department
to revise such measures if needed.
The parties to this Settlement will work together to develop streamlined
DSM reporting and reconciliation processes in order to reduce administrative
burdens and costs. This streamlined process shall be designed so that it will
not in any way limit the ability of the Department to review DSM expenditures.
The filing of any streamlining plan will be completed and filed in conjunction
with the September 1, 1997 DSM plan.
While the Department will decide the appropriate level for ongoing
conservation, load management and renewables funding after January 1, 2002,
Boston Edison, the Attorney General, and the Division of Energy Resources
jointly recommend that evaluation of funding after this date be informed by
review of the then current market barriers and experience gained with the
competitive energy markets and customer choice established in this Settlement;
and should further be based upon environmental and economic goals to be
achieved by such funding established by the Department through appropriate
proceedings. Ongoing commercialization support for fuel cells and clean
renewable technologies beyond January 1, 2002 should also be based on a goal
of supplying at least four percent of Massachusetts' electricity kilowatthour
sales from such new, clean technologies by the end of 2007.
Generation technologies potentially eligible for commercialization
support, subject to Department review, shall include a diverse group of low
and zero emissions generation technologies with substantial long-term, cost-
effective regional production potential which utilize any of the following:
a) solar photovoltaic and solar thermal electric energy;
b) wind energy;
<PAGE> 42
c) ocean thermal, wave and/or tidal energy;
d) fuel cells;
e) landfill gas; and
f) low emission advanced biomass power conversion technologies like
gasification using such biomass fuels as wood, agricultural, or food wastes;
energy crops, biogas, or organic refuse-derived fuel.
While the Department will decide how funds shall be allocated based on
input from a collaborative process, the commercialization of clean generating
technologies should be accomplished in a least cost manner. Optimal use
should be made of competitive bidding in funding commercialization activities.
Commercialization activities shall also attempt to promote as diverse a group
of clean technologies as is practical and ensure no single resource or
technology dominates commercialization efforts.
Boston Edison will perform pilot projects approved by the Department
to assess the value of distributed clean generation, conservation and load
management technologies in reducing or avoiding distribution system costs.
Operational procedures to invest in clean distributed generation and
geographically-targeted DSM that lower distribution service costs should be
implemented as soon as is practical.
Clean distributed generation of 30 kilowatts or less to include fuel
cells, renewables and small scale cogeneration shall remain eligible for "net
metering" as provided for in existing Department regulations regarding the
buy-back of generated power at the retail rate.
IV. Protect Low Income Customers
----------------------------
The fourth principle in the Attorney General's plan focuses on the
continued protection of low income customers. Boston Edison's plan complies
with this principle by continuing the
<PAGE>
discount for Rate R-2 customers, assuring that all customers receive immediate
rate reductions through standard offer service, providing safety net service
for low-income customers that have no other alternative supplier (see Section
I.B.6., above), and funding the residential low income demand side programs
in Section III.B. In addition, Boston Edison shall implement a program to
protect against redlining by market suppliers by paying market suppliers of
Rate R-2 customers directly for electricity delivered up to the prices for
standard offer service set forth in section I.B.1.(d) and then including the
costs of such service in Boston Edison's distribution bill to Rate R-2
customers. In this way, Boston Edison, rather than the market supplier,
shall assume the risk of nonpayment from Rate R-2 customers.
Electric service is essential and should be available to all retail
customers. The restructured electricity industry should provide adequate
safeguards to assure universal service. Programs and mechanisms that enable
residential customers with low incomes to manage and afford essential
electricity requirements will be maintained throughout the period of the
Settlement in order to foster the goal of universal service.
V. Create a Fully Functioning Stable and Reliable Structure for the
----------------------------------------------------------------
Competitive Market
------------------
The Attorney General's final principle focuses on the institutional
structure and protections necessary to prevent unfair and anti-competitive
conduct, and to maintain reliable and safe electricity supplies. These
industry structure issues focus on the region as a whole and the corporate
structure of Boston Edison.
V.A. Regional Reform
---------------
The regional issues center on the formation of a regional transmission
group, an independent system operator and NEPOOL reform. Boston Edison
supports the Restructuring Proposal filed by NEPOOL with the FERC on
December 31, 1996. Boston Edison shall continue
<PAGE> 044
to support at a minimum, the regional reforms set forth in those filings,
and shall consult with the parties to this Settlement to develop mutually
agreeable approaches to these issues that are consistent with the terms of
this Settlement. However, this Settlement is not conditional upon the
adoption, approval, or implementation of the regional reforms included in
those dockets. Nothing in this Settlement shall limit the parties from
advocating positions other than those in the above referenced FERC Dockets.
V.B. The Jurisdictional Separation Between Transmission and
------------------------------------------------------
Distribution
------------
In Order 888, FERC set forth a seven factor test for determining whether
facilities used to provide access to retail customers are subject to the
ratemaking jurisdiction of FERC under the Federal Power Act or of the
Department under state law. Attachment 7 provides a specific evaluation of
FERC's seven factors as applied to the separation of Boston Edison's
facilities. Approval of the jurisdictional separation of facilities without
change is not a condition of this Settlement.
V.C. Generation
----------
This section contains Boston Edison's commitments with respect to the
continued operation, shutdown, or divestiture of Boston Edison's existing
generation business. Subsection 1 addresses the commitment to divest Boston
Edison's fossil generation business. Subsection 2 addresses commitments with
respect to Pilgrim Nuclear Power Station ("Pilgrim"). Subsection 3 addresses
commitments with respect to power purchase contracts. Subsection 4 addresses
actions taken prior to the Retail Access Date.
Consistent with the restructuring plan advanced by the Division of Energy
Resources, Boston Edison agrees, subject to the receipt of all required
governmental approvals, to sell, spin off, or otherwise transfer ownership
of its generating business and facilities to a nonaffiliated
<PAGE>
entity or entities, other than properties, assets, and entitlements classified
to the transmission function and except as provided in section V.C.2.(b) and
subject to the provisions of section V.C.3 of this Settlement.
V.C.1. Generation Divestiture
----------------------
By the later of May 1, 1997 or ten (10) days after filing this Settlement
with the Department, Boston Edison shall develop and file for informational
purposes only a plan with the Department to implement divestiture of its
generating business assets, except as provided for in section V.C.2(b), and
subject to the provision of section V.C.3, below. This plan shall include in
particularized detail the fossil generating business to be divested and all
properties, assets, and entitlements to be included in the divestiture. The
plan also shall include specific terms and conditions to be included in the
RFP which are necessary to assure adequate support for the Boston Edison
distribution system. In addition, the plan shall include a draft of Boston
Edison's Request for Proposals for Standard Offer Service.
Within ten (10) days after signing a sale agreement related to any
generating business asset, Boston Edison will file said agreement with the
Department for approval. The Department shall review each such agreement and
shall issue a final order on the method of sale and the reasonableness of the
proceeds and commitments within seventy-five (75) days of filing such
agreement with the Department. The divestiture shall be completed by six
months after the later of the Retail Access Date or the receipt of all
governmental approvals necessary for the transfer. If, for any reason, the
divestiture is not completed within three years following the Retail Access
Date, Boston Edison shall file a report with the Department explaining the
delay.
Within three months after the completion of the divestiture and provided
the Retail Access Date has occurred, Boston Edison shall implement a residual
value credit as a direct offset to the
<PAGE> 046
access charge authorized under this Settlement. The residual value credit
shall be calculated as set forth in Section 1.0 of Attachment 3 to this
Settlement. On the first day of the month following implementation of the
residual value credit mechanism, the access charge shall be adjusted to
reflect the residual value credit in accordance with Section 1.4 of Attachment
3 to this Settlement.
V.C.2. Pilgrim Station
---------------
V.C.2.(a) Continued Operation Following the Retail Access Date, for
-------------------
such period as Pilgrim shall continue to operate, the following provisions
shall apply.
V.C.2.(a).i Unrecovered net book value of plant, decommissioning costs,
certain fixed operating costs, Post-Shutdown Costs payments in lieu of
property taxes, employee severance and retraining, and damages, costs and net
recoveries from claims shall be collected and applied in accordance with the
methodology set forth in Attachment 3.
V.C.2.(a).ii Through December 31, 2000, performance based rates shall be
in effect as set forth in Attachment 3.
V.C.2.(b) Divestiture There is no requirement to divest Pilgrim as
-----------
part of this Settlement. However, Boston Edison shall file for approval by
the Department a market valuation plan on or before January 1, 1999.
Valuation under this plan shall be completed on or before December 31, 2002.
Boston Edison shall implement, within three months after the valuation is
completed, a residual value credit which shall be reflected in the access
charge on the first day of the month following implementation of such
residual value credit in accordance with Section 1.5 of Attachment 3 of
this Settlement. Subject to the prior receipt of approvals by the Nuclear
Regulatory Commission and the Department, Boston Edison may assign or retain
responsibilities for certain activities such as decommissioning, premature
decommissioning or fixed operating
<PAGE>
costs and may either retain or assign the associated funds and or funds flow
as part of any sales agreement.
V.C.2.(c) Shutdown If at any time either before or after the Retail
--------
Access Date, Boston Edison notifies the Department that Boston Edison has
decided to permanently shut down Pilgrim Station, Boston Edison will be
allowed to recover the various categories of costs through the access charge
and/or the reconciliation account as set forth in Attachment 3.
V.C.3. Power Purchase Contracts
------------------------
V.C.3.(a) Boston Edison will endeavor to sell, assign or otherwise
dispose of its purchased power contracts on terms that will assign ongoing
contract payments to a nonaffiliated third party.
V.C.3.(b) By July 1, 1998, Boston Edison shall file a plan describing
the actions the Company intends to take to sell, assign or otherwise dispose
of its purchased power contracts. Such plan shall include a description of
options which were considered and milestones for implementing the proposed
plan.
V.C.3(c) To provide for any potential shortfall in power available
to supply the standard offer, and in recognition of the continued availability
of power from Boston Edison's independent purchased power contract suppliers,
if any contract is sold before the standard offer bid or if the standard offer
is not fully subscribed, any sale, assignment, or disposition of such
contracts shall include a stipulation that they be available to back up the
standard offer. To the extent that the contracts are not required to meet the
standard offer, the aforementioned stipulation shall not apply. In the event
that such contracts cannot be sold, assigned, or otherwise disposed of, and
such power is not used to provide standard offer service as provided for in
section I.B.5 of this Settlement, the power purchased from those contracts
shall be sold and the
<PAGE> 048
contract payments and market value associated with the sale shall be reflected
in the reconciliation account. Such power sales, if any, shall only be made
in the wholesale market to nonaffiliates. Nothing in this Settlement shall
affect the rights of suppliers or Boston Edison under purchased power
contracts.
V.C.4. Sale or Shutdown Prior to Retail Access Date
--------------------------------------------
If Boston Edison sells, spins off, or otherwise transfers an interest in
any or all of its generating facilities or its power purchase contracts prior
to the Retail Access Date, any resulting proceeds shall accrue carrying costs
at the same rate as shown on Schedule 1, page 14, used to calculate the return
on investment cost in the Attachment 3 from the date the proceeds are received
by Boston Edison to the Retail Access Date. This carrying cost will be added
to the total proceeds component of the Residual Value Credit of the Access
Charge (Attachment 3, Paragraphs 1.4 and 1.5), which becomes effective at the
Retail Access Date.
If Boston Edison sells, spins off, otherwise transfers or shuts down any
or all of its fossil or nuclear plants and facilities or its power purchase
contracts prior to the Retail Access Date ("Facilities Transactions"),
reasonable replacement power costs, including any short term bridging type
power contracts sold with the plant will be recovered through the fuel clause.
Any fuel charge recovery of replacement power costs will be net of the
reductions in non-capital operating costs resulting from the sale, spin off,
transfer or shut down. ("Recoverable Replacement Power Costs").
Boston Edison's fuel clause recovery of Recoverable Replacement Power
Costs will be no higher than the costs customers would have paid under the
fuel and purchased power clause had the Facilities Transactions contemplated
by this Section not occurred. Boston Edison agrees, that
<PAGE>
as part of its fuel charge filings,(9) it will provide a calculation making
such a showing. Any such Recoverable Replacement Power Costs found to be
reasonable and in excess of what retail customers otherwise would have
incurred shall be deferred with a carrying charge at the same rate defined in
Attachment 3, Schedule 1, page 14, used to calculate the return on investment
and be recovered over a three year period beginning in the year 2001 in the
Reconciliation Account.
V.C.5. Voluntary Act
-------------
The Department and intervenors have expressed the goals of attaining a
market valuation of utility stranded costs and creating a competitive market
for supplying electricity to consumers. The Department has expressed a
preference for voluntary divestiture of utility generation as a means of
achieving these goals. The Department has stated that it "has the authority
to approve the voluntary divestiture of assets", but that it has "no explicit
statutory authority [to] order divestiture, nor is it likely to be implied."
(D.P.U. 95-30, August 16, 1995). Boston Edison has asserted that the
Department lacks authority to order divestiture, and would contest any effort
by the Department to do so. Boston Edison has agreed, as part of this
Settlement, voluntarily to undertake such divestiture. In exchange, and as
consideration for this voluntary divestiture, the parties to this Settlement,
and the Department by its approval of this Settlement, agree that Boston
Edison's access charges as set forth in Attachment 3 are just and reasonable.
Accordingly, and to give effect to the reliance placed by the parties on the
foregoing, the Department shall treat the findings that such recovery and
access charges are just and reasonable as a final determination made after
public notice and a full investigation of the merits, and, in any future
proceeding brought by any person or party, or by the Department on its own
motion, shall
[FN]
____________________
(9) In the event the current provision of G.L. c. 164, 94G, are no longer in
effect, the parties agree that, in the absence of legislative direction
to the contrary, recovery of replacement energy and capacity costs under
this Section shall be governed by the principles and standard of review
applied under the current terms of 94G.
<PAGE> 050
accord such finding the full benefit of policies of repose including, without
limitation, the application of the doctrines of res judicata, collateral
estoppel, the filed rate doctrine, the prohibition against retroactive
ratemaking, and the finality of contracts, it being the express intention of
the parties to prevent, as a matter of law and policy, the Department or any
other authority from: (a) revisiting the issue of the justness and
reasonableness of the stranded investment and the access charges or
(b) reducing, other than as set forth in Attachment 3 the amount of the
access charges, or (c) otherwise limiting the right of Boston Edison, its
successors or assigns, to charge and recover its stranded costs or the access
charges set forth in this Settlement for any reason prior to their recovery
in full as contemplated by this Settlement.
<PAGE>
V.C.6. Exempt Wholesale Generator Status
---------------------------------
To facilitate the divestiture and valuation of Boston Edison units, the
parties agree that it is in the public interest for Boston Edison or its
successors or assigns to be authorized to sell electricity at market prices
in the wholesale markets, and that Boston Edison or its successors or assigns
shall be free to apply to become an exempt wholesale generator pursuant to
Section 32 of the Public Utilities Holding Company Act of 1935 and other
Federal law, rules and regulations, and to designate each and every generating
facility and entitlement it owns as an eligible facility pursuant to that
statute. Approval of the Settlement by the Department shall represent express
finding by the Department that it has sufficient regulatory authority,
resources, and access to books and records to exercise its duties, and that
the full participation of Boston Edison in the market and the designation of
each of its facilities as eligible facilities will benefit consumers, is
consistent with existing state laws, will not provide unfair competitive
advantage by virtue of its status as a facility owned or formerly owned by
Boston Edison, and is in the public interest.
Nothing in this Settlement shall prevent an affiliate of Boston Edison
from re-entering the generation business following the completion of
divestiture, and nothing in this Settlement shall prevent affiliates of Boston
Edison from marketing electricity, other energy sources, or energy services
to customers within or outside Boston Edison's service territory, provided
Boston Edison functionally unbundles as described by the Department in D.P.U.
96-100.
V.D. Additional Funding of Boston Energy Technology Group
----------------------------------------------------
As part of this Settlement, the parties agree they will support Boston
Edison's request to increase its investment in its wholly-owned subsidiary
Boston Energy Technology Group by up to $150 million in addition to the $45
million presently authorized. Boston Edison is not seeking
<PAGE> 052
resolution of any transfer pricing issues which may arise in connection with
the transfer of assets to any subsidiary.
V.E. Annual Updates of the Access Charge
-----------------------------------
Each year by November 1, Boston Edison will file with the Department a
proposed access charge to become effective on January 1 of the following year
("Annual Update Filing"). This filing will include all of the calculations
required by Attachment 3 to this Settlement. These calculations will to the
extent reasonably possible be made using the actual costs through September 30
of the current year, forecast costs for the period of October 1 through
December 31 of the current year and reconciliations of any differences between
forecast amounts used in prior years to set the prior year's access charge and
actual costs for those same period.
V.F. Resolution of Disputes
----------------------
As provided in Section V.E, above, Boston Edison shall make an Annual
Update Filing. It is intended that disputes pertaining to the Annual Update
Filing are, to the extent reasonably possible, to be resolved informally. In
order to facilitate such resolution, Boston Edison shall provide the
signatories to this Settlement a preliminary copy of the Annual Update Filing
at least thirty (30) days prior to the date of such filing. The parties agree
to review such preliminary filing as necessary and thereafter to confer,
exchange information and engage in good faith efforts to resolve any issues
that may arise concerning such filing.
V.G. No Waiver Provision
-------------------
If, as the result of the informal dispute resolution process described in
Section V.F above or as part of the Department's review of the Annual Update
Filing contemplated by Section V.E, above, any party to this Settlement
determines that either the then current residual value credit, a previous
residual value credit or the then current variable component of the access
charge or a
<PAGE>
previous variable component of the access charge was calculated incorrectly
or otherwise inappropriately included or excluded items from the calculation,
an adjustment reflecting the correction for any prior and prospective period
shall be made in the next Annual Update Filing. However, such an adjustment
shall be made only and to the extent the parties, as part of the informal
dispute resolution process described in Section V.F, above, agree to make such
adjustment; or, if agreement cannot be reached, the Department orders the
adjustment to be made as part of its review of the Annual Update Filing. Any
adjustments to the residual value credit or variable component of the access
charge resulting from this Section V.G shall not be subject to a claim by any
party to this Settlement that such an adjustment constitutes retroactive
ratemaking.
VI. Miscellaneous Provisions
------------------------
VI.A. Boston Edison shall adopt the standards of conduct which were
adopted by the Department in D.P.U. 96-44.
VI.B. Minimum residential customer service safeguards and protections
for consumers in their dealings with competitive power suppliers, as provided
by statute or the rules of the Department, should be maintained.
VI.C. Effective January 1, 2000, Boston Edison shall file with the
Department a proposal to unbundle distribution services that can be provided
competitively, without impairing system reliability or other system benefits.
VI.D. The rights conferred and obligations imposed on any signatory by
this Settlement shall be binding on or inure to the benefit of their
successors in interest or assignees, as if such successor or assignee was
itself a signatory hereto.
<PAGE> 054
VI.E. This Settlement is the product of settlement negotiations. The
content of those negotiations shall be privileged and all offers of settlement
shall be without prejudice to the position of any party or participant
presenting such offer.
VI.F. Except as expressly set forth above, this Settlement is submitted
on the conditions that it be approved in full by the Department and on the
further conditions that if the Department does not approve the Settlement in
its entirety, the Settlement shall be deemed withdrawn and shall not
constitute a part of the record in any proceeding or used for any purpose.
VI.G. Acceptance of this Settlement by the Department shall not be
deemed to restrain the Department's exercise of its authority to promulgate
future orders, regulations or rules which resolve similar matters affecting
other parties in a different fashion, provided, however, that approval of
this Settlement by the Department shall represent an express grant by the
Department of a waiver for Boston Edison of any rule, requirement or
regulation promulgated by the Department under existing statutes as part of
its proceeding on utility restructuring that is inconsistent with the terms
of this Settlement. Nor shall this Settlement be deemed to restrain the
authority of the General Court to enact any law which would resolve the
matters addressed in this Settlement in a different fashion.
VI.H. Neither the terms of this Settlement nor its approval by the
Department shall in any way prevent, constrain or otherwise limit the parties
hereto or the Department from taking any position, making any argument, or
reaching any determination with regard to the corporation reorganization plan
pending before the Department in D.P.U. 97-63 (or any other similar plan), to
any sale, transfer, or use of utility assets/employees/goodwill by or to any
affiliate, and/or to the appropriate ratemaking treatment/recognition to be
applied with regard to any such sale, transfer, or use.
<PAGE>
VI.I. The Department's approval of this Settlement shall endure so
long as is necessary to fulfill this Settlement's objectives. In the event
of future regulatory actions other than actions required by legislative
actions taken prior to the Retail Access Date, or legislative actions after
the Retail Access Date, which may render any part of this Settlement
ineffective, Boston Edison shall nevertheless be held harmless and made whole
through rates to Boston Edison retail customers.
VI.J. The rate of return provisions of this Agreement relate to certain
components of the revenue recovery subject to the adjustments and for the
specific purposes herein specified. Those provisions are not intended to
represent an agreement as to an allowed return as determined in a retail rate
case, they do not establish precedent for future proceedings, and they are
binding only with respect to the parties to the Agreement with respect to the
matters set forth in the Agreement.
Signed and agreed to by each of the following parties.
Respectfully submitted,
\s\ Douglas S. Horan
-----------------------------------------
Douglas S. Horan, Esquire
Senior Vice President and General Counsel
Boston Edison Company
800 Boylston Street
Boston, Massachusetts 02199
July 8, 1997
<PAGE> 056
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ George B. Dean
----------------------------------------------
Name: George B. Dean
Title: Assistant Attorney General,
Chief, Regulated Industries Division
Address: Office of the Attorney General
200 Portland Street
Boston, MA 02114
July 9, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ David L. O'Connor
----------------------------------------------
Name: David L. O'Connor
Title: Commissioner
Address: Commonwealth of Massachusetts
Division of Energy Resources
100 Cambridge Street, Room 1500
Boston, MA 02202
July 8, 1997
<PAGE> 058
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Stephen M. Tulega
----------------------------------------------
Name: Stephen M. Tulega
Title: President
Address: Alternate Power Source
200 Clarendon St. - T-32
Boston, MA 02116
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Joseph S. Fitzpatrick
----------------------------------------------
Name: Joseph S. Fitzpatrick
Title: Senior Vice President
Address: American National Power
108 National Street
Milford, MA 01757
June 25, 1997
<PAGE> 060
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Eugenia Balodimas
----------------------------------------------
Name: Eugenia Balodimas
Title: Associate Counsel - Director of
Regulatory and Legislative Affairs
Address: Citizens Power - The Energy Group
160 Federal Street
Boston, MA 02110-1766
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Neal B. Costello
----------------------------------------------
Name: Neal B. Costello, Esq.
Title: Executive Director
Address: Competitive Power Coalition
9 Park Street - 5th flr.
Boston, MA 02108
June 26, 1997
<PAGE> 062
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Lewis Milford
----------------------------------------------
Name: Lewis Milford
Title: Director, Energy Project
Address: Conservation Law Foundation
21 East State Street
Montpelier, VT -5602
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Judy Massey
----------------------------------------------
Name: Judy Massey
Title: Chair, Consumer Advisory Panel
Address: c/o Boston Edison Company
800 Boylston Street
Boston, MA 02199
June 26, 1997
<PAGE> 064
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Paul Guzzi
----------------------------------------------
Name: Paul Guzzi
Title: President and Chief
Executive Officer
Address: Greater Boston
Chamber of Commerce
One Beacon Street
Boston, MA 02108
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Ellen S. Roy
----------------------------------------------
Ellen S. Roy
Executive Vice President
Intercontinental Energy Corporation
350 Lincoln Place
Hingham, MA 02043
June 27, 1997
<PAGE> 066
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Howard Foley
----------------------------------------------
Name: Howard Foley
Title: President
Address: Massachusetts High Technology Council
1601 Trapelo Road
Waltham, MA 02154
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ William C. Sheehan
----------------------------------------------
Name: William C. Sheehan
Title: President
Address: Northeast Energy and Commerce Association
c/o Financial Management Group
P.O. Box 9116-165
Concord, MA 91742-9116
June 26, 1997
<PAGE> 068
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Roger Borghesani
----------------------------------------------
Name: Roger Borghesani
Title: Chairman, Corporate Energy Council
Address: Polaroid Corporation
1265 Main Street, W2-MA
Waltham, MA 02254
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Paul W. Gromer
----------------------------------------------
Name: Paul W. Gromer
Title: Attorney for
Address: Northeast Energy Efficiency Council
77 North Washington Street
Boston, MA 02114
June 25, 1997
<PAGE> 070
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Jon B. Hurst
----------------------------------------------
Name: Jon B. Hurst
Title: President
Address: Retailers Association of Massachesetts
18 Tremont Street, Suite 702
Boston, MA 02108
June 26, 1997
<PAGE>
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Bruce Paul
----------------------------------------------
Name: Bruce Paul
Title: Chairperson
Address: The Energy Consortium
42 Labor in Vain Road
Ipswich, MA 01938
June 26, 1997
<PAGE> 072
Electric Utility Restructuring Docket Nos. 96-100
Restructuring Settlement Agreement 96-23
\s\ Douglas F. Egan
----------------------------------------------
Name: Douglas F. Egan
Title: Sr. Vice President
Address: U. S. Generating Company
One Bowdoin Square
Boston, MA 02114
June 27, 1997
<PAGE>
ATTACHMENT 1
BOSTON EDISON COMPANY
UNBUNDLED RATES AND
SUPPORTING DOCUMENTATION
<PAGE> 073
Attachment 1
Exhibit 1 Summary of Unbundled Rate Design
for 1998
Exhibit 2 Summary of Proposed 1998 Rates
Exhibit 3 Revenue Reduction Proof by Rate Class
Exhibit 4 Calculation of 1998 Typical Bills
by Rate Class
Exhibit 5 1998 Rate Schedules
Exhibit 6 Rate Design Workpapers
<PAGE> 074
Attachment 1
Exhibit 1
Summary of Unbundled Rate Design for 1998
<PAGE> 075
Boston Edison Company
M.D.P.U. Nos. 96-100 & 96-23
Attachment 1
Exhibit 1
Page 1 of 5
Summary of Unbundled Rate Design for 1998
The first step in developing the rate designs for 1998 was to select
those class billing determinants (number of bills, monthly demands and monthly
on- and off-peak energy consumption) against which to design. Boston Edison
has chosen actual consumption for the year 1995 as the test year. These were
the billing determinants used in our February, 1996 filing with the Department
and have been the basis for the settlement negotiations with the Attorney
General (AG) and the Department of Energy Resources (DOER). From these
billing determinants, we calculated the annual revenues that would be
collected using the base rates which took effect in November, 1994 and the
periodically adjusted charges which were in effect in November, 1996.
Specifically the levels of those adjusted charges were: Fuel and Purchased
Power -- 3.709 cents/KWH; New Performance Adjustment Clause (NPAC) -- 0.481
cents/KWH; Conservation Service Charge -- $0.15 per bill; and Conservation
(DSM) Charges -- R1/R3/R4 - 0.249 cents/KWH, G1/T1 - 0.354 cents/KWH, G2/T2 -
0.381 cents/KWH, and G3 - .0.403 cents/KWH. The revenue levels determined
using these billing determinants and rates were then reduce by 10% for each
class in order to establish the class revenue targets for 1998.
In addition to the class revenue neutrality requirement, the more
stringent criterion of a 10% discount for each and every customer was also
imposed. In essence, this criterion means that the Distribution,
Transmission, Access and Generation components for each class must sum to 90%
of the current Customer, Demand and Energy Charges; i.e., if the current
Customer Charge is $7.15 per bill, then whatever pieces of the Distribution,
Transmission, Access and Generation costs which are collected through a fixed
monthly charge must equal $7.15 time 0.9, or $6.43, in total and likewise with
Demand and Energy related collections.
The Standard Offer for 1998 was set at the negotiated level of 2.8 cents/
KWH.
The NPAC, Conservation Service, and Conservation charges will disappear
as separate charges in 1998 and will become part of the Distribution
collections.
The Transmission Charge is determined from the rate established, reviewed
and accepted by FERC and has been translated into a unit rate of 0.25 cents/
KWH. For the purposes of this Settlement only, the total dollar value
allocated to the various rate classes was developed using the allocation
factors from the February, 1996 DPU filing.
<PAGE> 076
Boston Edison Company
M.D.P.U. Nos. 96-100 & 96-23
Attachment 1
Exhibit 1
Page 2 of 5
The negotiated Access Charge for 1998 is a unit rate of 3.51 cents/KWH.
This rate has been applied uniformly to all customer classes.
The above process sets the total dollar revenues for the Transmission,
Access, and Generation Charges. The only remaining component, Distribution,
is the difference between the 1998 target revenue levels and the sum of the
revenues from the above specified components.
The total dollars for each of the components described above are then
assigned to the Customer, Demand and Energy collection buckets. The
philosophy behind this assignment is to collect the Distribution and
Transmission Charges from the more fixed Customer and Demand Charges and to
collect the Access Charges mostly through the Energy Charges. The general
procedure followed is to assign as much of the Distribution Charges to the
Customer Charge as that Customer Charge is targeted to collect. Then, if the
rate has a Demand Charge, the Transmission Charges are assigned to equal the
target collections of the Demand Charge. If more revenues are needed to
satisfy the target collections from the Demand Charges, then any revenues from
the Distribution Charges left after removing the Customer collected charges
are applied to the Demand collections. If more Demand revenues are needed
after using all Distribution revenues, the Access revenues are applied until
the Demand revenues are equal to target collections. If there is no Demand
Charge in a given rate or if there are remaining Distribution revenues
available after satisfying the Demand requirement, the remaining Distribution
revenues are assigned to the Energy Charge. Likewise any remaining Access
revenues are assigned to the Energy Charges.
Although the Distribution and Access components will be separately
identified on the tariff sheets, they will be combined into a single line on
the customer's bills.
We have prepared an example to better explain the process. Please refer
to the following two page table for the development of the G3 unbundled rate.
The first page calculates the 1998 target revenue level for the G3 class
using the 1995 billing determinants, the base rates which have been in effect
since November, 1995, the periodically adjusted charges at their November,
1996 levels and the adjustment factor of 0.8999244, which is the ratio of the
1998 average cent per KWH to that of the baseline
<PAGE> 077
Boston Edison Company
M.D.P.U. Nos. 96-100 & 96-23
Attachment 1
Exhibit 1
Page 3 of 5
period. It also shows how much money is being collected based on number of
bills, KW demands, and KWH energy consumption (the Customer, Demand and Energy
collections or revenues respectively). The second page shows the derivation
of the various components. First the revenues from the allocated, FERC
approved transmission rates are input ($6,153,090.09) and the Access revenues
are calculated using the 3.51 cents/KWH value and the 2,707,411,279 KWH of
annual energy consumption ($95,030,135.89). Similarly to the Access revenues,
the Generation revenues (labeled "Fuel") are calculated using the 2.8 cents/
KWH Standard Offer rate and the same energy consumption. All of these total
dollars are subtracted from the target revenue level calculated on the first
page, leaving a Distribution amount of $59,715,672.12.
Since the Distribution collections greatly exceed the allowable
collection through the Customer Charge, only $1,268,783.09 of the Distribution
revenues are assigned to the Customer Charge, requiring the other
approximately $58.5 million of Distribution revenues to be collected through
another component of the rate. On the other hand, the allowed Transmission
revenues is much smaller than the target collection through the Demand
Charges. Therefore all of the Transmission revenues are assigned to the
Demand component. The Transmission related rate is derived by dividing the
total Transmission revenues by the total KW billing demands
($6,153,090.09/6,036,921). The Distribution revenues in excess of the
Customer Charge collections are assigned to the Demand Charges and are
calculated by dividing the Demand-related Distribution revenues by the total
Demand revenues and multiplying the quotient by the summer and winter Demand
Rates respectively. This produces time differentiated Distribution rates.
There are still additional collections required from the Demand Charges and so
a portion of the Access revenues is assigned to the Demand Charges to make up
the shortfall to the target Demand rates.
The remaining Access collections are assigned to the Energy Charges.
Basically this occurs by subtracting the Standard Offer and any Distribution
and Transmission rates from the target energy rates shown on the first page.
For example, the winter on-peak target energy charge is 6.0371 cents/KWH while
the other rates are respectively 2.8 cents/KWH for the Standard Offer and
0.000 cents/KWH for both Distribution and Transmission. This leaves a value
of 3.571 cents/KWH for the Access Charge during winter on-peak periods.
The rate unbundling for all the classes has been handled in a similar
fashion except for G1, G2 and T1 where this procedure produced negative
access charges. For these classes, time-varying transmission charges were
implemented to eliminate the negative access charges
<PAGE> 078
<TABLE>
Boston Edison Company
M.D.P.U. Nos. 96-100 & 96-23
Attachment 1
Exhibit 1
Page 4 of 5
G3 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/15/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 5,352 $ 237.07 $ 1,268,783.09 0.8999244
kw $/kw
Demand
Winter 3,768,643 $ 8.85 $ 33,338,385.43
Summer 2,268,278 $ 18.48 $ 41,927,866.72
kwh $/kwh
Energy
Winter
ON-peak 735,984,163 $ 0.06371 $ 46,886,350.29
OFF-peak 982,608,108 $ 0.05298 $ 52,057,154.51
Base ON-peak $ 0.02237
OFF-peak $ 0.01165
DSM $ 0.00363
Fuel $ 0.03338
NPAC $ 0.00433
Summer
ON-peak 334,393,478 $ 0.07373 $ 24,655,101.77
OFF-peak 654,425,530 $ 0.05589 $ 36,572,772.11
Base ON-peak $ 0.03240
OFF-peak $ 0.01455
DSM $ 0.00363
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 236,706,413.92
</TABLE>
<PAGE> 079
<TABLE>
Boston Edison Company
M.D.P.U. Nos. 96-100 & 96-23
Attachment 1
Exhibit 1
Page 5 of 5
G3 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/15/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Demand Energy $/bill $/kw $/kwh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dist $ 59,715,672.12 $ 1,268,783.09 $ 6,522.32 $ 237.07 Dist
$ 25,890,577.41 $ 6.87 Winter
$ - ON-peak
$ - OFF-peak
$ 32,549,789.30 $ 14.35 Summer
$ - ON-peak
$ - OFF-peak
DSM $ - $ - $ - DSM
Trans $ 6,153,090.09 $ - $ - Trans
$ 3,844,015.86 $ 1.02 Winter
$ 2,313,643.56 $ 1.02 Summer
Access $ 95,030,135.89 Access
$ 3,617,897.28 $ 0.96 Winter
$ 26,281,994.46 $ 0.03571 ON-peak
$ 24,535,724.46 $ 0.02497 OFF-peak
$ 7,054,344.58 $ 3.11 Summer
$ 15,288,469.81 $ 0.04572 ON-peak
$ 18,251,928.03 $ 0.02789 OFF-peak
Fuel $ 75,807,515.81 $ 75,807,515.81 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 236,706,413.91 $ 1,268,783.09 $ 75,270,267.99 $ 160,172,154.89 $ 237.07 $ 8.85 $ 0.06371 Winter ON-peak
$ 0.05297 OFF-peak
rates $ 236,704,699.21 $ 18.48 $ 0.07372 Summer ON-peak
$ 0.05589 OFF-peak
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS2.XLS
<PAGE> 080
Attachment 1
Exhibit 2
Summary of Proposed 1998 Rates
<PAGE> 081
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: SUMMARY1 Attachment 1
Exhibit 2
Page 1 of 2
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Summary of Proposed Rates
<CAPTION>
- ---------------------------------------------------------------------------------------------------
R-2 without R-2 with
Space Space
Residential & Street Light Rates R-1 Heating Heating R-3 R-4 S-2
- -------------------------------- --- ------- ------- --- --- ---
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $6.43 $3.91 $3.91 $6.43 $9.99 $8.02
Winter Distribution/Access Charge $0.07815 $0.04848 $0.04212 $0.06759 $0.06001
On-Peak $0.12618
Off-Peak $0.02707
Summer Distribution/Access Charge $0.07815 $0.04848 $0.05470 $0.08856 $0.06001
On-Peak $0.28635
Off-Peak $0.03013
Winter Transmission Charge $0.00244 $0.00242 $0.00242 $0.00241 $0.00162
On-Peak $0.00242
Off-Peak $0.00242
Summer Transmission Charge $0.00244 $0.00242 $0.00242 $0.00241 $0.00162
On-Peak $0.00242
Off-Peak $0.00242
Winter Generation Charge $0.02800 $0.02800 $0.02800 $0.02800 $0.02800
On-Peak $0.02800
Off-Peak $0.02800
Summer Generation Charge $0.02800 $0.02800 $0.02800 $0.02800 $0.02800
On-Peak $0.02800
Off-Peak $0.02800
- ---------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 082
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: SUMMARY2 Attachment 1
Exhibit 2
Page 2 of 2
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Summary of Proposed Rates
<CAPTION>
- ---------------------------------------------------------------------------------------------------------------------
G-1 without G-1 with
Demand Demand
Commercial & Industrial Rates Meters Meters G-2 G-3 T-1 T-2
- ----------------------------- ------ ------ --- --- --- ---
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $8.14 $12.09 $18.19 $237.07 $10.13
with Annual Ratchet kW: First 150kW $27.77
< 300 kW $114.62
> 300 kW $166.67
> 1,000 kW $374.57
Winter Demand Charge - Distribution/Access $7.83 $9.32
- Transmission $1.02 $0.98
- Distribution/Access > 10 kW $0.28 $9.43
- Transmission > 10 kW $3.31 $0.87
Summer Demand Charge - Distribution/Access $17.46 $21.09
- Transmission $1.02 $0.98
- Distribution/Access > 10 kW $0.86 $20.22
- Transmission > 10 kW $10.14 $1.85
Winter Distribution/Access Charge $0.06646
On-Peak $0.03571 $0.10894 $0.03795
Off-Peak $0.02497 $0.02509 $0.02614
1st 2,000 kWh $0.06960 $0.06985
Next 150 hrs. $0.05612 $0.03795
Additional kWh $0.02590 $0.02614
Summer Distribution/Access Charge $0.12926
On-Peak $0.04572 $0.23648 $0.04890
Off-Peak $0.02789 $0.02805 $0.02919
1st 2,000 kWh $0.13241 $0.13267
Next 150 hrs. $0.06709 $0.04891
Additional kWh $0.02895 $0.02919
Winter Transmission Charge $0.00314
On-Peak $0.00000 $0.00351 $0.00000
Off-Peak $0.00000 $0.00081 $0.00000
1st 2,000 kWh $0.00000 $0.00000
Next 150 hrs. $0.00000 $0.00000
Additional kWh $0.00000 $0.00000
Summer Transmission Charge $0.00314
On-Peak $0.00000 $0.00761 $0.00000
Off-Peak $0.00000 $0.00090 $0.00000
1st 2,000 kWh $0.00000 $0.00000
Next 150 hrs. $0.00000 $0.00000
Additional kWh $0.00000 $0.00000
Winter Generation Charge $0.02800
On-Peak $0.02800 $0.02800 $0.02800
Off-Peak $0.02800 $0.02800 $0.02800
1st 2,000 kWh $0.02800 $0.02800
Next 150 hrs. $0.02800 $0.02800
Additional kWh $0.02800 $0.02800
Summer Generation Charge $0.02800
On-Peak $0.02800 $0.02800 $0.02800
Off-Peak $0.02800 $0.02800 $0.02800
1st 2,000 kWh $0.02800 $0.02800
Next 150 hrs. $0.02800 $0.02800
Additional kWh $0.02800 $0.02800
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 083
Attachment 1
Exhibit 3
Revenue Reduction Proof by Rate Class
<PAGE> 084
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-1 Attachment 1
Exhibit 3
Page 1 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate R-1
<CAPTION>
================================================================================================
Present Present Proposed Proposed
R-1 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 4,044,864 $7.15 $28,920,778 $6.43 $26,008,476
2 Energy Charge:
Annual 1,897,991,916 $0.07627 $144,759,843
Retail Fuel & Purchased Power Charge $0.03709 $70,396,520
Net Performance Adjustment Charge $0.00481 $9,129,341
DSM $0.00249 $4,726,000
Distribution/Access Charge $0.07815 $148,328,068
Transmission Charge $0.00244 $4,631,100
Generation Charge $0.02800 $53,143,774
3 Total Design Revenue: $257,932,482 $232,111,418
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 2,022,432 $7.15 $14,460,389 $6.43 $13,004,238
2 Energy Charge:
Annual 948,995,958 $0.07627 $72,379,922
Retail Fuel & Purchased Power Charge $0.03709 $35,198,260
Net Performance Adjustment Charge $0.00481 $4,564,671
DSM $0.00249 $2,363,000
Distribution/Access Charge $0.07815 $74,164,034
Transmission Charge $0.00244 $2,315,550
Generation Charge $0.02800 $26,571,887
3 Total Design Revenue: $128,966,241 $116,055,709
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 6,067,296
kWh: 2,846,987,874
2 Total Design Revenue: $386,898,723 $348,167,127
3 Difference Between Present and Proposed Revenues: ($38,731,597)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 085
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-2 (W/O) Attachment 1
Exhibit 3
Page 2 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate R-2 without Space Heating
<CAPTION>
================================================================================================
Present Present Proposed Proposed
R-2 without Space Heating Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 232,816 $4.35 $1,012,750 $3.91 $910,311
2 Energy Charge:
Winter 42,815,730 $0.04576 $1,959,248
Retail Fuel & Purchased Power Charge $0.03709 $1,588,035
Net Performance Adjustment Charge $0.00481 $205,944
Distribution/Access Charge $0.04848 $2,075,707
Transmission Charge $0.00242 $103,614
Generation Charge $0.02800 $1,198,840
3 Total Design Revenue: $4,765,976 $4,288,472
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 116,408 $4.35 $506,375 $3.91 $455,155
2 Energy Charge:
Summer 85,631,460 $0.04576 $3,918,496
Retail Fuel & Purchased Power Charge $0.03709 $3,176,071
Net Performance Adjustment Charge $0.00481 $411,887
Distribution/Access Charge $0.04848 $4,151,413
Transmission Charge $0.00242 $207,228
Generation Charge $0.02800 $2,397,681
3 Total Design Revenue: $8,012,829 $7,211,477
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 349,224
kWh: 128,447,190
2 Total Design Revenue: $12,778,805 $11,499,949
3 Difference Between Present and Proposed Revenues: ($1,278,856)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 086
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-2 (W/) Attachment 1
Exhibit 3
Page 3 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate R-2 with Space Heating
<CAPTION>
================================================================================================
Present Present Proposed Proposed
R-2 with Space Heating Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 15,992 $4.35 $69,565 $3.91 $62,529
2 Energy Charge:
Winter 17,654,881 $0.03871 $683,420
Retail Fuel & Purchased Power Charge $0.03709 $654,820
Net Performance Adjustment Charge $0.00481 $84,920
Distribution/Access Charge $0.04212 $743,624
Transmission Charge $0.00242 $42,725
Generation Charge $0.02800 $494,337
3 Total Design Revenue: $1,492,725 $1,343,214
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 7,996 $4.35 $34,783 $3.91 $31,264
2 Energy Charge:
Summer 5,070,958 $0.05269 $267,189
Retail Fuel & Purchased Power Charge $0.03709 $188,082
Net Performance Adjustment Charge $0.00481 $24,391
Distribution/Access Charge $0.05470 $277,381
Transmission Charge $0.00242 $12,272
Generation Charge $0.02800 $141,987
3 Total Design Revenue: $514,445 $462,904
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 23,988
kWh: 22,725,839
2 Total Design Revenue: $2,007,170 $1,806,118
3 Difference Between Present and Proposed Revenues: ($201,052)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 087
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-3 Attachment 1
Exhibit 3
Page 4 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate R-3
<CAPTION>
================================================================================================
Present Present Proposed Proposed
R-3 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 333,808 $7.15 $2,386,727 $6.43 $2,146,385
2 Energy Charge:
Winter 404,022,629 $0.06451 $26,063,500
Retail Fuel & Purchased Power Charge $0.03709 $14,985,199
Net Performance Adjustment Charge $0.00481 $1,943,349
DSM $0.00249 $1,006,016
Distribution/Access Charge $0.06759 $27,307,889
Transmission Charge $0.00241 $973,695
Generation Charge $0.02800 $11,312,634
3 Total Design Revenue: $46,384,792 $41,740,603
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 166,904 $7.15 $1,193,364 $6.43 $1,073,193
2 Energy Charge:
Summer 114,426,271 $0.08781 $10,047,771
Retail Fuel & Purchased Power Charge $0.03709 $4,244,070
Net Performance Adjustment Charge $0.00481 $550,390
DSM $0.00249 $284,921
Distribution/Access Charge $0.08856 $10,133,591
Transmission Charge $0.00241 $275,767
Generation Charge $0.02800 $3,203,936
3 Total Design Revenue: $16,320,517 $14,686,486
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 500,712
kWh: 518,448,900
2 Total Design Revenue: $62,705,308 $56,427,089
3 Difference Between Present and Proposed Revenues: ($6,278,219)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 088
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-4 Attachment 1
Exhibit 3
Page 5 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate R-4
<CAPTION>
================================================================================================
Present Present Proposed Proposed
R-4 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 1,120 $11.10 $12,432 $9.99 $11,189
2 Energy Charge:
Winter On-Peak 462,315 $0.12962 $59,925
Off-Peak 991,839 $0.01950 $19,341
Retail Fuel & Purchased Power Charge $0.03709 $53,925
Net Performance Adjustment Charge $0.00481 $6,994
DSM $0.00249 $3,621
Distribution/Access Charge On-Peak $0.12618 $58,335
Off-Peak $0.02707 $26,849
Transmission Charge On-Peak $0.00242 $1,119
Off-Peak $0.00242 $2,400
Generation Charge On-Peak $0.02800 $12,945
Off-Peak $0.02800 $27,771
3 Total Design Revenue: $156,248 $140,608
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 560 $11.10 $6,216 $9.99 $5,594
2 Energy Charge:
Summer On-Peak 146,897 $0.30761 $45,187
Off-Peak 463,596 $0.02289 $10,612
Retail Fuel & Purchased Power Charge $0.03709 $22,643
Net Performance Adjustment Charge $0.00481 $2,936
DSM $0.00249 $1,520
Distribution/Access Charge On-Peak $0.28635 $42,064
Off-Peak $0.03013 $13,968
Transmission Charge On-Peak $0.00242 $355
Off-Peak $0.00242 $1,122
Generation Charge On-Peak $0.02800 $4,113
Off-Peak $0.02800 $12,981
3 Total Design Revenue: $89,114 $80,198
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 1,680
kWh: 2,064,647
2 Total Design Revenue: $245,363 $220,806
3 Difference Between Present and Proposed Revenues: ($24,557)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 089
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-1 (W/O) Attachment 1
Exhibit 3
Page 6 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate G-1 without Demand Meters
<CAPTION>
================================================================================================
Present Present Proposed Proposed
G-1 without Demand Meters Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 374,824 $9.04 $3,388,409 $8.14 $3,051,067
2 Energy Charge:
Winter 227,687,653 $0.06302 $14,348,876
Retail Fuel & Purchased Power Charge $0.03709 $8,444,935
Net Performance Adjustment Charge $0.00481 $1,095,178
DSM $0.00354 $806,014
Distribution/Access Charge $0.06646 $15,132,121
Transmission Charge $0.00314 $714,939
Generation Charge $0.02800 $6,375,254
3 Total Design Revenue: $28,083,412 $25,273,382
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 187,412 $9.04 $1,694,204 $8.14 $1,525,534
2 Energy Charge:
Summer 121,636,340 $0.13282 $16,155,739
Retail Fuel & Purchased Power Charge $0.03709 $4,511,492
Net Performance Adjustment Charge $0.00481 $585,071
DSM $0.00354 $430,593
Distribution/Access Charge $0.12926 $15,722,713
Transmission Charge $0.00314 $381,938
Generation Charge $0.02800 $3,405,818
3 Total Design Revenue: $23,377,098 $21,036,003
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 562,236
kWh: 349,323,993
2 Total Design Revenue: $51,460,510 $46,309,385
3 Difference Between Present and Proposed Revenues: ($5,151,125)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 090
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-1 (W/) Attachment 1
Exhibit 3
Page 7 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate G-1 with Demand Meters
<CAPTION>
================================================================================================
Present Present Proposed Proposed
G-1 with Demand Meters Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 76,016 $13.43 $1,020,895 $12.09 $919,033
2 Demand Charge: > 10 kW 43,537 $3.99 $173,713
- Distribution/Access > 10 kW $0.28 $12,190
- Transmission > 10 kW $3.31 $144,107
3 Energy Charge:
Winter 1st 2,000 kWh 61,874,379 $0.06302 $3,899,323
Next 150 hrs. 13,615,662 $0.04804 $654,096
Additional kWh 10,083,339 $0.01445 $145,704
Retail Fuel & Purchased Power Charge $0.03709 $3,173,917
Net Performance Adjustment Charge $0.00481 $411,608
DSM $0.00354 $302,930
Distribution/Access Charge 1st 2,000 kWh $0.06960 $4,306,457
Next 150 hrs. $0.05612 $764,111
Additional kWh $0.02590 $261,158
Transmission Charge 1st 2,000 kWh $0.00000 $0
Next 150 hrs. $0.00000 $0
Additional kWh $0.00000 $0
Generation Charge 1st 2,000 kWh $0.02800 $1,732,483
Next 150 hrs. $0.02800 $381,239
Additional kWh $0.02800 $282,333
4 Total Design Revenue: $9,782,186 $8,803,112
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 38,008 $13.43 $510,447 $12.09 $459,517
2 Demand Charge: > 10 kW 26,449 $12.22 $323,207
- Distribution/Access > 10 kW $0.86 $22,746
- Transmission > 10 kW $10.14 $268,193
3 Energy Charge:
Summer 1st 2,000 kWh 31,939,174 $0.13282 $4,242,161
Next 150 hrs. 8,258,637 $0.06022 $497,335
Additional kWh 5,511,738 $0.01784 $98,329
Retail Fuel & Purchased Power Charge $0.03709 $1,695,367
Net Performance Adjustment Charge $0.00481 $219,863
DSM $0.00354 $161,812
Distribution/Access Charge 1st 2,000 kWh $0.13241 $4,229,066
Next 150 hrs. $0.06709 $554,072
Additional kWh $0.02895 $159,565
Transmission Charge 1st 2,000 kWh $0.00000 $0
Next 150 hrs. $0.00000 $0
Additional kWh $0.00000 $0
Generation Charge 1st 2,000 kWh $0.02800 $894,297
Next 150 hrs. $0.02800 $231,242
Additional kWh $0.02800 $154,329
4 Total Design Revenue: $7,748,522 $6,973,026
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 114,024
kW: 69,986
kWh: 131,282,929
2 Total Design Revenue: $17,530,708 $15,776,138
3 Difference Between Present and Proposed Revenues: ($1,754,570)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 091
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 3
Page 8 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate G-2
<CAPTION>
================================================================================================
Present Present Proposed Proposed
G-2 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 202,112 $20.21 $4,084,684 $18.19 $3,676,417
2 Demand Charge: > 10 kW 3,489,462 $11.45 $39,954,340
- Distribution/Access > 10 kW $9.43 $32,905,627
- Transmission > 10 kW $0.87 $3,035,832
3 Energy Charge:
Winter 1st 2,000 kWh 337,697,570 $0.06302 $21,281,701
Next 150 hrs. 645,393,157 $0.02757 $17,793,489
Additional kWh 548,255,682 $0.01445 $7,922,295
Retail Fuel & Purchased Power Charge $0.03709 $56,797,638
Net Performance Adjustment Charge $0.00481 $7,365,776
DSM $0.00381 $5,834,430
Distribution/Access Charge 1st 2,000 kWh $0.06985 $23,588,175
Next 150 hrs. $0.03795 $24,492,670
Additional kWh $0.02614 $14,331,404
Transmission Charge 1st 2,000 kWh $0.00000 $0
Next 150 hrs. $0.00000 $0
Additional kWh $0.00000 $0
Generation Charge 1st 2,000 kWh $0.02800 $9,455,532
Next 150 hrs. $0.02800 $18,071,008
Additional kWh $0.02800 $15,351,159
4 Total Design Revenue: $161,034,353 $144,907,824
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 101,056 $20.21 $2,042,342 $18.19 $1,838,209
2 Demand Charge: > 10 kW 2,017,299 $24.52 $49,464,171
- Distribution/Access > 10 kW $20.22 $40,789,786
- Transmission > 10 kW $1.85 $3,732,003
3 Energy Charge:
Summer 1st 2,000 kWh 169,086,564 $0.13282 $22,458,077
Next 150 hrs. 360,563,002 $0.03975 $14,332,379
Additional kWh 321,971,623 $0.01784 $5,743,974
Retail Fuel & Purchased Power Charge $0.03709 $31,586,630
Net Performance Adjustment Charge $0.00481 $4,096,298
DSM $0.00381 $3,244,677
Distribution/Access Charge 1st 2,000 kWh $0.13267 $22,432,714
Next 150 hrs. $0.04891 $17,635,136
Additional kWh $0.02919 $9,398,352
Transmission Charge 1st 2,000 kWh $0.00000 $0
Next 150 hrs. $0.00000 $0
Additional kWh $0.00000 $0
Generation Charge 1st 2,000 kWh $0.02800 $4,734,424
Next 150 hrs. $0.02800 $10,095,764
Additional kWh $0.02800 $9,015,205
4 Total Design Revenue: $132,968,548 $119,671,593
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 303,168
kW: 5,506,761
kWh: 2,382,967,598
2 Total Design Revenue: $294,002,901 $264,579,418
3 Difference Between Present and Proposed Revenues: ($29,423,483)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 092
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 3
Page 9 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate G-3
<CAPTION>
================================================================================================
Present Present Proposed Proposed
G-3 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 3,568 $263.43 $939,918 $237.07 $845,866
2 Demand Charge: 3,768,643 $9.83 $37,045,761
- Distribution/Access $7.83 $29,508,475
- Transmission $1.02 $3,844,016
3 Energy Charge:
Winter On-Peak 735,984,163 $0.02486 $18,296,566
Off-Peak 982,608,108 $0.01294 $12,714,949
Retail Fuel & Purchased Power Charge $0.03709 $63,742,587
Net Performance Adjustment Charge $0.00481 $8,266,429
DSM $0.00403 $6,925,927
Distribution/Access Charge On-Peak $0.03571 $26,281,994
Off-Peak $0.02497 $24,535,724
Transmission Charge On-Peak $0.00000 $0
Off-Peak $0.00000 $0
Generation Charge On-Peak $0.02800 $20,607,557
Off-Peak $0.02800 $27,513,027
4 Total Design Revenue: $147,932,137 $133,136,659
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 1,784 $263.43 $469,959 $237.07 $422,933
2 Demand Charge: 2,268,278 $20.54 $46,590,430
- Distribution/Access $17.46 $39,604,134
- Transmission $1.02 $2,313,644
3 Energy Charge:
Summer On-Peak 334,393,478 $0.03600 $12,038,165
Off-Peak 654,425,530 $0.01617 $10,582,061
Retail Fuel & Purchased Power Charge $0.03709 $36,675,297
Net Performance Adjustment Charge $0.00481 $4,756,219
DSM $0.00403 $3,984,941
Distribution/Access Charge On-Peak $0.04572 $15,288,470
Off-Peak $0.02789 $18,251,928
Transmission Charge On-Peak $0.00000 $0
Off-Peak $0.00000 $0
Generation Charge On-Peak $0.02800 $9,363,017
Off-Peak $0.02800 $18,323,915
4 Total Design Revenue: $115,097,072 $103,568,040
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 5,352
kW: 6,036,921
kWh: 2,707,411,279
2 Total Design Revenue: $263,029,209 $236,704,699
3 Difference Between Present and Proposed Revenues: ($26,324,510)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 093
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-1 Attachment 1
Exhibit 3
Page 10 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate T-1
<CAPTION>
================================================================================================
Present Present Proposed Proposed
T-1 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 40 $11.26 $450 $10.13 $405
2 Energy Charge:
Winter On-Peak 9,823 $0.11063 $1,087
Off-Peak 7,092 $0.01445 $102
Retail Fuel & Purchased Power Charge $0.03709 $627
Net Performance Adjustment Charge $0.00481 $81
DSM $0.00354 $60
Distribution/Access Charge On-Peak $0.10894 $1,070
Off-Peak $0.02509 $178
Transmission Charge On-Peak $0.00351 $34
Off-Peak $0.00081 $6
Generation Charge On-Peak $0.02800 $275
Off-Peak $0.02800 $199
3 Total Design Revenue: $2,408 $2,167
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 20 $11.26 $225 $10.13 $203
2 Energy Charge:
Summer On-Peak 6,406 $0.25689 $1,646
Off-Peak 5,387 $0.01784 $96
Retail Fuel & Purchased Power Charge $0.03709 $437
Net Performance Adjustment Charge $0.00481 $57
DSM $0.00354 $42
Distribution/Access Charge On-Peak $0.23648 $1,515
Off-Peak $0.02805 $151
Transmission Charge On-Peak $0.00761 $49
Off-Peak $0.00090 $5
Generation Charge On-Peak $0.02800 $179
Off-Peak $0.02800 $151
3 Total Design Revenue: $2,503 $2,252
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 60
kWh: 28,708
2 Total Design Revenue: $4,911 $4,420
3 Difference Between Present and Proposed Revenues: ($492)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 094
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 3
Page 11 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate T-2
<CAPTION>
================================================================================================
Present Present Proposed Proposed
T-2 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
Annual
Ratchet kW
----------
1 Customer Charge: First 150 kW 5,176 $30.86 $159,731 $27.77 $143,738
< 300 kW 5,136 $127.37 $654,172 $114.62 $588,688
> 300 kW 4,320 $185.20 $800,064 $166.67 $720,014
> 1,000 kW 728 $416.22 $303,008 $374.57 $272,687
2 Demand Charge: 4,204,405 $11.45 $48,140,437
- Distribution/Access $9.32 $39,185,055
- Transmission $0.98 $4,120,317
3 Energy Charge:
Winter On-Peak 963,496,344 $0.02757 $26,563,594
Off-Peak 1,153,566,477 $0.01445 $16,669,036
Retail Fuel & Purchased Power Charge $0.03709 $78,521,860
Net Performance Adjustment Charge $0.00481 $10,183,072
DSM $0.00381 $8,066,009
Distribution/Access Charge On-Peak $0.03795 $36,564,686
Off-Peak $0.02614 $30,154,228
Transmission Charge On-Peak $0.00000 $0
Off-Peak $0.00000 $0
Generation Charge On-Peak $0.02800 $26,977,898
Off-Peak $0.02800 $32,299,861
4 Total Design Revenue: $190,060,984 $171,027,172
================================================================================================
Section 2. Summer Billing Period (June - September)
Annual
Ratchet kW
----------
1 Customer Charge: First 150 kW 2,588 $30.86 $79,866 $27.77 $71,869
< 300 kW 2,568 $127.37 $327,086 $114.62 $294,344
> 300 kW 2,160 $185.20 $400,032 $166.67 $360,007
> 1,000 kW 364 $416.22 $151,504 $374.57 $136,343
2 Demand Charge: 3,986,644 $24.52 $97,752,511
- Distribution/Access $21.09 $84,078,322
- Transmission $0.98 $3,906,911
3 Energy Charge:
Winter On-Peak 434,841,597 $0.03975 $17,284,953
Off-Peak 719,234,559 $0.01784 $12,831,145
Retail Fuel & Purchased Power Charge $0.03709 $42,804,685
Net Performance Adjustment Charge $0.00481 $5,551,106
DSM $0.00381 $4,397,030
Distribution/Access Charge On-Peak $0.04890 $21,263,754
Off-Peak $0.02919 $20,994,457
Transmission Charge On-Peak $0.00000 $0
Off-Peak $0.00000 $0
Generation Charge On-Peak $0.02800 $12,175,565
Off-Peak $0.02800 $20,138,568
4 Total Design Revenue: $181,579,918 $163,420,140
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 23,040
kW: 8,191,049
kWh: 3,271,138,977
2 Total Design Revenue: $371,640,902 $334,447,312
3 Difference Between Present and Proposed Revenues: ($37,193,591)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 095
<TABLE>
File: S\SHARED\SALESGEN\ACOS1995\RTD98SE2.WK4 Boston Edison Company
Last Updated: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE S-2 Attachment 1
Exhibit 3
Page 12 of 12
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
for Rate S-2
<CAPTION>
================================================================================================
Present Present Proposed Proposed
S-2 Units Rates Revenues Rates Revenues
(1) (2) (3) (4) (5)
================================================================================================
<S> <C> <C> <C> <C> <C>
Section 1. Winter Billing Period (October - May)
1 Customer Charge: 23,504 $8.91 $209,421 $8.02 $188,502
2 Energy Charge:
Annual 34,907,932 $0.05770 $2,014,188
Retail Fuel & Purchased Power Charge $0.03709 $1,294,735
Net Performance Adjustment Charge $0.00481 $167,907
Distribution/Access Charge $0.06001 $2,094,825
Transmission Charge $0.00162 $56,551
Generation Charge $0.02800 $977,422
3 Total Design Revenue: $3,686,251 $3,317,300
================================================================================================
Section 2. Summer Billing Period (June - September)
1 Customer Charge: 11,752 $8.91 $104,710 $8.02 $94,251
2 Energy Charge:
Annual 17,453,966 $0.05770 $1,007,094
Retail Fuel & Purchased Power Charge $0.03709 $647,368
Net Performance Adjustment Charge $0.00481 $83,954
Distribution/Access Charge $0.06001 $1,047,413
Transmission Charge $0.00162 $28,275
Generation Charge $0.02800 $488,711
3 Total Design Revenue: $1,843,125 $1,658,650
================================================================================================
Section 3. Annual Calculation
1 Total Units: Number of Bills: 35,256
kWh: 52,361,898
2 Total Design Revenue: $5,529,376 $4,975,950
3 Difference Between Present and Proposed Revenues: ($553,426)
4 Percent Difference Between Present and Proposed Revenues: -10.0%
================================================================================================
</TABLE>
<PAGE> 096
Attachment 1
Exhibit 4
Calculation of 1998 Typical Bills by Rate Class
<PAGE> 097
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-1 Attachment 1
Exhibit 4
Page 1 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on R-1 Rate Customers
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
125 $200.21 $66.59 $266.80 $198.05 $42.00 $240.05 ($26.75) -13.4% -10.0%
150 $223.09 $79.90 $302.99 $222.22 $50.40 $272.62 ($30.37) -13.6% -10.0%
500 $543.42 $266.34 $809.76 $560.70 $168.00 $728.70 ($81.06) -14.9% -10.0%
750 $772.23 $399.51 $1,171.74 $802.47 $252.00 $1,054.47 ($117.27) -15.2% -10.0%
1,000 $1,001.04 $532.68 $1,533.72 $1,044.24 $336.00 $1,380.24 ($153.48) -15.3% -10.0%
1,250 $1,229.85 $665.85 $1,895.70 $1,286.01 $420.00 $1,706.01 ($189.69) -15.4% -10.0%
1,500 $1,458.66 $799.02 $2,257.68 $1,527.78 $504.00 $2,031.78 ($225.90) -15.5% -10.0%
2,000 $1,916.28 $1,065.36 $2,981.64 $2,011.32 $672.00 $2,683.32 ($298.32) -15.6% -10.0%
- ------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates R-1 Proposed Rates: R-1
<S> <C> <C> <C> <C> <C>
Customer Charge $7.15 Customer Charge $6.43
Energy Charge kWh x $0.07627 Distrib/Access Charge kWh x $0.07815
- ----------------------------------------------------- Transmission Charge kWh x $0.00244
Base Bill Subtotal --------------------------------------
Delivery Component Subtotal
Retail Fuel & Purchased Power Charge kWh x $0.03709
Net Performance Adjustment Charge kWh x $0.00481
DSM kWh x $0.00249 Generation Charge kWh x $0.02800
- -----------------------------------------------------
Combined Adjustment Charge $0.04439
</TABLE>
<PAGE> 098
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-2 (W/O) Attachment 1
Exhibit 4
Page 2 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on R-2 Rate Customers
(without Space Heating)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 $79.66 $25.14 $104.80 $77.46 $16.80 $94.26 ($10.54) -13.2% -10.1%
100 $107.11 $50.28 $157.39 $108.00 $33.60 $141.60 ($15.79) -14.7% -10.0%
150 $134.57 $75.42 $209.99 $138.54 $50.40 $188.94 ($21.05) -15.6% -10.0%
250 $189.48 $125.70 $315.18 $199.62 $84.00 $283.62 ($31.56) -16.7% -10.0%
300 $216.94 $150.84 $367.78 $230.16 $100.80 $330.96 ($36.82) -17.0% -10.0%
500 $326.76 $251.40 $578.16 $352.32 $168.00 $520.32 ($57.84) -17.7% -10.0%
600 $381.67 $301.68 $683.35 $413.40 $201.60 $615.00 ($68.35) -17.9% -10.0%
750 $464.04 $377.10 $841.14 $505.02 $252.00 $757.02 ($84.12) -18.1% -10.0%
- ------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates R-2 Proposed Rates: R-2
<S> <C> <C> <C> <C> <C>
Customer Charge $4.35 Customer Charge $3.91
Energy Charge kWh x $0.04576 Distrib/Access Charge kWh x $0.04848
- ----------------------------------------------------- Transmission Charge kWh x $0.00242
Base Bill Subtotal --------------------------------------
Delivery Component Subtotal
Retail Fuel & Purchased Power Charge kWh x $0.03709
Net Performance Adjustment Charge kWh x $0.00481
DSM kWh x $0.00000 Generation Charge kWh x $0.02800
- -----------------------------------------------------
Combined Adjustment Charge $0.04190
</TABLE>
<PAGE> 099
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-1 (W/) Attachment 1
Exhibit 4
Page 3 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on R-2 Rate Customers
(with Space Heating)
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
250 $177.69 $125.70 $303.39 $188.96 $84.00 $272.96 ($30.43) -17.1% -10.0%
500 $303.18 $251.40 $554.58 $331.00 $168.00 $499.00 ($55.58) -18.3% -10.0%
750 $428.67 $377.10 $805.77 $473.04 $252.00 $725.04 ($80.73) -18.8% -10.0%
1,000 $554.15 $502.80 $1,056.95 $615.08 $336.00 $951.08 ($105.87) -19.1% -10.0%
1,250 $679.64 $628.50 $1,308.14 $757.13 $420.00 $1,177.13 ($131.01) -19.3% -10.0%
1,500 $805.13 $754.20 $1,559.33 $899.17 $504.00 $1,403.17 ($156.16) -19.4% -10.0%
2,000 $1,056.11 $1,005.60 $2,061.71 $1,183.25 $672.00 $1,855.25 ($206.46) -19.5% -10.0%
2,500 $1,307.08 $1,257.00 $2,564.08 $1,467.33 $840.00 $2,307.33 ($256.75) -19.6% -10.0%
- ------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates R-2 Proposed Rates: R-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $4.35 $4.35 Customer Charge $3.91 $3.91
Energy Charge kWh x $0.05269 $0.03871 Distrib/Access
- ----------------------------------------------------- Charge kWh x $0.05470 $0.04212
Base Bill Subtotal Subtotal Transmission
Charge kWh x $0.00242 $0.00242
Retail Fuel & Purchased -----------------------------------------
Power Charge kWh x $0.03709 $0.03709 Delivery
Net Performance Component Subtotal Subtotal
Adjustment Charge kWh x $0.00481 $0.00481
DSM kWh x $0.00000 $0.00000 Generation
- ----------------------------------------------------- Charge kWh x $0.02800 $0.02800
Combined Adjustment Charge $0.04190 $0.04190
</TABLE>
<PAGE> 100
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-3 Attachment 1
Exhibit 4
Page 4 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on R-3 Rate Customers
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
125 $190.28 $66.59 $256.87 $189.10 $42.00 $231.10 ($25.77) -13.5% -10.0%
150 $211.17 $79.90 $291.07 $211.49 $50.40 $261.89 ($29.18) -13.8% -10.0%
500 $503.72 $266.34 $770.06 $524.93 $168.00 $692.93 ($77.13) -15.3% -10.0%
750 $712.67 $399.51 $1,112.18 $748.81 $252.00 $1,000.81 ($111.37) -15.6% -10.0%
1,000 $921.63 $532.68 $1,454.31 $972.70 $336.00 $1,308.70 ($145.61) -15.8% -10.0%
1,250 $1,130.59 $665.85 $1,796.44 $1,196.58 $420.00 $1,616.58 ($179.86) -15.9% -10.0%
1,500 $1,339.55 $799.02 $2,138.57 $1,420.47 $504.00 $1,924.47 ($214.10) -16.0% -10.0%
2,000 $1,757.46 $1,065.36 $2,822.82 $1,868.24 $672.00 $2,540.24 ($282.58) -16.1% -10.0%
- ------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates R-3 Proposed Rates: R-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $7.15 $7.15 Customer Charge $6.43 $6.43
Energy Charge kWh x $0.08781 $0.06451 Distrib/Access
- ----------------------------------------------------- Charge kWh x $0.08856 $0.06759
Base Bill Subtotal Subtotal Transmission
Charge kWh x $0.00241 $0.00241
Retail Fuel & Purchased -----------------------------------------
Power Charge kWh x $0.03709 $0.03709 Delivery
Net Performance Component Subtotal Subtotal
Adjustment Charge kWh x $0.00481 $0.00481
DSM kWh x $0.00249 $0.00249 Generation
- ----------------------------------------------------- Charge kWh x $0.02800 $0.02800
Combined Adjustment Charge $0.04439 $0.04439
</TABLE>
<PAGE> 101
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE R-4 Attachment 1
Exhibit 4
Page 5 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on R-4 Rate Customers
<CAPTION>
- --------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1,000 $918.21 $532.68 $1,450.89 $969.69 $336.00 $1,305.69 ($145.20) -15.8% -10.0%
1,500 $1,310.72 $799.02 $2,109.74 $1,394.59 $504.00 $1,898.59 ($211.15) -16.1% -10.0%
2,000 $1,703.23 $1,065.36 $2,768.59 $1,819.49 $672.00 $2,491.49 ($277.10) -16.3% -10.0%
3,000 $2,488.24 $1,598.04 $4,086.28 $2,669.30 $1,008.00 $3,677.30 ($408.98) -16.4% -10.0%
4,000 $3,273.26 $2,130.72 $5,403.98 $3,519.11 $1,344.00 $4,863.11 ($540.87) -16.5% -10.0%
5,000 $4,058.27 $2,663.40 $6,721.67 $4,368.91 $1,680.00 $6,048.91 ($672.76) -16.6% -10.0%
8,000 $6,413.32 $4,261.44 $10,674.76 $6,918.33 $2,688.00 $9,606.33 ($1,068.43) -16.7% -10.0%
10,000 $7,983.35 $5,326.80 $13,310.15 $8,617.95 $3,360.00 $11,977.95 ($1,332.20) -16.7% -10.0%
- --------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates R-4 Proposed Rates: R-4
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $11.10 $11.10 Customer Charge $9.99 $9.99
Energy Charge On-Peak kWh x $0.30761 $0.12962 Distrib/Access
Off-Peak kWh x $0.02289 $0.01950 On-Peak Charge kWh x $0.28635 $0.12618
- ---------------------------------------------------- Distrib/Access
Base Bill Subtotal Subtotal Off-Peak Charge kWh x $0.03013 $0.02707
Transmission
Retail Fuel & Purchased On-Peak Charge kWh x $0.00242 $0.00242
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Off-Peak Charge kWh x $0.00242 $0.00242
Adjustment Charge kWh x $0.00481 $0.00481 --------------------------------------------
DSM kWh x $0.00249 $0.00249 Delivery Component Subtotal Subtotal
- ----------------------------------------------------
Combined Adjustment Charge $0.04439 $0.04439 Generation Charge
On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 102
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-1 (W/O) Attachment 1
Exhibit 4
Page 6 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-1 Rate Customers
(without Demand Meters)
<CAPTION>
- --------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
50 $160.87 $27.26 $188.13 $152.56 $16.80 $169.36 ($18.77) -11.7% -10.0%
100 $213.27 $54.53 $267.80 $207.44 $33.60 $241.04 ($26.76) -12.5% -10.0%
250 $370.45 $136.32 $506.77 $372.08 $84.00 $456.08 ($50.69) -13.7% -10.0%
500 $632.43 $272.64 $905.07 $646.48 $168.00 $814.48 ($90.59) -14.3% -10.0%
1,000 $1,156.38 $545.28 $1,701.66 $1,195.29 $336.00 $1,531.29 ($170.37) -14.7% -10.0%
2,500 $2,728.22 $1,363.20 $4,091.42 $2,841.70 $840.00 $3,681.70 ($409.72) -15.0% -10.0%
5,000 $5,347.96 $2,726.40 $8,074.36 $5,585.72 $1,680.00 $7,265.72 ($808.64) -15.1% -10.0%
7,500 $7,967.70 $4,089.60 $12,057.30 $8,329.73 $2,520.00 $10,849.73 ($1,207.57) -15.2% -10.0%
- --------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-1 Proposed Rates: G-1
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $9.04 $9.04 Customer Charge $8.14 $8.14
Energy Charge kWh x $0.13282 $0.06302 Distrib/Access
- ---------------------------------------------------- Charge kWh x $0.12926 $0.06646
Base Bill Subtotal Subtotal Transmission
Charge kWh x $0.00314 $0.00314
Retail Fuel & Purchased --------------------------------------------
Power Charge kWh x $0.03709 $0.03709 Delivery Component Subtotal Subtotal
Net Performance
Adjustment Charge kWh x $0.00481 $0.00481
DSM kWh x $0.00354 $0.00354 Generation Charge kWh x $0.02800 $0.02800
- ----------------------------------------------------
Combined Adjustment Charge $0.04544 $0.04544
</TABLE>
<PAGE> 103
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-1 (W/) Attachment 1
Exhibit 4
Page 7 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-1 Rate Customers
(with Demand Meters)
Hours Use: 150
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 2,250 $2,548.57 $1,226.88 $3,775.45 $2,641.57 $756.00 $3,397.57 ($377.88) -14.8% -10.0%
20 3,000 $3,628.39 $1,635.84 $5,264.23 $3,729.35 $1,008.00 $4,737.35 ($526.88) -14.5% -10.0%
40 6,000 $7,947.64 $3,271.68 $11,219.32 $8,080.46 $2,016.00 $10,096.46 ($1,122.86) -14.1% -10.0%
75 11,250 $15,506.34 $6,134.40 $21,640.74 $15,694.91 $3,780.00 $19,474.91 ($2,165.83) -14.0% -10.0%
150 22,500 $31,703.56 $12,268.80 $43,972.36 $32,011.58 $7,560.00 $39,571.58 ($4,400.78) -13.9% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-1 Proposed Rates: G-1
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $13.43 $13.43 Customer Charge $12.09 $12.09
Demand Charge (> 10 kW) kW x $12.22 $3.99 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $0.86 $0.28
(Next 150 hrs.) kWh x $0.06022 $0.04804 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $10.14 $3.31
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13241 $0.06960
(Next 150 hrs.) kWh x $0.06709 $0.05612
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02895 $0.02590
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00354 $0.00354 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04544 $0.04544 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 104
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-1 (W/) Attachment 1
Exhibit 4
Page 8 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-1 Rate Customers
(with Demand Meters)
Hours Use: 300
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 4,500 $4,509.97 $2,453.76 $6,963.73 $4,754.64 $1,512.00 $6,266.64 ($697.09) -15.5% -10.0%
20 6,000 $6,243.58 $3,271.68 $9,515.26 $6,546.77 $2,016.00 $8,562.77 ($952.49) -15.3% -10.0%
40 12,000 $13,178.03 $6,543.36 $19,721.39 $13,715.30 $4,032.00 $17,747.30 ($1,974.09) -15.0% -10.0%
75 22,500 $25,313.32 $12,268.80 $37,582.12 $26,260.24 $7,560.00 $33,820.24 ($3,761.88) -14.9% -10.0%
150 45,000 $51,317.51 $24,537.60 $75,855.11 $53,142.24 $15,120.00 $68,262.24 ($7,592.87) -14.8% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-1 Proposed Rates: G-1
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $13.43 $13.43 Customer Charge $12.09 $12.09
Demand Charge (> 10 kW) kW x $12.22 $3.99 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $0.86 $0.28
(Next 150 hrs.) kWh x $0.06022 $0.04804 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $10.14 $3.31
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13241 $0.06960
(Next 150 hrs.) kWh x $0.06709 $0.05612
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02895 $0.02590
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00354 $0.00354 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04544 $0.04544 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 105
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-1 (W/) Attachment 1
Exhibit 4
Page 9 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-1 Rate Customers
(with Demand Meters)
Hours Use: 450
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 6,750 $6,471.36 $3,680.64 $10,152.00 $6,867.70 $2,268.00 $9,135.70 ($1,016.30) -15.7% -10.0%
20 9,000 $8,858.77 $4,907.52 $13,766.29 $9,364.19 $3,024.00 $12,388.19 ($1,378.10) -15.6% -10.0%
40 18,000 $18,408.41 $9,815.04 $28,223.45 $19,350.15 $6,048.00 $25,398.15 ($2,825.30) -15.3% -10.0%
75 33,750 $35,120.29 $18,403.20 $53,523.49 $36,825.57 $11,340.00 $48,165.57 ($5,357.92) -15.3% -10.0%
150 67,500 $70,931.45 $36,806.40 $107,737.85 $74,272.91 $22,680.00 $96,952.91 ($10,784.94) -15.2% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-1 Proposed Rates: G-1
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $13.43 $13.43 Customer Charge $12.09 $12.09
Demand Charge (> 10 kW) kW x $12.22 $3.99 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $0.86 $0.28
(Next 150 hrs.) kWh x $0.06022 $0.04804 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $10.14 $3.31
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13241 $0.06960
(Next 150 hrs.) kWh x $0.06709 $0.05612
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02895 $0.02590
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00354 $0.00354 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04544 $0.04544 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 106
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 4
Page 10 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-2 Rate Customers
Hours Use: 200
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 3,000 $2,569.37 $1,645.56 $4,214.93 $2,785.15 $1,008.00 $3,793.15 ($421.78) -16.4% -10.0%
20 4,000 $3,994.51 $2,194.08 $6,188.59 $4,225.25 $1,344.00 $5,569.25 ($619.34) -15.5% -10.0%
40 8,000 $9,695.06 $4,388.16 $14,083.22 $9,985.62 $2,688.00 $12,673.62 ($1,409.60) -14.5% -10.0%
75 15,000 $19,671.01 $8,227.80 $27,898.81 $20,066.28 $5,040.00 $25,106.28 ($2,792.53) -14.2% -10.0%
150 30,000 $41,048.05 $16,455.60 $57,503.65 $41,667.69 $10,080.00 $51,747.69 ($5,755.96) -14.0% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-2 Proposed Rates: G-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $20.21 $20.21 Customer Charge $18.19 $18.19
Demand Charge (> 10 kW) kW x $24.52 $11.45 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $20.22 $9.43
(Next 150 hrs.) kWh x $0.03975 $0.02757 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $1.85 $0.87
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13267 $0.06985
(Next 150 hrs.) kWh x $0.04891 $0.03795
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02919 $0.02614
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04571 $0.04571 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 107
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 4
Page 11 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-2 Rate Customers
Hours Use: 250
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 3,750 $2,907.52 $2,056.95 $4,964.47 $3,207.70 $1,260.00 $4,467.70 ($496.77) -17.1% -10.0%
20 5,000 $4,445.37 $2,742.60 $7,187.97 $4,788.64 $1,680.00 $6,468.64 ($719.33) -16.2% -10.0%
40 10,000 $10,596.77 $5,485.20 $16,081.97 $11,112.40 $3,360.00 $14,472.40 ($1,609.57) -15.2% -10.0%
75 18,750 $21,361.73 $10,284.75 $31,646.48 $22,178.99 $6,300.00 $28,478.99 ($3,167.49) -14.8% -10.0%
150 37,500 $44,429.50 $20,569.50 $64,999.00 $45,893.11 $12,600.00 $58,493.11 ($6,505.89) -14.6% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-2 Proposed Rates: G-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $20.21 $20.21 Customer Charge $18.19 $18.19
Demand Charge (> 10 kW) kW x $24.52 $11.45 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $20.22 $9.43
(Next 150 hrs.) kWh x $0.03975 $0.02757 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $1.85 $0.87
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13267 $0.06985
(Next 150 hrs.) kWh x $0.04891 $0.03795
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02919 $0.02614
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04571 $0.04571 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 108
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 4
Page 12 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-2 Rate Customers
Hours Use: 300
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 4,500 $3,245.66 $2,468.34 $5,714.00 $3,630.24 $1,512.00 $5,142.24 ($571.76) -17.6% -10.0%
20 6,000 $4,896.23 $3,291.12 $8,187.35 $5,352.03 $2,016.00 $7,368.03 ($819.32) -16.7% -10.0%
40 12,000 $11,498.49 $6,582.24 $18,080.73 $12,239.19 $4,032.00 $16,271.19 ($1,809.54) -15.7% -10.0%
75 22,500 $23,052.45 $12,341.70 $35,394.15 $24,291.71 $7,560.00 $31,851.71 ($3,542.44) -15.4% -10.0%
150 45,000 $47,810.94 $24,683.40 $72,494.34 $50,118.54 $15,120.00 $65,238.54 ($7,255.80) -15.2% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-2 Proposed Rates: G-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $20.21 $20.21 Customer Charge $18.19 $18.19
Demand Charge (> 10 kW) kW x $24.52 $11.45 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $20.22 $9.43
(Next 150 hrs.) kWh x $0.03975 $0.02757 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $1.85 $0.87
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13267 $0.06985
(Next 150 hrs.) kWh x $0.04891 $0.03795
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02919 $0.02614
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04571 $0.04571 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 109
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 4
Page 13 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-2 Rate Customers
Hours Use: 350
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 5,250 $3,583.81 $2,879.73 $6,463.54 $4,052.78 $1,764.00 $5,816.78 ($646.76) -18.0% -10.0%
20 7,000 $5,347.09 $3,839.64 $9,186.73 $5,915.42 $2,352.00 $8,267.42 ($919.31) -17.2% -10.0%
40 14,000 $12,400.21 $7,679.28 $20,079.49 $13,365.97 $4,704.00 $18,069.97 ($2,009.52) -16.2% -10.0%
75 26,250 $24,743.18 $14,398.65 $39,141.83 $26,404.42 $8,820.00 $35,224.42 ($3,917.41) -15.8% -10.0%
150 52,500 $51,192.39 $28,797.30 $79,989.69 $54,343.97 $17,640.00 $71,983.97 ($8,005.72) -15.6% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-2 Proposed Rates: G-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $20.21 $20.21 Customer Charge $18.19 $18.19
Demand Charge (> 10 kW) kW x $24.52 $11.45 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $20.22 $9.43
(Next 150 hrs.) kWh x $0.03975 $0.02757 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $1.85 $0.87
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13267 $0.06985
(Next 150 hrs.) kWh x $0.04891 $0.03795
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02919 $0.02614
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04571 $0.04571 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 110
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 4
Page 14 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-2 Rate Customers
Hours Use: 400
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 6,000 $3,921.95 $3,291.12 $7,213.07 $4,475.33 $2,016.00 $6,491.33 ($721.74) -18.4% -10.0%
20 8,000 $5,797.95 $4,388.16 $10,186.11 $6,478.81 $2,688.00 $9,166.81 ($1,019.30) -17.6% -10.0%
40 16,000 $13,301.93 $8,776.32 $22,078.25 $14,492.75 $5,376.00 $19,868.75 ($2,209.50) -16.6% -10.0%
75 30,000 $26,433.90 $16,455.60 $42,889.50 $28,517.14 $10,080.00 $38,597.14 ($4,292.36) -16.2% -10.0%
150 60,000 $54,573.83 $32,911.20 $87,485.03 $58,569.40 $20,160.00 $78,729.40 ($8,755.63) -16.0% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-2 Proposed Rates: G-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $20.21 $20.21 Customer Charge $18.19 $18.19
Demand Charge (> 10 kW) kW x $24.52 $11.45 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $20.22 $9.43
(Next 150 hrs.) kWh x $0.03975 $0.02757 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $1.85 $0.87
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13267 $0.06985
(Next 150 hrs.) kWh x $0.04891 $0.03795
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02919 $0.02614
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04571 $0.04571 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 111
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-2 Attachment 1
Exhibit 4
Page 15 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-2 Rate Customers
Hours Use: 450
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
15 6,750 $4,260.10 $3,702.51 $7,962.61 $4,897.87 $2,268.00 $7,165.87 ($796.74) -18.7% -10.0%
20 9,000 $6,248.81 $4,936.68 $11,185.49 $7,042.20 $3,024.00 $10,066.20 ($1,119.29) -17.9% -10.0%
40 18,000 $14,203.65 $9,873.36 $24,077.01 $15,619.53 $6,048.00 $21,667.53 ($2,409.48) -17.0% -10.0%
75 33,750 $28,124.62 $18,512.55 $46,637.17 $30,629.85 $11,340.00 $41,969.85 ($4,667.32) -16.6% -10.0%
150 67,500 $57,955.28 $37,025.10 $94,980.38 $62,794.83 $22,680.00 $85,474.83 ($9,505.55) -16.4% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-2 Proposed Rates: G-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $20.21 $20.21 Customer Charge $18.19 $18.19
Demand Charge (> 10 kW) kW x $24.52 $11.45 Distrib/Access Demand
Energy Charge (1st 2,000 kWh) kWh x $0.13282 $0.06302 Charge (> 10 kW) kW x $20.22 $9.43
(Next 150 hrs.) kWh x $0.03975 $0.02757 Transmission Demand
(Additional kWh) kWh x $0.01784 $0.01445 Charge (> 10 kW) kW x $1.85 $0.87
- ----------------------------------------------------------- Distrib/Access Energy
Base Bill Subtotal Subtotal Charge (1st 2,000 kWh) kWh x $0.13267 $0.06985
(Next 150 hrs.) kWh x $0.04891 $0.03795
Retail Fuel & Purchased Power (Additional kWh) kWh x $0.02919 $0.02614
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge (1st 2,000 kWh) kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 (Next 150 hrs.) kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 (Additional kWh) kWh x $0.00000 $0.00000
- ----------------------------------------------------------- ------------------------------------------------------------------
Combined Adjustment Charge $0.04571 $0.04571 Delivery Component Subtotal Subtotal
Generation Charge (1st 2,000 kWh) kWh x $0.02800 $0.02800
(Next 150 hrs.) kWh x $0.02800 $0.02800
(Additional kWh) kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 112
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 4
Page 16 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-3 Rate Customers
Hours Use: 250
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 150,000 $138,567.40 $82,674.00 $221,241.40 $148,701.55 $50,400.00 $199,101.55 ($22,139.85) -16.0% -10.0%
800 200,000 $183,702.81 $110,232.00 $293,934.81 $197,320.45 $67,200.00 $264,520.45 ($29,414.36) -16.0% -10.0%
1,000 250,000 $228,838.23 $137,790.00 $366,628.23 $245,939.35 $84,000.00 $329,939.35 ($36,688.88) -16.0% -10.0%
1,500 375,000 $341,676.76 $206,685.00 $548,361.76 $367,486.61 $126,000.00 $493,486.61 ($54,875.15) -16.1% -10.0%
3,000 750,000 $680,192.36 $413,370.00 $1,093,562.36 $732,128.37 $252,000.00 $984,128.37 ($109,433.99) -16.1% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-3 Proposed Rates: G-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $263.43 $263.43 Customer Charge $237.07 $237.07
Demand Charge kW x $20.54 $9.83 Distrib/Access Demand
Energy Charge On-Peak kWh x $0.03600 $0.02486 Charge kW x $17.46 $7.83
Off-Peak kWh x $0.01617 $0.01294 Transmission Demand
- ----------------------------------------------------------- Charge kW x $1.02 $1.02
Base Bill Subtotal Subtotal Distrib/Access Energy
Charge On-Peak kWh x $0.04572 $0.03571
Retail Fuel & Purchased Power Off-Peak kWh x $0.02789 $0.02497
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge On-Peak kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00403 $0.00403 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04593 $0.04593
Generation Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 113
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 4
Page 17 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-3 Rate Customers
Hours Use: 300
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 180,000 $145,698.72 $99,208.80 $244,907.52 $159,918.51 $60,480.00 $220,398.51 ($24,509.01) -16.8% -10.0%
800 240,000 $193,211.24 $132,278.40 $325,489.64 $212,276.39 $80,640.00 $292,916.39 ($32,573.25) -16.9% -10.0%
1,000 300,000 $240,723.77 $165,348.00 $406,071.77 $264,634.28 $100,800.00 $365,434.28 ($40,637.49) -16.9% -10.0%
1,500 450,000 $359,505.07 $248,022.00 $607,527.07 $395,529.00 $151,200.00 $546,729.00 ($60,798.07) -16.9% -10.0%
3,000 900,000 $715,848.98 $496,044.00 $1,211,892.98 $788,213.17 $302,400.00 $1,090,613.17 ($121,279.81) -16.9% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-3 Proposed Rates: G-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $263.43 $263.43 Customer Charge $237.07 $237.07
Demand Charge kW x $20.54 $9.83 Distrib/Access Demand
Energy Charge On-Peak kWh x $0.03600 $0.02486 Charge kW x $17.46 $7.83
Off-Peak kWh x $0.01617 $0.01294 Transmission Demand
- ----------------------------------------------------------- Charge kW x $1.02 $1.02
Base Bill Subtotal Subtotal Distrib/Access Energy
Charge On-Peak kWh x $0.04572 $0.03571
Retail Fuel & Purchased Power Off-Peak kWh x $0.02789 $0.02497
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge On-Peak kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00403 $0.00403 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04593 $0.04593
Generation Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 114
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 4
Page 18 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-3 Rate Customers
Hours Use: 350
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 210,000 $152,830.05 $115,743.60 $268,573.65 $171,135.47 $70,560.00 $241,695.47 ($26,878.18) -17.6% -10.0%
800 280,000 $202,719.68 $154,324.80 $357,044.48 $227,232.34 $94,080.00 $321,312.34 ($35,732.14) -17.6% -10.0%
1,000 350,000 $252,609.31 $192,906.00 $445,515.31 $283,329.22 $117,600.00 $400,929.22 ($44,586.09) -17.7% -10.0%
1,500 525,000 $377,333.38 $289,359.00 $666,692.38 $423,571.40 $176,400.00 $599,971.40 ($66,720.98) -17.7% -10.0%
3,000 1,050,000 $751,505.60 $578,718.00 $1,330,223.60 $844,297.97 $352,800.00 $1,197,097.97 ($133,125.63) -17.7% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-3 Proposed Rates: G-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $263.43 $263.43 Customer Charge $237.07 $237.07
Demand Charge kW x $20.54 $9.83 Distrib/Access Demand
Energy Charge On-Peak kWh x $0.03600 $0.02486 Charge kW x $17.46 $7.83
Off-Peak kWh x $0.01617 $0.01294 Transmission Demand
- ----------------------------------------------------------- Charge kW x $1.02 $1.02
Base Bill Subtotal Subtotal Distrib/Access Energy
Charge On-Peak kWh x $0.04572 $0.03571
Retail Fuel & Purchased Power Off-Peak kWh x $0.02789 $0.02497
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge On-Peak kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00403 $0.00403 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04593 $0.04593
Generation Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 115
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 4
Page 19 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-3 Rate Customers
Hours Use: 400
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 240,000 $159,961.37 $132,278.40 $292,239.77 $182,352.42 $80,640.00 $262,992.42 ($29,247.35) -18.3% -10.0%
800 320,000 $212,228.11 $176,371.20 $388,599.31 $242,188.29 $107,520.00 $349,708.29 ($38,891.02) -18.3% -10.0%
1,000 400,000 $264,494.85 $220,464.00 $484,958.85 $302,024.15 $134,400.00 $436,424.15 ($48,534.70) -18.3% -10.0%
1,500 600,000 $395,161.69 $330,696.00 $725,857.69 $451,613.80 $201,600.00 $653,213.80 ($72,643.89) -18.4% -10.0%
3,000 1,200,000 $787,162.22 $661,392.00 $1,448,554.22 $900,382.76 $403,200.00 $1,303,582.76 ($144,971.46) -18.4% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-3 Proposed Rates: G-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $263.43 $263.43 Customer Charge $237.07 $237.07
Demand Charge kW x $20.54 $9.83 Distrib/Access Demand
Energy Charge On-Peak kWh x $0.03600 $0.02486 Charge kW x $17.46 $7.83
Off-Peak kWh x $0.01617 $0.01294 Transmission Demand
- ----------------------------------------------------------- Charge kW x $1.02 $1.02
Base Bill Subtotal Subtotal Distrib/Access Energy
Charge On-Peak kWh x $0.04572 $0.03571
Retail Fuel & Purchased Power Off-Peak kWh x $0.02789 $0.02497
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge On-Peak kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00403 $0.00403 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04593 $0.04593
Generation Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 116
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 4
Page 20 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-3 Rate Customers
Hours Use: 450
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 270,000 $167,092.70 $148,813.20 $315,905.90 $193,569.38 $90,720.00 $284,289.38 ($31,616.52) -18.9% -10.0%
800 360,000 $221,736.54 $198,417.60 $420,154.14 $257,144.23 $120,960.00 $378,104.23 ($42,049.91) -19.0% -10.0%
1,000 450,000 $276,380.39 $248,022.00 $524,402.39 $320,719.08 $151,200.00 $471,919.08 ($52,483.31) -19.0% -10.0%
1,500 675,000 $412,990.00 $372,033.00 $785,023.00 $479,656.20 $226,800.00 $706,456.20 ($78,566.80) -19.0% -10.0%
3,000 1,350,000 $822,818.84 $744,066.00 $1,566,884.84 $956,467.56 $453,600.00 $1,410,067.56 ($156,817.28) -19.1% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-3 Proposed Rates: G-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $263.43 $263.43 Customer Charge $237.07 $237.07
Demand Charge kW x $20.54 $9.83 Distrib/Access Demand
Energy Charge On-Peak kWh x $0.03600 $0.02486 Charge kW x $17.46 $7.83
Off-Peak kWh x $0.01617 $0.01294 Transmission Demand
- ----------------------------------------------------------- Charge kW x $1.02 $1.02
Base Bill Subtotal Subtotal Distrib/Access Energy
Charge On-Peak kWh x $0.04572 $0.03571
Retail Fuel & Purchased Power Off-Peak kWh x $0.02789 $0.02497
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge On-Peak kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00403 $0.00403 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04593 $0.04593
Generation Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 117
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE G-3 Attachment 1
Exhibit 4
Page 21 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on G-3 Rate Customers
Hours Use: 500
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Present Rates Proposed Rates Difference
Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
600 300,000 $174,224.02 $165,348.00 $339,572.02 $204,786.34 $100,800.00 $305,586.34 ($33,985.68) -19.5% -10.0%
800 400,000 $231,244.97 $220,464.00 $451,708.97 $272,100.18 $134,400.00 $406,500.18 ($45,208.79) -19.6% -10.0%
1,000 500,000 $288,265.92 $275,580.00 $563,845.92 $339,414.01 $168,000.00 $507,414.01 ($56,431.91) -19.6% -10.0%
1,500 750,000 $430,818.31 $413,370.00 $844,188.31 $507,698.60 $252,000.00 $759,698.60 ($84,489.71) -19.6% -10.0%
3,000 1,500,000 $858,475.45 $826,740.00 $1,685,215.45 $1,012,552.35 $504,000.00 $1,516,552.35 ($168,663.10) -19.6% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates G-3 Proposed Rates: G-3
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $263.43 $263.43 Customer Charge $237.07 $237.07
Demand Charge kW x $20.54 $9.83 Distrib/Access Demand
Energy Charge On-Peak kWh x $0.03600 $0.02486 Charge kW x $17.46 $7.83
Off-Peak kWh x $0.01617 $0.01294 Transmission Demand
- ----------------------------------------------------------- Charge kW x $1.02 $1.02
Base Bill Subtotal Subtotal Distrib/Access Energy
Charge On-Peak kWh x $0.04572 $0.03571
Retail Fuel & Purchased Power Off-Peak kWh x $0.02789 $0.02497
Charge kWh x $0.03709 $0.03709 Transmission Energy
Net Performance Adjustment Charge On-Peak kWh x $0.00000 $0.00000
Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00403 $0.00403 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04593 $0.04593
Generation Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 118
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-1 Attachment 1
Exhibit 4
Page 22 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-1 Rate Customers
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
200 $380.15 $109.06 $489.21 $373.02 $67.20 $440.22 ($48.99) -12.9% -10.0%
300 $502.66 $163.58 $666.24 $498.75 $100.80 $599.55 ($66.69) -13.3% -10.0%
400 $625.18 $218.11 $843.29 $624.48 $134.40 $758.88 ($84.41) -13.5% -10.0%
500 $747.69 $272.64 $1,020.33 $750.21 $168.00 $918.21 ($102.12) -13.7% -10.0%
600 $870.20 $327.17 $1,197.37 $875.94 $201.60 $1,077.54 ($119.83) -13.8% -10.0%
700 $992.72 $381.70 $1,374.42 $1,001.67 $235.20 $1,236.87 ($137.55) -13.9% -10.0%
800 $1,115.23 $436.22 $1,551.45 $1,127.40 $268.80 $1,396.20 ($155.25) -13.9% -10.0%
900 $1,237.74 $490.75 $1,728.49 $1,253.13 $302.40 $1,555.53 ($172.96) -14.0% -10.0%
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-1 Proposed Rates: T-1
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Customer Charge $11.26 $11.26 Customer Charge $10.13 $10.13
Energy Charge On-Peak kWh x $0.25689 $0.11063 Distrib/Access On-Peak Charge kWh x $0.23648 $0.10894
Off-Peak kWh x $0.01784 $0.01445 Distrib/Access Off-Peak Charge kWh x $0.02805 $0.02509
- ----------------------------------------------------------- Transmission On-Peak Charge kWh x $0.00761 $0.00351
Base Bill Subtotal Subtotal Transmission On-Peak Charge kWh x $0.00090 $0.00081
------------------------------------------------------------------
Retail Fuel & Purchased Power Delivery Component Subtotal Subtotal
Charge kWh x $0.03709 $0.03709
Net Performance Adjustment Generation Charge
Charge kWh x $0.00481 $0.00481 On-Peak kWh x $0.02800 $0.02800
DSM kWh x $0.00354 $0.00354 Off-Peak kWh x $0.02800 $0.02800
- -----------------------------------------------------------
Combined Adjustment Charge $0.04544 $0.04544
</TABLE>
<PAGE> 119
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 4
Page 23 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-2 Rate Customers
Hours Use: 200
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Maximum Present Rates Proposed Rates Difference
Ratchet Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 100 20,000 $27,125.36 $10,970.40 $38,095.76 $27,563.03 $6,720.00 $34,283.03 ($3,812.73) -14.1% -10.0%
300 250 50,000 $68,416.03 $27,426.00 $95,842.03 $69,449.92 $16,800.00 $86,249.92 ($9,592.11) -14.0% -10.0%
1,000 500 100,000 $135,997.58 $54,852.00 $190,849.58 $138,149.00 $33,600.00 $171,749.00 ($19,100.58) -14.0% -10.0%
> 1,000 1,000 200,000 $272,545.01 $109,704.00 $382,249.01 $276,792.75 $67,200.00 $343,992.75 ($38,256.26) -14.0% -10.0%
> 1,000 1,500 300,000 $406,320.19 $164,556.00 $570,876.19 $412,941.71 $100,800.00 $513,741.71 ($57,134.48) -14.1% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-2 Proposed Rates: T-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge with Customer Charge with
Ratchet kW = First 150 kW $30.86 $30.86 Ratchet kW = First 150 kW $27.77 $27.77
< 300 kW $127.37 $127.37 < 300 kW $114.62 $114.62
> 300 kW $185.20 $185.20 > 300 kW $166.67 $166.67
> 1,000 kW $416.22 $416.22 > 1,000 kW $374.57 $374.57
Demand Charge kW x $24.52 $11.45 Distrib/Access
Energy Charge On-Peak kWh x $0.03975 $0.02757 Demand Charge kW x $21.09 $9.32
Off-Peak kWh x $0.01784 $0.01445 Transmission
- ----------------------------------------------------------- Demand Charge kW x $0.98 $0.98
Base Bill Subtotal Subtotal Distrib/Access
Energy Charge On-Peak kWh x $0.04890 $0.03795
Retail Fuel & Purchased Off-Peak kWh x $0.02919 $0.02614
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Energy Charge On-Peak kWh x $0.00000 $0.00000
Adjustment Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04571 $0.04571
Generation
Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 120
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 4
Page 24 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-2 Rate Customers
Hours Use: 250
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Maximum Present Rates Proposed Rates Difference
Ratchet Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 100 25,000 $28,470.74 $13,713.00 $42,183.74 $29,561.92 $8,400.00 $37,961.92 ($4,221.82) -14.8% -10.0%
300 250 62,500 $71,779.48 $34,282.50 $106,061.98 $74,447.13 $21,000.00 $95,447.13 ($10,614.85) -14.8% -10.0%
1,000 500 125,000 $142,724.48 $68,565.00 $211,289.48 $148,143.42 $42,000.00 $190,143.42 ($21,146.06) -14.8% -10.0%
> 1,000 1,000 250,000 $285,998.81 $137,130.00 $423,128.81 $296,781.59 $84,000.00 $380,781.59 ($42,347.22) -14.8% -10.0%
> 1,000 1,500 375,000 $426,500.89 $205,695.00 $632,195.89 $442,924.97 $126,000.00 $568,924.97 ($63,270.92) -14.8% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-2 Proposed Rates: T-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge with Customer Charge with
Ratchet kW = First 150 kW $30.86 $30.86 Ratchet kW = First 150 kW $27.77 $27.77
< 300 kW $127.37 $127.37 < 300 kW $114.62 $114.62
> 300 kW $185.20 $185.20 > 300 kW $166.67 $166.67
> 1,000 kW $416.22 $416.22 > 1,000 kW $374.57 $374.57
Demand Charge kW x $24.52 $11.45 Distrib/Access
Energy Charge On-Peak kWh x $0.03975 $0.02757 Demand Charge kW x $21.09 $9.32
Off-Peak kWh x $0.01784 $0.01445 Transmission
- ----------------------------------------------------------- Demand Charge kW x $0.98 $0.98
Base Bill Subtotal Subtotal Distrib/Access
Energy Charge On-Peak kWh x $0.04890 $0.03795
Retail Fuel & Purchased Off-Peak kWh x $0.02919 $0.02614
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Energy Charge On-Peak kWh x $0.00000 $0.00000
Adjustment Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04571 $0.04571
Generation
Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 121
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 4
Page 25 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-2 Rate Customers
Hours Use: 300
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Maximum Present Rates Proposed Rates Difference
Ratchet Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 100 30,000 $29,816.12 $16,455.60 $46,271.72 $31,560.80 $10,080.00 $41,640.80 ($4,630.92) -15.5% -10.0%
300 250 75,000 $75,142.93 $41,139.00 $116,281.93 $79,444.34 $25,200.00 $104,644.34 ($11,637.59) -15.5% -10.0%
1,000 500 150,000 $149,451.38 $82,278.00 $231,729.38 $158,137.84 $50,400.00 $208,537.84 ($23,191.54) -15.5% -10.0%
> 1,000 1,000 300,000 $299,452.60 $164,556.00 $464,008.60 $316,770.43 $100,800.00 $417,570.43 ($46,438.17) -15.5% -10.0%
> 1,000 1,500 450,000 $446,681.58 $246,834.00 $693,515.58 $472,908.23 $151,200.00 $624,108.23 ($69,407.35) -15.5% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-2 Proposed Rates: T-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge with Customer Charge with
Ratchet kW = First 150 kW $30.86 $30.86 Ratchet kW = First 150 kW $27.77 $27.77
< 300 kW $127.37 $127.37 < 300 kW $114.62 $114.62
> 300 kW $185.20 $185.20 > 300 kW $166.67 $166.67
> 1,000 kW $416.22 $416.22 > 1,000 kW $374.57 $374.57
Demand Charge kW x $24.52 $11.45 Distrib/Access
Energy Charge On-Peak kWh x $0.03975 $0.02757 Demand Charge kW x $21.09 $9.32
Off-Peak kWh x $0.01784 $0.01445 Transmission
- ----------------------------------------------------------- Demand Charge kW x $0.98 $0.98
Base Bill Subtotal Subtotal Distrib/Access
Energy Charge On-Peak kWh x $0.04890 $0.03795
Retail Fuel & Purchased Off-Peak kWh x $0.02919 $0.02614
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Energy Charge On-Peak kWh x $0.00000 $0.00000
Adjustment Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04571 $0.04571
Generation
Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 122
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 4
Page 26 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-2 Rate Customers
Hours Use: 350
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Maximum Present Rates Proposed Rates Difference
Ratchet Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 100 35,000 $31,161.50 $19,198.20 $50,359.70 $33,559.68 $11,760.00 $45,319.68 ($5,040.02) -16.2% -10.0%
300 250 87,500 $78,506.38 $47,995.50 $126,501.88 $84,441.55 $29,400.00 $113,841.55 ($12,660.33) -16.1% -10.0%
1,000 500 175,000 $156,178.28 $95,991.00 $252,169.28 $168,132.26 $58,800.00 $226,932.26 ($25,237.02) -16.2% -10.0%
> 1,000 1,000 350,000 $312,906.40 $191,982.00 $504,888.40 $336,759.27 $117,600.00 $454,359.27 ($50,529.13) -16.1% -10.0%
> 1,000 1,500 525,000 $466,862.28 $287,973.00 $754,835.28 $502,891.49 $176,400.00 $679,291.49 ($75,543.79) -16.2% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-2 Proposed Rates: T-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge with Customer Charge with
Ratchet kW = First 150 kW $30.86 $30.86 Ratchet kW = First 150 kW $27.77 $27.77
< 300 kW $127.37 $127.37 < 300 kW $114.62 $114.62
> 300 kW $185.20 $185.20 > 300 kW $166.67 $166.67
> 1,000 kW $416.22 $416.22 > 1,000 kW $374.57 $374.57
Demand Charge kW x $24.52 $11.45 Distrib/Access
Energy Charge On-Peak kWh x $0.03975 $0.02757 Demand Charge kW x $21.09 $9.32
Off-Peak kWh x $0.01784 $0.01445 Transmission
- ----------------------------------------------------------- Demand Charge kW x $0.98 $0.98
Base Bill Subtotal Subtotal Distrib/Access
Energy Charge On-Peak kWh x $0.04890 $0.03795
Retail Fuel & Purchased Off-Peak kWh x $0.02919 $0.02614
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Energy Charge On-Peak kWh x $0.00000 $0.00000
Adjustment Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04571 $0.04571
Generation
Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 123
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 4
Page 27 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-2 Rate Customers
Hours Use: 400
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Maximum Present Rates Proposed Rates Difference
Ratchet Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 100 40,000 $32,506.88 $21,940.80 $54,447.68 $35,558.57 $13,440.00 $48,998.57 ($5,449.11) -16.8% -10.0%
300 250 100,000 $81,869.83 $54,852.00 $136,721.83 $89,438.76 $33,600.00 $123,038.76 ($13,683.07) -16.7% -10.0%
1,000 500 200,000 $162,905.18 $109,704.00 $272,609.18 $178,126.68 $67,200.00 $245,326.68 ($27,282.50) -16.7% -10.0%
> 1,000 1,000 400,000 $326,360.19 $219,408.00 $545,768.19 $356,748.11 $134,400.00 $491,148.11 ($54,620.08) -16.7% -10.0%
> 1,000 1,500 600,000 $487,042.97 $329,112.00 $816,154.97 $532,874.75 $201,600.00 $734,474.75 ($81,680.22) -16.8% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-2 Proposed Rates: T-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge with Customer Charge with
Ratchet kW = First 150 kW $30.86 $30.86 Ratchet kW = First 150 kW $27.77 $27.77
< 300 kW $127.37 $127.37 < 300 kW $114.62 $114.62
> 300 kW $185.20 $185.20 > 300 kW $166.67 $166.67
> 1,000 kW $416.22 $416.22 > 1,000 kW $374.57 $374.57
Demand Charge kW x $24.52 $11.45 Distrib/Access
Energy Charge On-Peak kWh x $0.03975 $0.02757 Demand Charge kW x $21.09 $9.32
Off-Peak kWh x $0.01784 $0.01445 Transmission
- ----------------------------------------------------------- Demand Charge kW x $0.98 $0.98
Base Bill Subtotal Subtotal Distrib/Access
Energy Charge On-Peak kWh x $0.04890 $0.03795
Retail Fuel & Purchased Off-Peak kWh x $0.02919 $0.02614
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Energy Charge On-Peak kWh x $0.00000 $0.00000
Adjustment Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04571 $0.04571
Generation
Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 124
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE T-2 Attachment 1
Exhibit 4
Page 28 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on T-2 Rate Customers
Hours Use: 450
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Maximum Present Rates Proposed Rates Difference
Ratchet Average Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kW kW kWh Base Factors Total Component Component Total In Totals Base Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
150 100 45,000 $33,852.26 $24,683.40 $58,535.66 $37,557.45 $15,120.00 $52,677.45 ($5,858.21) -17.3% -10.0%
300 250 112,500 $85,233.28 $61,708.50 $146,941.78 $94,435.97 $37,800.00 $132,235.97 ($14,705.81) -17.3% -10.0%
1,000 500 225,000 $169,632.08 $123,417.00 $293,049.08 $188,121.10 $75,600.00 $263,721.10 ($29,327.98) -17.3% -10.0%
> 1,000 1,000 450,000 $339,813.99 $246,834.00 $586,647.99 $376,736.95 $151,200.00 $527,936.95 ($58,711.04) -17.3% -10.0%
> 1,000 1,500 675,000 $507,223.67 $370,251.00 $877,474.67 $562,858.01 $226,800.00 $789,658.01 ($87,816.66) -17.3% -10.0%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates T-2 Proposed Rates: T-2
Summer Winter Summer Winter
------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Customer Charge with Customer Charge with
Ratchet kW = First 150 kW $30.86 $30.86 Ratchet kW = First 150 kW $27.77 $27.77
< 300 kW $127.37 $127.37 < 300 kW $114.62 $114.62
> 300 kW $185.20 $185.20 > 300 kW $166.67 $166.67
> 1,000 kW $416.22 $416.22 > 1,000 kW $374.57 $374.57
Demand Charge kW x $24.52 $11.45 Distrib/Access
Energy Charge On-Peak kWh x $0.03975 $0.02757 Demand Charge kW x $21.09 $9.32
Off-Peak kWh x $0.01784 $0.01445 Transmission
- ----------------------------------------------------------- Demand Charge kW x $0.98 $0.98
Base Bill Subtotal Subtotal Distrib/Access
Energy Charge On-Peak kWh x $0.04890 $0.03795
Retail Fuel & Purchased Off-Peak kWh x $0.02919 $0.02614
Power Charge kWh x $0.03709 $0.03709 Transmission
Net Performance Energy Charge On-Peak kWh x $0.00000 $0.00000
Adjustment Charge kWh x $0.00481 $0.00481 Off-Peak kWh x $0.00000 $0.00000
DSM kWh x $0.00381 $0.00381 ------------------------------------------------------------------
- ----------------------------------------------------------- Delivery Component Subtotal Subtotal
Combined Adjustment Charge $0.04571 $0.04571
Generation
Charge On-Peak kWh x $0.02800 $0.02800
Off-Peak kWh x $0.02800 $0.02800
</TABLE>
<PAGE> 125
<TABLE>
File Name: S\SHARED\SALESGEN\TYPCBILL\TYP98SE2.WK4 Boston Edison Company
Last Update: 28-May-97 M.D.P.U. Nos. 96-100 & 96-23
Range Name: RATE S-2 Attachment 1
Exhibit 4
Page 29 of 29
Boston Edison Company
Settlement Proposal
1998 Rate Designs (Seasonality & Time-of-Use in Access & Distribution)
Impact on S-2 Rate Customers
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------
Average Present Rates Proposed Rates Difference
Monthly Adjustment Annual Delivery Energy Annual Difference % of % of
kWh Base Factors Total Component Component Total In Totals Base Total
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
2,600 $1,907.16 $1,307.28 $3,214.44 $2,019.10 $873.60 $2,892.70 ($321.74) -16.9% -10.0%
3,000 $2,184.12 $1,508.40 $3,692.52 $2,314.92 $1,008.00 $3,322.92 ($369.60) -16.9% -10.0%
3,400 $2,461.08 $1,709.52 $4,170.60 $2,610.74 $1,142.40 $3,753.14 ($417.46) -17.0% -10.0%
3,800 $2,738.04 $1,910.64 $4,648.68 $2,906.57 $1,276.80 $4,183.37 ($465.31) -17.0% -10.0%
4,200 $3,015.00 $2,111.76 $5,126.76 $3,202.39 $1,411.20 $4,613.59 ($513.17) -17.0% -10.0%
4,600 $3,291.96 $2,312.88 $5,604.84 $3,498.22 $1,545.60 $5,043.82 ($561.02) -17.0% -10.0%
5,000 $3,568.92 $2,514.00 $6,082.92 $3,794.04 $1,680.00 $5,474.04 ($608.88) -17.1% -10.0%
5,400 $3,845.88 $2,715.12 $6,561.00 $4,089.86 $1,814.40 $5,904.26 ($656.74) -17.1% -10.0%
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
Present Rates S-2 Proposed Rates: S-2
<S> <C> <C> <C> <C> <C>
Customer Charge $8.91 Customer Charge $8.02
Energy Charge kWh x $0.05770 Distrib/Access Charge kWh x $0.06001
- ----------------------------------------------------- Transmission Charge kWh x $0.00162
Base Bill Subtotal --------------------------------------
Delivery Component Subtotal
Retail Fuel & Purchased Power Charge kWh x $0.03709
Net Performance Adjustment Charge kWh x $0.00481
DSM kWh x $0.00000 Generation Charge kWh x $0.02800
- -----------------------------------------------------
Combined Adjustment Charge $0.04190
</TABLE>
<PAGE> 126
Attachment 1
Exhibit 5
1998 Rate Schedules
<PAGE> 127
B O S T O N E D I S O N C O M P A N Y
-----------------------------------------
S C H E D U L E O F E L E C T R I C R A T E S
---------------------------------------------------
Applying to all territory served by the Company in the following cities
and towns: Acton, Arlington, Ashland, Bedford, Bellingham, Boston, Brookline,
Burlington, Canton, Carlisle, Chelsea, Dedham, Dover, Framingham, Holliston,
Hopkinton, Lexington, Lincoln, Maynard, Medfield, Medway, Millis, Milton,
Natick, Needham, Newton, Norfolk, Sharon, Sherborn, Somerville, Stoneham,
Sudbury, Walpole, Waltham, Watertown, Wayland, Weston, Westwood, Winchester
and Woburn.
<TABLE>
TABLE OF CONTENTS
-----------------
<CAPTION>
RATE SCHEDULE M.D.P.U.
- ------------- --------
<S> <C>
TERMS AND CONDITIONS................................. 839
STANDARD OFFER....................................... 840
STANDARD OFFER ADJUSTMENT PROVISION.................. 841
SHORT-RUN QUALIFYING FACILITY POWER PURCHASE RATE.... 842
GENERAL SERVICE RATE G-1............................. 843
GENERAL SERVICE RATE G-2............................. 844
GENERAL SERVICE RATE G-3............................. 845
OPTIONAL TIME OF USE RATE T-1........................ 846
TIME OF USE RATE T-2................................. 847
RESIDENCE RATE R-1................................... 848
RESIDENCE RATE R-2................................... 849
RESIDENCE RATE R-3................................... 850
OPTIONAL TIME OF USE RATE R-4........................ 851
STREET LIGHTING RATE S-1............................. 852
STREET LIGHTING ENERGY RATE S-2...................... 853
OUTDOOR LIGHTING RATE S-3............................ 854
MISCELLANEOUS CHARGES................................ 855
INTERRUPTIBLE LOAD CREDIT I-C........................ 856
INTERRUPTIBLE LOAD CREDIT I-N........................ 857
ECONOMIC DEVELOPMENT RATE E.......................... 858
TRANSMISSION SERVICE COST ADJUSTMENT PROVISION....... 859
ACCESS COST ADJUSTMENT PROVISION..................... 860
TRANSITION TRUE-UP CHARGE............................ 861
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 128
M.D.P.U. No. 839
Sheet 1
Canceling M.D.P.U. No. 818
BOSTON EDISON COMPANY
TERMS AND CONDITIONS
--------------------
Applicable to all Rates for Electric Service
--------------------------------------------
[ This tariff will be filed with the
Department by July 1, 1997 per
Section I.B.8 of the Settlement
Agreement and is not a condition
of the settlement. ]
<PAGE> 129
M.D.P.U. No. 840
Sheet 1
BOSTON EDISON COMPANY
STANDARD OFFER
--------------
AVAILABILITY
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. After the Retail Access Date customers are free to leave the
Standard Offer at any time to purchase from an alternative supplier. However,
once the market option is selected, a customer may not return to service at
Standard Offer prices. The only exception is during the first year after the
Retail Access Date, when all Rate R-1, R-2, R-3, R-4, T-1, and G-1 customers
who elect to take service from an alternative supplier may return to service
at Standard Offer prices provided that such election is made within 90 days
of first taking service from the alternative supplier.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
DEFINITION
The Standard Offer energy service is provided by energy suppliers who are
designated by the Company to Customers for a fixed period at specified rates.
A Standard Offer Service Customer will pay for Standard Offer Service
according to the Term, Rate, Adjustment, and Availability provisions set forth
below.
TERM
The Company shall arrange to provide Standard Offer Service for the
period from the effective date of this tariff through December 31, 2004.
RATE
The Standard Offer rate will be fixed on the following schedule.
Standard Offer rates may be modified according to the Adjustment provision
below.
<TABLE>
<CAPTION>
Calendar Year Average Price per kilowatt hour
------------- -------------------------------
<S> <C>
1998 2.8 cents
1999 3.1 cents
2000 3.4 cents
2001 3.8 cents
2002 4.2 cents
2003 4.7 cents
2004 5.1 cents
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 130
M.D.P.U. No. 840
Sheet 2
BOSTON EDISON COMPANY
STANDARD OFFER
--------------
The Company's charges for Standard Offer Service are included as a
separate surcharge to the rates for retail delivery service that apply to all
retail customers.
ADJUSTMENT
Standard Offer Service will be put out to bid to interested energy
suppliers and all obligations are fully reconciling. The Company shall
reconcile the revenues billed to retail customers taking Standard Offer
Service against payments to suppliers of Standard Offer service and refund
or recover any over or undercollections on the following terms:
1. Overcollections
Any revenues billed by the Company for Standard Offer Service in excess
of payments to suppliers of that service shall be accumulated in an account
and credited with interest using the methodology for calculating interest on
customer deposits specified in the Company's terms and conditions. The
accumulated balance at the end of each calendar year shall be credited to all
the Company's retail delivery customers through a uniform cents per kilowatt-
hour factor the following year.
2. Undercollections
Standard Offer Rates may also be adjusted from time to time to reflect
changes in the Standard Offer Service Fuel Index or to recover deferred costs
that result from undercollection of expenses for Standard Offer Service as
provided below. These adjustments shall be collected through the Standard
Offer Surcharge as a uniform cents per kilowatt-hour surcharge on the prices
for Standard Offer Service.
For any revenues billed by the Company that do not recover the Company's
payments to suppliers or for any expenses the Company defers to meet the
inflation cap established in Section I.B.9 of the Settlement Agreement, Boston
Edison shall be authorized to accumulate the deficiencies together with
interest and to recover those amounts by implementing a uniform cents per
kilowatthour surcharge on the rates for Standard Offer Service, if and to the
extent that the access charges billed by Boston Edison to its retail customers
are for any reason below the unadjusted access charge listed in Attachment 3
of the Settlement Agreement. Under-recoveries, if any, that remain after the
standard offer transition period ends on December 31, 2004 shall be recovered
from all retail customers by a uniform surcharge to the Standard Offer not
exceeding $0.005 per kilowatthour commencing on January 1, 2005.
Not withstanding any other provisions, in the event the deferred costs
under the Standard Offer at any time accumulate to an amount in excess of
$50 million, Boston Edison shall be
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 131
M.D.P.U. No. 840
Sheet 3
BOSTON EDISON COMPANY
STANDARD OFFER
--------------
authorized to fully recover the amount of deferred costs in excess of $50
million by filing with the Department a Standard Offer Surcharge. Such
Standard Offer Surcharge will be designed to recover the deferred excess costs
forecast for the next twelve (12) months on an annual basis and shall go into
effect sixty (60) days following the filing with the Department. The
collection of deferred excess costs will be through a uniform cents per kWh
surcharge to the Standard Offer until such time as the amount of energy
consumed by retail customers receiving Standard Offer Service reduces to 15
percent of the energy delivered to all retail customers. At that point, the
surcharge will be billed to all retail customers through the delivery charge.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 132
M.D.P.U. No. 841
Sheet 1
BOSTON EDISON COMPANY
STANDARD OFFER ADJUSTMENT PROVISION
-----------------------------------
The Standard Offer Adjustment shall be used to collect surcharges on the
prices for Standard Offer Service through a uniform cents per kilowatt-hour
factor.
Each adjustment of the prices under the Company's applicable rates shall
be in accordance with the following:
The Customer Rate in effect for a given billing month is multiplied
by a "Fuel Adjustment" that is set equal to 1.0 and thus has no
impact on Distribution Company Rates unless the "Market Gas Price"
plus "Market Oil Price" for the billing month exceeds the "Fuel
----
Trigger Point" then in effect, where:
Market Gas Price is the average of the values of "Gas Index" for the
----------------
most recent twelve months through and including the billing month,
where:
Gas Index is the average of the daily settlement prices for the last
---------
three days that the NYMEX Contract (as defined below) for the month
of delivery trades as reported in the "Wall Street Journal",
expressed in dollars per MMBtu. NYMEX Contract shall mean the New
York Mercantile Exchange Natural Gas Futures Contract as approved by
the Commodity Futures Trading Commission for the purchase and sale
of natural gas at Henry Hub;
Market Oil Price is the average of the values of "Oil Index" for the
----------------
most recent twelve months through and including the billing month,
where:
Oil Index is the average for the month of the daily low quotations
---------
for cargo delivery of 1.0% sulphur No. 6 residual fuel oil into New
York Harbor, as reported in "Platt's Pilgrim U.S. Markets Can" in
dollars per barrel and converted to dollars per MMBtu by dividing by
6.3; and
If the indices referred to above should become obsolete or no longer
suitable, the distribution company shall file alternate indices with
the Department.
Fuel Trigger Point is the following amounts, expressed in dollars
------------------
per MMBtu, applicable for all months in the specified calendar year:
<TABLE>
<S> <C>
2000 $5.35/MMBtu
2001 $5.35
2002 $6.09
2003 $7.01
2004 $7.74
</TABLE>
In the event that the Fuel Trigger Point is exceeded, the Fuel
Adjustment value for the billing month is determined based according
to the following formula:
Fuel = (Market Gas Price + $0.60/MMBtu) + (Market Oil Price + $0.04/MMBtu)
Adjustment -------------------------------------------------------------------
Fuel Trigger Point + $0.60 + $0.04/MMBtu
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 133
M.D.P.U. No. 841
Sheet 2
BOSTON EDISON COMPANY
STANDARD OFFER ADJUSTMENT PROVISION
-----------------------------------
Where: Market Gas Price, Market Oil Price and Fuel Trigger Point
are as defined above. The values of $0.60 and $0.04/MMBtu represent
for gas and oil respectively, estimated basis differentials or
market costs of transportation from the point where the index is
calculated to a proxy power plant in the New England market.
For example, if at a point in the year 2002 the Market Gas Price and
Market Oil Price total $6.50 ($3.30/MMBtu plus $3.00/MMBtu
respectively), the Fuel Trigger Point of $6.09 would be exceeded.
In this case the Fuel Adjustment value would be
($3.50 + $0.60/MMBtu) + ($3.00 + $0.04/MMBtu) = 1.0609
------------------------------------------------------
$6.09 + $0.60 + $0.04/MMBtu
The customer Rate paid to the distribution company is increased by
this Fuel Adjustment factor for the billing month, becoming
4.4548 cents/kWh (4.2 x 1.0609).
In subsequent months the same comparisons are made and, if
applicable, a Fuel Adjustment determined.
Incremental revenues received by the distribution company as the
result of a Fuel Adjustment would be allocated to Standard Offer
suppliers in proportion to the Standard Offer energy provided by a
supplier to the distribution company in the applicable billing
month.
A notice filed with the Department of Public Utilities (the Department)
setting forth the amount of the applicable Standard Offer Adjustment, the
amount of the increase and the effective Standard Offer charge in the
Company's rates as adjusted to reflect the new Standard Offer Adjustment
amount. The notice shall further specify the effective date of such
adjustment, which shall not be earlier than thirty days after the filing of
the notice, or such other date as the Department may authorize.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 134
M.D.P.U. No. 842
Sheet 1
Canceling M.D.P.U. No. 819
BOSTON EDISON COMPANY
SHORT-RUN QUALIFYING FACILITY POWER PURCHASE RATE
-------------------------------------------------
AVAILABILITY
Service under this rate is available upon written application to the
Company and execution of a service agreement for the purchase by the Company
of electricity from qualifying small power producers or cogenerators in
accordance with 220 Code of Massachusetts Regulations 8.00 et seq. The
-- ---
Company's obligation to purchase electricity under this rate is preconditioned
upon compliance with the requirements applicable to qualifying small power
producers or cogenerators contained in the following Company publications:
Information and Requirements for Electric Service; Guidelines - Parallel
Operation of Customer Generation; and Interconnection Guidelines.
POWER PURCHASE RATE
(a) Energy Purchase Rate
--------------------
In accordance with 220 CMR 8.04(4)(d), the Company will pay for
energy furnished to it under the terms of this rate schedule at a
price, separately applied to each rating period defined below,
computed according to the following formula:
ER = (F + O&M + SS) x (1 + LL)
where: ER = Energy purchase rate
F = Avoided fuel cost
O&M = Avoided operations and maintenance expense
SS = Avoided cost of a NEPOOL savings share
LL = Cumulative line loss factor
(b) Short-Run Capacity Rate
-----------------------
In accordance with 220 CMR 8.04(5)&(6), to the extent that the sale
by the qualifying facility to the Company is recognized by NEPOOL as
a capacity sale that contributes toward meeting the Company's
capability responsibility, the Company will also pay for capacity
furnished to it under the terms of this rate schedule when the
Company is capacity-deficient or otherwise would be capacity-
deficient without short-run power purchases from qualifying
facilities. The price for such short-run avoidable capacity shall
be calculated on a kilowatthour basis by voltage level according to
the following formula:
SR = (CC/PKH x EAF)) x (1 + DL)
where: SR = The short-run capacity rate.
CC = The NEPOOL Capability Responsibility
Adjustment Charge.
PKH = The number of peak hours in the year.
EAF = The equivalent availability factor of a
typical utility peaking unit.
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<PAGE> 135
M.D.P.U. No. 842
Sheet 2
Canceling M.D.P.U. No. 819
BOSTON EDISON COMPANY
SHORT-RUN QUALIFYING FACILITY POWER PURCHASE RATE
-------------------------------------------------
DL = The cumulative demand loss factor as a decimal
during the peak rating period for the
appropriate voltage level. The demand loss
factor represents the capacity-related
losses through the utility transmission and
distribution system at the time of system
peak demand.
(c) A customer operating small power production or cogeneration
equipment with a design capacity of 30 kilowatts or less may elect
to sell separately metered electricity to the Company on a non-time-
differentiated rate basis. The non-time-differentiated rate is the
Company's energy rate calculated over the total period.
(d) A customer operating small power production or cogeneration
equipment with a design capacity of 30 kilowatts or less may also
elect, where no separate metering is installed, to allow the
Company's usual metering equipment to run backwards and to reduce
the recorded amount of electricity sold to the customer. The
customer will receive an energy payment, but not a capacity payment,
at the current short-run energy rate for the net energy, if any,
delivered to the Company measured by the reduction in the meter
reading below the reading of the previous month. In no event,
however, shall the customer's monthly bill without this credit be
less than the minimum charge as stated in the Company's generally
available rate schedule applicable to the service supplied to the
customer.
(e) The purchase option selected by a customer under this section may
not be changed more frequently than once in any twelve month period.
RATINGS PERIODS
There shall be two rating periods for purposes of computing the Energy
Purchase Rate.
(1) During the months of June through September, the peak demand shall
be the hours between 9 A.M. and 6 P.M. weekdays. During the months
of October through May, the peak period shall be the hours between
8 A.M. and 9 P.M. weekdays.
(2) All other hours shall be off-peak including twelve Massachusetts
holidays as follows:
New Year's Day Labor Day
Martin L. King Day Columbus Day
President's Day Veteran's Day
Patriot's Day Thanksgiving Day
Memorial Day Day after Thanksgiving
Independence Day Christmas Day
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 136
M.D.P.U. No. 842
Sheet 3
Canceling M.D.P.U. No. 819
BOSTON EDISON COMPANY
SHORT-RUN QUALIFYING FACILITY POWER PURCHASE RATE
-------------------------------------------------
INTERCONNECTION REQUIREMENTS
(a) Within 45 days of a request by a qualifying facility according to
the requirements of the Company's Interconnection Guidelines, the
Company will conduct an initial site inspection and will provide a
written estimate of the connection cost and specifications.
(b) The customer shall install interconnection equipment conforming with
the standards filed at the DPU and with the specific requirements of
the Company based on its site inspection and engineering studies.
(c) The customer shall reimburse the Company for all incremental costs
associated with the interconnection of its facilities to accommodate
purchases under this rate including any required metering equipment.
At the customer's option, all costs may be amortized over a period
not in excess of 36 months. If the charges are amortized, the
qualifying facility will pay a monthly charge, approved by the
Department, designed to recover the interconnection costs plus
interest computed at the Company's average weighted cost of capital.
(d) The customer shall maintain such operating records as the Company
may require from time to time and shall allow the Company at its
request to inspect such records or the installation and operation
of the generating equipment and the interconnection.
(e) The customer shall defend, indemnify and hold the Company harmless
from and against all claims or damage to the customer's equipment or
damage or injury to any person or property arising out of the
customer's use of generating equipment in parallel with the
Company's system; provided that nothing in this paragraph shall
relieve the Company from liability for damage or injury caused by
its own willful default or negligence.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
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<PAGE> 137
M.D.P.U. No. 843
Sheet 1
Canceling M.D.P.U. No. 820
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-1
------------------------
AVAILABILITY
Service under this rate is available for all use at a single location
where the monthly demand is less than 10 kilowatts. Demand meters will be
installed for all new customers with either a) three phase service or
b) single phase service exceeding 100 amperes. Customers with a demand
exceeding 12 kilowatts in any month will be placed on Rate G-2. Not available
for residential use.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
FOR CUSTOMERS WITHOUT DEMAND METERS
RETAIL DELIVERY SERVICES
Customer Charge $8.14
---------------
Distribution/Access Charges *
---------------------------
Energy Charge Per Delivered kWh October - May June - September
------------- ----------------
6.646 cents 12.926 cents
Transmission Charge
-------------------
Energy Charge Per Delivered kWh 0.314 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 138
M.D.P.U. No. 843
Sheet 2
Canceling M.D.P.U. No. 820
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-1
------------------------
FOR CUSTOMERS WITH DEMAND METERS
DELIVERY SERVICES
Customer Charge $12.09
---------------
Distribution/Access Charges *
---------------------------
October - May June - September
Demand Charge Per kW ------------- ----------------
(in excess of 10 kilowatts) $0.28 $0.86
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
First 2,000 kWh 6.960 cents 13.241 cents
Next 150 hours use of the billing kW 5.612 cents 6.709 cents
Each Additional kWh 2.590 cents 2.895 cents
Transmission Charge
-------------------
October - May June - September
Demand Charge Per kW ------------- ----------------
(in excess of 10 kilowatts) $3.31 $10.14
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 139
M.D.P.U. No. 843
Sheet 3
Canceling M.D.P.U. No. 820
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-1
------------------------
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is an optional service available under this tariff
for existing or new Customers who have not yet chosen a supplier other than
the Company on or after the retail access date, when retail choice becomes
available to all customers. A Standard Offer Service Customer will pay the
Rate for Standard Offer Service set forth above in addition to the Rates for
Retail Delivery Service. For the first year after the retail access date, if
the Customer has selected an energy supplier other than the Company, the
Customer may elect to return to Standard Offer Service by so notifying the
Company within 90 days of the date when the Customer began to purchase
electricity from the other supplier. Otherwise, the Customer who has selected
another supplier is not eligible for Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Service from the Company in accordance with the terms and
price for Basic Energy Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
METER READING AND BILLING
Bills calculated under this rate schedule are due when presented and
shall be rendered monthly; however, the Company reserves the right to read
meters and render bills on a bimonthly
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 140
M.D.P.U. No. 843
Sheet 4
Canceling M.D.P.U. No. 820
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-1
------------------------
basis. When bills are rendered bimonthly, the Customer Basic Monthly Charge
shall be multiplied by two. The Company may install a demand meter on
existing customer premises where the customer use exceeds 3,000 kilowatt-hours
in any one month.
DETERMINATION OF DEMAND
The billing demand will be the maximum fifteen-minute demand (either
kilowatts or 90 percent of the kilovolt-amperes) as determined by meter during
the monthly billing period. Demands established prior to the application of
this rate shall be considered as having been established under this rate.
TERM OF SERVICE
Customers served under this rate must provide the Company with two years
prior written notice before installing or allowing to be installed for its use
a non-emergency generator with a nameplate capacity greater than that in place
on the Customer's location as of October 1, 1993.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 141
M.D.P.U. No. 844
Sheet 1
Canceling M.D.P.U. No. 821
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-2
------------------------
AVAILABILITY
Service under this rate is available for all use at a single location
where the service voltage is less than 10,000 volts and the monthly demand is
equal to or greater than 10 kilowatts. Rate G-2 customers with demands less
than 8 kilowatts for at least one year will be placed on Rate G-1. Rate G-2
customers with a monthly demand equal to or greater than 200 kW will be
evaluated for transfer to Rate T-2. Additionally, all new customers with a
monthly demand equal to or greater than 200 kW will be placed on Rate T-2.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $18.19
---------------
Distribution/Access Charges *
---------------------------
October - May June - September
Demand Charge Per kW ------------- ----------------
(in excess of 10 kilowatts) $9.43 $20.22
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
First 2,000 kWh 6.985 cents 13.267 cents
Next 150 hours use of the billing kW 3.795 cents 4.891 cents
Each Additional kWh 2.614 cents 2.919 cents
Transmission Charge
-------------------
October - May June - September
Demand Charge Per kW ------------- ----------------
(in excess of 10 kilowatts) $0.87 $1.85
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 142
M.D.P.U. No. 844
Sheet 2
Canceling M.D.P.U. No. 821
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-2
------------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is an optional service available under this tariff
for existing or new Customers who have not yet chosen a supplier other than
the Company on or after the retail access date, when retail choice becomes
available to all customers. A Standard Offer Service Customer will pay the
Rate for Standard Offer Service set forth above in addition to the Rates for
Retail Delivery Service. A customer who has selected another supplier is not
eligible for Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 143
M.D.P.U. No. 844
Sheet 3
Canceling M.D.P.U. No. 821
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-2
------------------------
DETERMINATION OF DEMAND
The billing demand will be the maximum fifteen-minute demand (either
kilowatts or 90 percent of the kilovolt-amperes) as determined by meter during
the monthly billing period, except any demand recorded during off-peak hours
will be reduced by 55 percent (see the Additional Meter Charge below).
Demands established prior to the application of this rate shall be considered
as having been established under this rate.
Separately metered outdoor lighting for recreational facilities which
are owned and operated by a public authority customer of record, such as a
municipality or a state agency, may utilize this rate until it is metered for
Time of Use Rate T-2. For such a customer, the billing demand recorded in the
billing months of June to September will be reduced by 55 percent if no use
other than outdoor recreational lighting is included under this service and
the lights are used only after 6 p.m.
BILLING
In determining if a demand charge reduction is applicable, the following
defines the peak and off-peak periods:
(1) During the months of June through September, the peak period
shall be the hours between 9 A.M. and 6 P.M. weekdays. During
the months of October through May, the peak period shall be the
hours between 8 A.M. and 9 P.M. weekdays.
(2) All other hours shall be off-peak including twelve
Massachusetts holidays as follows:
New Year's Day Labor Day
Martin L. King Day Columbus Day
President's Day Veteran's Day
Patriot's Day Thanksgiving Day
Memorial Day Day after Thanksgiving
Independence Day Christmas Day
ADDITIONAL METER CHARGE
The customer shall be responsible for the cost of all special metering
equipment or if special metering is requested, including the cost of
installation, to ascertain the necessary billing determinants under this rate.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 144
M.D.P.U. No. 844
Sheet 4
Canceling M.D.P.U. No. 821
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-2
------------------------
PRIMARY CREDIT
A credit of two percent of the total bill (not including all other tariff
adjustments and other Miscellaneous Charges and before deduction of the
Transformer Ownership Allowance) will be made when energy is metered at the
nominal voltage of 2,400 volts single phase or 4,160 volts three phase.
TRANSFORMER OWNERSHIP ALLOWANCE
If a customer furnishes, installs, owns and maintains at his expense all
the protective devices, transformers, and other equipment required, as
specified by the Company upon request, the electricity so supplied will be
metered by the Company at line voltage and the monthly demand charges will be
reduced by 12 cents per kilowatt of demand when the demand is 75 kilowatts or
more and the nominal voltage is 2,400 volts single phase or 4,160 volts three
phase.
TERM OF SERVICE
Customers served under this rate must provide the Company with two years
prior written notice before installing or allowing to be installed for its use
a non-emergency generator with a nameplate capacity greater than that in place
on the Customer's location as of October 1, 1993.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 145
M.D.P.U. No. 845
Sheet 1
Canceling M.D.P.U. No. 822
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-3
------------------------
AVAILABILITY
Service under this rate is available for all use at a single location on
contiguous private property if service is supplied to the customer and metered
at 14,000 volts nominal or greater and if the customer furnishes, installs,
owns and maintains at his expense all protective devices, transformers and
other equipment required by the Company. Not available for resale.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $237.07
---------------
Distribution/Access Charges *
---------------------------
October - May June - September
Demand Charge Per kW ------------- ----------------
$7.83 $17.46
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
Peak Hours Use 3.571 cents 4.572 cents
Off-Peak Hours Use 2.497 cents 2.789 cents
Transmission Charge
-------------------
Demand Charge per kW $1.02
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 146
M.D.P.U. No. 845
Sheet 2
Canceling M.D.P.U. No. 822
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-3
------------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or
new Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. A customer who has selected another supplier is not eligible for
Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 147
M.D.P.U. No. 845
Sheet 3
Canceling M.D.P.U. No. 822
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-3
------------------------
DETERMINATION OF DEMAND
The billing demand will be the maximum fifteen-minute demand (either
kilowatts or 90 percent of the kilovolt-amperes) as determined by meter
during the monthly billing period, except any demand recorded during off-peak
hours will be reduced by 70 percent. Demands established prior to the
application of this rate shall be considered as having been established under
this rate.
BILLING
In determining if a demand charge reduction is applicable, the following
defines the peak and off-peak periods:
(1) During the months of June through September, the peak period
shall be the hours between 9 A.M. and 6 P.M. weekdays. During
the months of October through May, the peak period shall be the
hours between 8 A.M. and 9 P.M. weekdays.
(2) All other hours shall be off-peak including twelve
Massachusetts holidays as follows:
New Year's Day Labor Day
Martin L. King Day Columbus Day
President's Day Veteran's Day
Patriot's Day Thanksgiving Day
Memorial Day Day after Thanksgiving
Independence Day Christmas Day
TERM OF SERVICE
Customers served under this rate must provide the Company with two years
prior written notice before installing or allowing to be installed for its use
a non-emergency generator with a nameplate capacity greater than that in place
on the Customer's location as of October 1, 1993.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 148
M.D.P.U. No. 845
Sheet 4
Canceling M.D.P.U. No. 822
BOSTON EDISON COMPANY
GENERAL SERVICE RATE G-3
------------------------
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 149
M.D.P.U. No. 846
Sheet 1
Canceling M.D.P.U. No. 823
BOSTON EDISON COMPANY
OPTIONAL TIME OF USE RATE T-1
-----------------------------
AVAILABILITY
Service under this rate is available for all use at a single location
where the monthly demand is less than 10 kilowatts. Not available for
residential use.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $10.13
---------------
Distribution/Access Charges *
---------------------------
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
Peak Hours Use 10.894 cents 23.648 cents
Off-Peak Hours Use 2.509 cents 2.805 cents
Transmission Charge
-------------------
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
Peak Hours Use 0.351 cents 0.761 cents
Off-Peak Hours Use 0.081 cents 0.090 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 150
M.D.P.U. No. 846
Sheet 2
Canceling M.D.P.U. No. 823
BOSTON EDISON COMPANY
OPTIONAL TIME OF USE RATE T-1
-----------------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. For the first year after the retail access date, if the Customer has
selected an energy supplier other than the Company, the Customer may elect to
return to Standard Offer Service by so notifying the Company within 90 days of
the date when the Customer began to purchase electricity from the other
supplier. Otherwise, the Customer who has selected another supplier is not
eligible for Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 151
M.D.P.U. No. 846
Sheet 3
Canceling M.D.P.U. No. 823
BOSTON EDISON COMPANY
OPTIONAL TIME OF USE RATE T-1
-----------------------------
BILLING PERIODS
Two daily time periods are included in this rate as follows:
(1) During the months of June through September, the peak period
shall be the hours between 9 A.M. and 6 P.M. weekdays. During
the months of October through May, the peak period shall be the
hours between 8 A.M. and 9 P.M. weekdays.
(2) All other hours shall be off-peak including twelve
Massachusetts holidays as follows:
New Year's Day Labor Day
Martin L. King Day Columbus Day
President's Day Veteran's Day
Patriot's Day Thanksgiving Day
Memorial Day Day after Thanksgiving
Independence Day Christmas Day
METER READING AND BILLING
Bills calculated under this rate schedule are due when presented and
shall be rendered monthly; however, the Company reserves the right to read
meters and render bills on a bimonthly basis. When bills are rendered
bimonthly, the Customer Basic Monthly Charge shall be multiplied by two. The
Company may install a demand meter on a customer's premises where the
customer's use exceeds 3,000 kilowatt-hours in any one month so as to evaluate
the customer's load for transfer to Rate T-2.
TERM OF SERVICE
Customers served under this rate must provide the Company with two years
prior written notice before installing or allowing to be installed for its use
a non-emergency generator with a nameplate capacity greater than that in place
on the Customer's location as of October 1, 1993.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 152
M.D.P.U. No. 846
Sheet 4
Canceling M.D.P.U. No. 823
BOSTON EDISON COMPANY
OPTIONAL TIME OF USE RATE T-1
-----------------------------
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 153
M.D.P.U. No. 847
Sheet 1
Canceling M.D.P.U. No. 824
BOSTON EDISON COMPANY
TIME OF USE RATE T-2
--------------------
AVAILABILITY
Service under this rate is available for all use at a single location
where the service voltage is less than 10,000 volts and the monthly demand is
greater than or equal to 10 kW. Customers with monthly demands less than 150
kW will be evaluated for transfer to Rate G-2.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge - The Customer Charge shall be based on the maximum
--------------- monthly billing demand in the most recent twelve
months and will be:
<TABLE>
<S> <C>
Annual maximum billing kW less than or equal to 150 $27.77
Annual maximum billing kW > 150 and less than or equal to 300 $114.62
Annual maximum billing kW > 300 and less than or equal to 1000 $166.67
Annual maximum billing kW > 1000 $374.57
</TABLE>
Distribution/Access Charges *
---------------------------
October - May June - September
Demand Charge Per kW ------------- ----------------
$9.32 $21.09
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
Peak Hours Use 3.795 cents 4.890 cents
Off-Peak Hours Use 2.614 cents 2.919 cents
Transmission Charge
-------------------
Demand Charge per kW $0.98
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 154
M.D.P.U. No. 847
Sheet 2
Canceling M.D.P.U. No. 824
BOSTON EDISON COMPANY
TIME OF USE RATE T-2
--------------------
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. A customer who has selected another supplier is not eligible for
Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 155
M.D.P.U. No. 847
Sheet 3
Canceling M.D.P.U. No. 824
BOSTON EDISON COMPANY
TIME OF USE RATE T-2
--------------------
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
PRIMARY CREDIT
A credit of two percent of the total bill (not including all other tariff
adjustments and other Miscellaneous Charges and before deduction of the
Transformer Ownership Allowance) will be made when energy is metered at the
nominal voltage of 2,400 volts single phase or 4,160 volts three phase.
TRANSFORMER OWNERSHIP ALLOWANCE
If a customer furnishes, installs, owns and maintains at his expense all
the protective devices, transformers, and other equipment required, as
specified by the Company upon request, the electricity so supplied will be
metered by the Company at line voltage and the monthly demand charges will be
reduced by 12 cents per kilowatt of demand when the demand is 75 kilowatts or
more and the nominal voltage is 2,400 volts single phase or 4,160 three phase.
DETERMINATION OF DEMAND
The billing demand will be the maximum fifteen minute demand (either
kilowatts or 90 percent of the kilovolt-amperes) as determined by meter during
the monthly billing period, except any demand recorded during off-peak hours
will be reduced by 55 percent. Demands established prior to the application
of this rate shall be considered as having been established under this rate.
BILLING
In determining if a demand charge reduction is applicable, the following
defines the peak and off-peak periods:
(1) During the months of June through September, the peak period
shall be the hours between 9 A.M. and 6 P.M. weekdays. During
the months of October through May, the peak period shall be the
hours between 8 A.M. and 9 P.M. weekdays.
(2) All other hours shall be off-peak including twelve
Massachusetts holidays as follows:
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 156
M.D.P.U. No. 847
Sheet 4
Canceling M.D.P.U. No. 824
BOSTON EDISON COMPANY
TIME OF USE RATE T-2
--------------------
New Year's Day Labor Day
Martin L. King Day Columbus Day
President's Day Veteran's Day
Patriot's Day Thanksgiving Day
Memorial Day Day after Thanksgiving
Independence Day Christmas Day
TERM OF SERVICE
Customers served under this rate must provide the Company with two years
prior written notice before installing or allowing to be installed for its use
a non-emergency generator with a nameplate capacity greater than that in place
on the Customer's location as of October 1, 1993.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 157
M.D.P.U. No. 848
Sheet 1
Canceling M.D.P.U. No. 825
BOSTON EDISON COMPANY
RESIDENTIAL RATE R-1
--------------------
AVAILABILITY
Service under this rate is available for lighting, heating and other uses
in residential premises, for service in an edifice set apart exclusively for
public worship, condominium common areas (per M.G.L. Chapter 164 Section 94H),
and cooperative apartment common areas (per DPU 1720) excluding hotels and
apartment buildings of ten or more dwelling units where the bills are not
rendered by the Company directly to the individual tenants. Not available for
commercial or industrial use. This rate is closed for expansion to nursing
homes.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $6.43
---------------
Distribution/Access Charges *
---------------------------
Energy Charge Per Delivered kWh 7.815 cents
Transmission Charge
-------------------
Energy Charge Per kWh 0.244 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 158
M.D.P.U. No. 848
Sheet 2
Canceling M.D.P.U. No. 825
BOSTON EDISON COMPANY
RESIDENTIAL RATE R-1
--------------------
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. For the first year after the retail access date, if the Customer has
selected an energy supplier other than the Company, the Customer may elect to
return to Standard Offer Service by so notifying the Company within 90 days of
the date when the Customer began to purchase electricity from the other
supplier. Otherwise, the Customer who has selected another supplier is not
eligible for Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE:
The minimum charge per month is the Customer Charge.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 159
M.D.P.U. No. 848
Sheet 3
Canceling M.D.P.U. No. 825
BOSTON EDISON COMPANY
RESIDENTIAL RATE R-1
--------------------
APARTMENTS OR MULTIPLE DWELLINGS
In an apartment building or residential premises having more than one
dwelling unit (but not more than nine), service may be rendered through a
single meter, but the Customer Charge shall be multiplied by two.
On and after the date upon which the Company receives sufficient notice
from the customer that the multiple dwelling premises served is a condominium
or cooperative, the customer will be entitled to receive service to common
areas and facilities of the condominium or cooperative on this Rate, to the
extent provided by the terms of Chapter 164, section 94H and DPU 1720,
respectively.
METER READING AND BILLING
Bills calculated under this rate schedule are payable when presented and
shall be rendered monthly; however, the Company reserves the right to read
meters and render bills on bimonthly basis. When bills are rendered
bimonthly, the Customer Charge shall be multiplied by two.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
TERM OF CONTRACT
The customer may terminate delivery service at any time by giving ten
days' notice, provided that such termination is not made for the purpose of
obtaining the advantage of this rate for periods of less than one year. If
the notice is oral, the Company may notify the customer in writing that a
written confirmation is required.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 160
M.D.P.U. No. 849
Sheet 1
Canceling M.D.P.U. No. 826
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-2
------------------------
AVAILABILITY
Service under this rate is available for lighting, heating and other uses
in residential premises only to current qualified customers in an individual
private dwelling or an individual apartment, providing such customer meets the
following criteria:
1. Must be the head of a household or principal wage earner, and
2. Must be presently receiving:
(a) Supplemental Security Income from the Social Security
Administration, or
(b) Aid to Families with Dependent Children, General Relief,
Refugee Assistance, Medicaid, or Food Stamps from the
Massachusetts Department of Public Welfare.
(c) Veteran's Service Benefits (G.L. c.115) from the Massachusetts
Veteran Services Administration.
(d) Low Income Heating Energy Assistance Program (LIHEAP) services
from a certified Community Action Program Agency.
It is the responsibility of the customer to certify annually, by forms
provided by the Company, the continued compliance with the foregoing
qualifications. Billing shall begin for service on this rate as of the
billing month following the date on which the Company receives verification
of eligibility from the certifying Government Agency.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $3.91
---------------
Distribution/Access Charges *
---------------------------
Energy Charge Per Delivered kWh
without space heating qualifying
for Rate R-1: 4.848 cents
with space heating qualifying October - May June - September
for Rate R-3: ------------- ----------------
4.212 cents 5.470 cents
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 161
M.D.P.U. No. 849
Sheet 2
Canceling M.D.P.U. No. 826
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-2
------------------------
Transmission Charge
-------------------
Energy Charge Per kWh 0.242 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. For the first year after the retail access date, if the Customer has
selected an energy supplier other than the Company, the Customer may elect to
return to Standard Offer Service by so notifying the Company within 90 days of
the date when the Customer began to purchase electricity from the other
supplier. Otherwise, the Customer who has selected another supplier is not
eligible for Standard Offer Service.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 162
M.D.P.U. No. 849
Sheet 3
Canceling M.D.P.U. No. 826
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-2
------------------------
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
SAFETY NET SERVICE
The Company shall arrange to provide electric supply for low-income
customers who are no longer eligible to receive Standard Offer Service and are
unable to obtain or retain electric service from competitive power suppliers.
Service under this provision shall be made available at prices, terms, and
conditions approved by the Department. The Company shall fully recover the
reasonable costs it incurs in arranging this service.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
METER READING AND BILLING
Bills calculated under this rate schedule are payable when presented and
shall be rendered monthly; however, the Company reserves the right to read
meters and render bills on bimonthly basis. When bills are rendered
bimonthly, the Customer Charge shall be multiplied by two.
TERM OF CONTRACT
The customer may terminate delivery service at any time by giving ten
days' notice, provided that such termination is not made for the purpose of
obtaining the advantage of this rate for periods of less than one year. If
the notice is oral, the Company may notify the customer in writing that a
written confirmation is required.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 163
M.D.P.U. No. 849
Sheet 4
Canceling M.D.P.U. No. 826
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-2
------------------------
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 164
M.D.P.U. No. 850
Sheet 1
Canceling M.D.P.U. No. 827
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-3
------------------------
AVAILABILITY
Service under this rate is available for domestic uses in residential
premises, for service in an edifice set apart exclusively for public worship,
and condominium common areas (per M.G.L. Chapter 164 Section 94H), and
cooperative apartment common areas (Per DPU 1720) with total electric water
and space heating requirements, and whose electric equipment installations
have been approved by the Company, excluding hotels and apartment buildings
of ten or more dwelling units where the bills are not rendered by the Company
directly to the individual tenants. Not available for commercial or
industrial use. This rate is closed for expansion to nursing homes or master
metered apartment buildings.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $6.43
---------------
Distribution/Access Charges *
---------------------------
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
6.759 cents 8.856 cents
Transmission Charge
-------------------
Energy Charge Per kWh 0.241 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 165
M.D.P.U. No. 850
Sheet 2
Canceling M.D.P.U. No. 827
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-3
------------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. For the first year after the retail access date, if the Customer has
selected an energy supplier other than the Company, the Customer may elect to
return to Standard Offer Service by so notifying the Company within 90 days of
the date when the Customer began to purchase electricity from the other
supplier. Otherwise, the Customer who has selected another supplier is not
eligible for Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 166
M.D.P.U. No. 850
Sheet 3
Canceling M.D.P.U. No. 827
BOSTON EDISON COMPANY
GENERAL SERVICE RATE R-3
------------------------
APARTMENTS OR MULTIPLE DWELLINGS
In an apartment building or residential premises having more than one
dwelling unit (but not more than nine), service may be rendered through a
single meter, but the Customer Charge shall be multiplied by two.
On and after the date upon which the Company receives sufficient notice
from the customer that the multiple dwelling premises served is a condominium
or cooperative, the customer will be entitled to receive service to common
areas and facilities of the condominium or cooperative on this Rate, to the
extent provided by the terms of Chapter 164, section 94H and DPU 1720,
respectively.
METER READING AND BILLING
Bills calculated under this rate schedule are payable when presented and
shall be rendered monthly; however, the Company reserves the right to read
meters and render bills on bimonthly basis. When bills are rendered
bimonthly, the Customer Charge shall be multiplied by two.
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges shall apply
to service under this rate.
TERM OF CONTRACT
The customer may terminate delivery service at any time by giving ten
days' notice, provided that such termination is not made for the purpose of
obtaining the advantage of this rate for periods of less than one year. If
the notice is oral, the Company may notify the customer in writing that a
written confirmation is required.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 167
M.D.P.U. No. 851
Sheet 1
Canceling M.D.P.U. No. 828
BOSTON EDISON COMPANY
OPTIONAL RESIDENCE TIME OF USE RATE R-4
---------------------------------------
AVAILABILITY
Service under this rate is available for lighting, heating and other uses
in single dwelling unit premises and apartments (single phase service), for
service in an edifice set apart exclusively for public worship and for
condominium common areas served at secondary voltages. Not available for
commercial or industrial use.
MONTHLY CHARGE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $9.99
Distribution/Access Charges *
---------------------------
October - May June - September
Energy Charge Per Delivered kWh ------------- ----------------
Peak Hours Use 12.618 cents 28.635 cents
Off-Peak Hours Use 2.707 cents 3.013 cents
Transmission Charge
-------------------
Energy Charge Per kWh 0.242 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 168
M.D.P.U. No. 851
Sheet 2
Canceling M.D.P.U. No. 828
BOSTON EDISON COMPANY
OPTIONAL RESIDENCE TIME OF USE RATE R-4
---------------------------------------
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. For the first year after the retail access date, if the Customer has
selected an energy supplier other than the Company, the Customer may elect to
return to Standard Offer Service by so notifying the Company within 90 days of
the date when the Customer began to purchase electricity from the other
supplier. Otherwise, the Customer who has selected another supplier is not
eligible for Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
BILLING PERIODS
Two daily time periods are included in this rate as follows:
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 169
M.D.P.U. No. 851
Sheet 3
Canceling M.D.P.U. No. 828
BOSTON EDISON COMPANY
OPTIONAL RESIDENCE TIME OF USE RATE R-4
---------------------------------------
(1) During the months of June through September, the peak period
shall be the hours between 9 A.M. and 6 P.M. weekdays. During
the months of October through May, the peak period shall be the
hours between 8 A.M. and 9 P.M. weekdays.
(2) All other hours shall be off-peak including twelve
Massachusetts holidays as follows:
New Year's Day Labor Day
Martin L. King Day Columbus Day
President's Day Veteran's Day
Patriot's Day Thanksgiving Day
Memorial Day Day after Thanksgiving
Independence Day Christmas Day
METER READING AND BILLING
Bills calculated under this rate schedule are payable when presented and
shall be rendered monthly.
TERM OF CONTRACT
Customer may terminate delivery service at any time by giving ten days'
notice provided that such termination is not made for the purpose of obtaining
the advantage of this rate for periods of less than one year. If the notice
is oral, the Company may notify the customer in writing that a written
confirmation is required.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 170
M.D.P.U. No. 852
Sheet 1
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
AVAILABILITY
Service under this rate is available for Street and Fire-Alarm Lighting
Service in the Public Way. For lighting service on private property refer to
Rate S-3.
RATE
STREET LIGHTING SERVICE
Unit Charge Per Month for
Standard 4200-hour Lighting Schedule
Size of Lamp Luminaire O.H. Connected - Class I
Lumens Watts Type Distribution/Access Transmission
- ------ ----- ---- ------------------- ------------
Incandescent Lamps
1,000 87 Open $7.85 $0.08
2,500 176 Open 9.57 0.10
2,500 176 Enclosed 9.57 0.10
4,000 274 Enclosed 11.47 0.12
6,000 376 Enclosed 13.47 0.14
10,000 577 Enclosed 17.24 0.18
15,000 855 Enclosed 22.53 0.23
2- 2,500 Enclosed, Twin 19.15 0.20
2- 4,000 Enclosed, Twin 22.96 0.24
2- 6,000 Enclosed, Twin 26.93 0.28
2-10,000 Enclosed, Twin 34.49 0.36
2-15,000 Enclosed, Twin 45.05 0.47
Mercury Vapor Lamps
3,500 100 Enclosed $8.80 $0.09
7,000 175 Enclosed 10.43 0.11
11,000 250 Enclosed 12.07 0.13
20,000 400 Enclosed 15.48 0.16
35,000 700 Enclosed 23.28 0.24
2- 3,500 Enclosed, Twin 17.61 0.18
2- 7,000 Enclosed, Twin 20.85 0.22
2-11,000 Enclosed, Twin 24.13 0.25
2-20,000 Enclosed, Twin 30.94 0.32
2-35,000 Enclosed, Twin 46.55 0.48
High Pressure Sodium Vapor Lamps
2,150 35 Enclosed $6.98 $0.07
4,000 50 Enclosed 7.36 0.08
9,500 100 Enclosed 8.53 0.09
16,000 150 Enclosed 9.64 0.10
25,000 250 Enclosed 12.40 0.13
45,000 400 Enclosed 16.06 0.17
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 171
M.D.P.U. No. 852
Sheet 2
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
2- 2,150 Enclosed, Twin $13.96 $0.14
2- 4,000 Enclosed, Twin 14.72 0.15
2- 9,500 Enclosed, Twin 17.07 0.18
2-16,000 Enclosed, Twin 19.28 0.20
2-25,000 Enclosed, Twin 24.81 0.26
2-45,000 Enclosed, Twin 32.13 0.33
Unit Charge Per Month for
Standard 4200-hour Lighting Schedule
Size of Lamp Luminaire O.H. Connected - Class II
Lumens Watts Type Distribution/Access Transmission
- ------ ----- ---- ------------------- ------------
Incandescent Lamps
1,000 87 Open $12.59 $0.08
2,500 176 Open 14.31 0.10
2,500 176 Enclosed 14.31 0.10
4,000 274 Enclosed 16.21 0.12
6,000 376 Enclosed 18.20 0.14
10,000 577 Enclosed 21.98 0.18
15,000 855 Enclosed 27.26 0.23
2- 2,500 Enclosed, Twin 23.89 0.20
2- 4,000 Enclosed, Twin 27.69 0.24
2- 6,000 Enclosed, Twin 31.67 0.28
2-10,000 Enclosed, Twin 39.22 0.36
2-15,000 Enclosed, Twin 49.79 0.47
Mercury Vapor Lamps
3,500 100 Enclosed $13.54 $0.09
7,000 175 Enclosed 15.16 0.11
11,000 250 Enclosed 16.80 0.13
20,000 400 Enclosed 20.21 0.16
35,000 700 Enclosed 28.02 0.24
2- 3,500 Enclosed, Twin 22.35 0.18
2- 7,000 Enclosed, Twin 25.59 0.22
2-11,000 Enclosed, Twin 28.87 0.25
2-20,000 Enclosed, Twin 35.68 0.32
2-35,000 Enclosed, Twin 51.28 0.48
High Pressure Sodium Vapor Lamps
2,150 35 Enclosed $11.72 $0.07
4,000 50 Enclosed 12.10 0.08
9,500 100 Enclosed 13.27 0.09
16,000 150 Enclosed 14.38 0.10
25,000 250 Enclosed 17.14 0.13
45,000 400 Enclosed 20.80 0.17
2- 2,150 Enclosed, Twin 18.69 0.14
2- 4,000 Enclosed, Twin 19.46 0.15
2- 9,500 Enclosed, Twin 21.81 0.18
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 172
M.D.P.U. No. 852
Sheet 3
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
2-16,000 Enclosed, Twin $24.01 $0.20
2-25,000 Enclosed, Twin 29.55 0.26
2-45,000 Enclosed, Twin 36.86 0.33
Unit Charge Per Month for
Standard 4200-hour Lighting Schedule
Size of Lamp Luminaire O.H. Connected - Class III
Lumens Watts Type Distribution/Access Transmission
- ------ ----- ---- ------------------- ------------
Incandescent Lamps
1,000 87 Open $14.48 $0.08
2,500 176 Open 16.20 0.10
2,500 176 Enclosed 16.20 0.10
4,000 274 Enclosed 18.11 0.12
6,000 376 Enclosed 20.10 0.14
10,000 577 Enclosed 23.88 0.18
15,000 855 Enclosed 29.16 0.23
2- 2,500 Enclosed, Twin 25.78 0.20
2- 4,000 Enclosed, Twin 29.59 0.24
2- 6,000 Enclosed, Twin 33.57 0.28
2-10,000 Enclosed, Twin 41.12 0.36
2-15,000 Enclosed, Twin 51.68 0.47
Mercury Vapor Lamps
3,500 100 Enclosed $15.43 $0.09
7,000 175 Enclosed 17.06 0.11
11,000 250 Enclosed 18.70 0.13
20,000 400 Enclosed 22.11 0.16
35,000 700 Enclosed 29.91 0.24
2- 3,500 Enclosed, Twin 24.24 0.18
2- 7,000 Enclosed, Twin 27.48 0.22
2-11,000 Enclosed, Twin 30.76 0.25
2-20,000 Enclosed, Twin 37.57 0.32
2-35,000 Enclosed, Twin 53.18 0.48
High Pressure Sodium Vapor Lamps
2,150 35 Enclosed $13.61 $0.07
4,000 50 Enclosed 13.99 0.08
9,500 100 Enclosed 15.16 0.09
16,000 150 Enclosed 16.27 0.10
25,000 250 Enclosed 19.03 0.13
45,000 400 Enclosed 22.69 0.17
2- 2,150 Enclosed, Twin 20.59 0.14
2- 4,000 Enclosed, Twin 21.36 0.15
2- 9,500 Enclosed, Twin 23.70 0.18
2-16,000 Enclosed, Twin 25.91 0.20
2-25,000 Enclosed, Twin 31.45 0.26
2-45,000 Enclosed, Twin 38.76 0.33
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 173
M.D.P.U. No. 852
Sheet 4
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
Unit Charge Per Month for
Standard 4200-hour Lighting Schedule
Size of Lamp Luminaire U.G. Connected - Class V
Lumens Watts Type Distribution/Access Transmission
- ------ ----- ---- ------------------- ------------
Incandescent Lamps
1,000 87 Open $23.96 $0.08
2,500 176 Open 25.68 0.10
2,500 176 Enclosed 25.68 0.10
4,000 274 Enclosed 27.58 0.12
6,000 376 Enclosed 29.57 0.14
10,000 577 Enclosed 33.35 0.18
15,000 855 Enclosed 38.63 0.23
2- 2,500 Enclosed, Twin 35.26 0.20
2- 4,000 Enclosed, Twin 39.06 0.24
2- 6,000 Enclosed, Twin 43.04 0.28
2-10,000 Enclosed, Twin 50.59 0.36
2-15,000 Enclosed, Twin 61.16 0.47
Mercury Vapor Lamps
3,500 100 Enclosed $24.91 $0.09
7,000 175 Enclosed 26.53 0.11
11,000 250 Enclosed 28.17 0.13
20,000 400 Enclosed 31.58 0.16
35,000 700 Enclosed 39.38 0.24
2- 3,500 Enclosed, Twin 33.72 0.18
2- 7,000 Enclosed, Twin 36.96 0.22
2-11,000 Enclosed, Twin 40.24 0.25
2-20,000 Enclosed, Twin 47.05 0.32
2-35,000 Enclosed, Twin 62.65 0.48
High Pressure Sodium Vapor Lamps
2,150 35 Enclosed $23.08 $0.07
4,000 50 Enclosed 23.47 0.08
9,500 100 Enclosed 24.64 0.09
16,000 150 Enclosed 25.75 0.10
25,000 250 Enclosed 28.51 0.13
45,000 400 Enclosed 32.17 0.17
2- 2,150 Enclosed, Twin 30.06 0.14
2- 4,000 Enclosed, Twin 30.83 0.15
2- 9,500 Enclosed, Twin 33.17 0.18
2-16,000 Enclosed, Twin 35.38 0.20
2-25,000 Enclosed, Twin 40.92 0.26
2-45,000 Enclosed, Twin 48.23 0.33
Note 1: The above charges are based on the use of the Company's
standard bracket of not over 6 feet in length. A standard
twelve foot bracket will be supplied,
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<PAGE> 174
M.D.P.U. No. 852
Sheet 5
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
where requested by the Customer, at an additional monthly
charge of $0.54 per month.
Note 2: The above charges for Rate Classes III and V are based on
concrete post installations for standard mounting heights of
up to 30 feet. For installations utilizing either aluminum
posts or nonstandard mounting heights of greater than 30 feet,
an additional charge of $3.86 shall be added to the Class III
and Class V monthly charges.
Note 3: Incandescent lamps will not be supplied hereunder for new
installations, but only for replacement of existing lamps.
Note 4: The 45,000 lumen lamps are not recommended for mounting
heights of less than 30 feet.
OVERHEAD-CONNECTED STREET LIGHTING UNITS
Class I All overhead-connected lighting units except those in Classes II
or III.
Class II All overhead-connected lighting units installed with non-line
poles.
Class III All overhead-connected lighting units installed with lampposts.
UNDERGROUND-CONNECTED STREET LIGHTING UNITS
Class V All existing underground-connected lighting units or modernization
of existing units.
Standard Offer Charge (Optional)
- ---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
- --------------------
<TABLE>
FIRE-ALARM LIGHTING SERVICE
<CAPTION>
Unit Charge per Month
Size of Lamp Lighting Schedule Class Distribution/Access Transmission
- ------------ ----------------- ----- ------------------- ------------
<S> <C> <C> <C> <C>
600 Lumen 8,760 hours per year Class VI $4.21 $0.04
Class VII $7.35 $0.04
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 175
M.D.P.U. No. 852
Sheet 6
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
Class VI Overhead-connected fire-alarm luminaires.
Class VII Underground-connected fire-alarm luminaires.
Fire-alarm luminaires are installed and owned by the Company on customer-
owned fire-alarm posts or on Company-owned fixtures carried on poles. Colored
fire-alarm globes or domes are installed and maintained at the customer's
expense.
Standard Offer Charge (Optional)
- ---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
- --------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. A customer who has selected another supplier is not eligible for
Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 176
M.D.P.U. No. 852
Sheet 7
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Service. In this case, a Customer will
receive Basic Service from the Company in accordance with the terms and price
for Basic Service as approved by the Department of Public Utilities.
SERVICE FACILITIES
Under this rate the Company will furnish, install, own, and maintain
street lighting facilities and fire alarm lighting units on public streets.
Service for non-standard lighting units is available in accordance with the
provisions of Rate S-2. Service for other public or private property is
available in accordance with the provisions of Rate S-3.
It is the Company's policy to offer a wide range of industry accepted
energy efficient streetlights. In cases where a city/town requests additions
to the Company's existing schedule of streetlights, the Company will:
1) evaluate the market potential of the streetlight to assure there is
adequate interest to meet minimum ordering requirements, 2) determine the
technical merit and feasibility of the proposed addition to the existing
schedule, and 3) share the costs of 1 and 2 with the proponents of the change.
Any suggested changes to the schedule arising from the proposal will be
subject to DPU review and approval. The Company reserves the right to
withdraw this policy if the number of requests exceed the Company's resources
available to provide 1 and 2 above.
For new overhead-connected services, the Company will provide a standard
lighting unit and a single span of overhead secondary wire if such span is
necessary. All other construction costs will be undertaken, solely at
customer expense.
For new underground-connected services, the Company will provide a
standard lighting unit and a single section of underground secondary cable
from the service manhole. All other construction, including the installation
of conduit and manhole breaks, modifications to the service manhole,
extensions of the existing distribution system to the service manhole, and
all paving, will be undertaken solely at customer expense.
GENERAL CONDITIONS
If a customer requests a change to a unit less than twenty-five years
old, the customer will pay a charge equal to the cost of the change multiplied
by the ratio of the number of years remaining until the existing installation
would be in service twenty-five years divided by twenty-five. For changes to
a portion of an individual street, or the entire street, or all lighting units
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 177
M.D.P.U. No. 852
Sheet 8
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
provided under this rate, the Company will determine the age on the basis of
the average age of all units to be changed. During any calendar year, the
remaining portion of the costs will be assumed by the Company up to a limit
of ten percent of the prior calendar year's revenue from the customer,
exclusive of the fuel and purchased power adjustment. Once the limit is
exceeded, all costs of changes for the remainder of the calendar year will be
paid by the customer.
Customer requests to relocate lighting units, regardless of age, will be
provided solely at customer expense. Alternatively, the customer may also
terminate service at the old location and apply for new service.
If a street light installation in a Company approved Underground
Residential Development (URD) area was made prior to October 31, 1992 an
allowance of $2.02 per month will be made from the Class V unit charge
contained herein.
If the Metropolitan District Commission, has furnished and installed a
lamppost and a bracket acceptable to the Company and continues to own and
maintain such installation, pursuant to order in DPU 14132, an allowance of
$2.04 per month will be made from the Class V unit charges.
OUTAGE ALLOWANCE
A deduction for lamps not lighted during the hours called for by the
existing street lighting schedule applying thereto will be made at the rate
of 1.3 cents per lamp hour on all lamps smaller than 10,000 lumens, and at
the rate of 3.1 cents per lamp hour on all other lamps.
BILLING
All bills calculated under this rate schedule are due when presented and
shall be rendered monthly. Billing kilowatthours include lamp wattage plus
accessory wattage.
TERM OF CONTRACT
Lighting units are installed by the Company for use at this rate on the
basis of permanent service. The Company or the customer may terminate
permanent delivery service by giving at least ninety (90) days notice in
writing. If the customer desires to remove Company-owned installations
without replacement by the Company, the customer will pay to the Company,
the portion of the installation cost (current costs trended to the date of
installation) determined by the ratio of: (1) Twenty-five years minus the
age of such installation to (2) Twenty-five years. The customer will also
pay the cost of removal of such installation. If temporary service is
desired, the
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 178
M.D.P.U. No. 852
Sheet 9
Canceling M.D.P.U. No. 829A
BOSTON EDISON COMPANY
STREETLIGHTING RATE S-1
-----------------------
customer will be required to pay the cost of installation and removal and in
such case the customer may terminate service by giving ten days' notice in
writing.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 179
M.D.P.U. No. 853
Sheet 1
Canceling M.D.P.U. No. 830
BOSTON EDISON COMPANY
STREET LIGHTING ENERGY RATE S-2
-------------------------------
AVAILABILITY
Service under this rate is available to the public authorities, such as
municipalities, State and Federal agencies, for the operation of a public
street, park or highway lighting system, owned, operated and maintained by
such agencies, on a standard 4,200 hour per year dusk-to-dawn lighting
schedule; and for the operation of fire alarm lighting service and traffic
signals. Not available for lighting service on private property nor for
commercial, industrial or residential use.
RATE
The Monthly Charge will be the sum of the Retail Delivery Service
and the Supplier Service Charges.
DELIVERY SERVICES
Customer Charge $8.02
---------------
Distribution/Access Charges *
---------------------------
Energy Charge Per Delivered kWh 6.001 cents
Transmission Charge
-------------------
Energy Charge Per kWh 0.162 cents
* includes Access Cost Adjustment Charge Per kWh of 3.510 cents
SUPPLIER SERVICES
Standard Offer Charge (Optional)
---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
--------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 180
M.D.P.U. No. 853
Sheet 2
Canceling M.D.P.U. No. 830
BOSTON EDISON COMPANY
STREET LIGHTING ENERGY RATE S-2
-------------------------------
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. A customer who has selected another supplier is not eligible for
Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Energy Service. In this case, a Customer
will receive Basic Energy Service from the Company in accordance with the
terms and price for Basic Service as approved by the Department of Public
Utilities.
MINIMUM CHARGE
The minimum charge per month is the Customer Charge.
METER READING AND BILLING
Bills calculated under this rate schedule are due when presented and
shall be rendered monthly; however, the Company reserves the right to read
meters and render bills on a bimonthly basis. When bills are rendered
bimonthly, the Customer Charge shall be multiplied by two.
In a case in which it is not practicable to determine by meter the
kilowatt-hours supplied, the charge for the kilowatt-hours supplied in any
month shall be determined on the basis of the
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<PAGE> 181
M.D.P.U. No. 853
Sheet 3
Canceling M.D.P.U. No. 830
BOSTON EDISON COMPANY
STREET LIGHTING ENERGY RATE S-2
-------------------------------
rated wattage of the light sources and auxiliaries connected at the beginning
of the month multiplied by the average monthly burning hours of a standard
4,200 hours per year dusk-to-dawn street lighting schedule. The Company
shall have the right to inspect and make tests of the customer's equipment in
connection with the determination of wattage and operating period for billing
purposes. The customer shall give the Company prior written notice of changes
in the wattage and operating period of installed equipment.
If in the case of unmetered service, the standard 4,200 hours per year
dusk-to-dawn street lighting schedule is being exceeded, as is commonly the
case with a fire alarm unit, the charge for the kilowatt-hours supplied in
any month shall be determined on the basis of the rated wattage of the light
sources and auxiliaries connected at the beginning of the month multiplied by
the average monthly burning hours of an 8,760 hours per year lighting
schedule, unless a determination of an operating period of shorter duration
is made by the Company, in which case the average monthly burning hours of
such annual lighting schedule (minimum of 4,200 hours per year) shall be
substituted for the 8,760 hours per year lighting schedule.
The Company reserves the right of final determination of wattage and
operating period for unmetered loads.
SERVICE FACILITIES
The Company will furnish, own, install and maintain the cable system in
the public way and up to two feet beyond the edge of the public way. The
Company will own and maintain such other facilities that are required to
supply electric service in the public way and up to two feet of cable and
conduit beyond the edge of the public way. All facilities from beyond this
point two feet off of the public way to the metering location will be
furnished, owned, installed, and maintained by the customer except for the
cable. This cable will be furnished, installed and maintained by the Company
to the first junction point at customer expense and owned by the customer.
The customer will furnish, own, install, and maintain any facilities beyond
the first junction point.
The Company will furnish and install the public way portion plus two feet
beyond of a single section of secondary cables from the service manhole or
pole to the junction point on the basis of the anticipated revenue, exclusive
of fuel and purchased power adjustment and other adjustment tariffs. All
other costs of construction including extensions of the existing distribution
system to the service manhole or pole, the installation of any conduit,
manhole breaks, modifications to the service manhole or pole, and paving will
be provided solely at the expense of the customer.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 182
M.D.P.U. No. 853
Sheet 4
Canceling M.D.P.U. No. 830
BOSTON EDISON COMPANY
STREET LIGHTING ENERGY RATE S-2
-------------------------------
GENERAL CONDITIONS
(1) Customer shall plainly mark customer-owned street lighting lamppost
for the purpose of ownership identification.
(2) A meter will be required on all installations for traffic signals if
more than one lamppost is connected after October 17, 1975.
(3) If an installation of customer-owned street lights requires the
removal of Boston Edison Company-owned street lighting units less
than 25 years old, the provisions for Term of Contract in Rate S-1,
as it exists from time to time, shall apply.
(4) Street Lighting Service shall not be furnished under both Rate S-1
and Rate S-2 in the same area. An area may be defined as follows:
(A) Service locations on public ways which may be shown to be within
the lines of a geometric figure. These lines will be other public
ways. (B) An adjoining portion of a public way which may be shown
within the lines of a geometric figure.
(5) The Company may at its option for situations in which Rate S-1 and
Rate S-2 are served within the same area, correct the situation by
transferring the Rate S-1 units to Rate S-2.
(6) The customer shall pay all construction costs for the relocation,
replacement, or substitution of existing service associated with
the replacement or modification of existing customer-owned lighting
systems
(7) The customer will furnish, install, and maintain a suitable
enclosure for housing the Company's metering equipment as well as
a suitable switching or disconnecting device in accordance with the
Company's standard practices as adopted from time to time.
TERM OF CONTRACT
As specified in agreement for service. Customer may terminate delivery
service on or after the expiration of such specified term of service by giving
at least ninety (90) days notice in writing.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
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<PAGE> 183
M.D.P.U. No. 854
Sheet 1
Canceling M.D.P.U. No. 831
BOSTON EDISON COMPANY
OUTDOOR LIGHTING RATE S-3
-------------------------
AVAILABILITY
Service under this rate is available to any customer for outdoor lighting
and floodlighting service.
RATE
<TABLE>
<CAPTION>
Rate Per Lamp Per Month
Billing Installation "A" Installation "B"
kWh -------------------------- --------------------------
Size of Lamp / Month Distribution Distribution
Service Type Lumens Watts / Lamp /Access Transmission /Access Transmission
- ------- ---- ------ ----- ------ ------- ------------ ------- ------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Area Mercury 7,000 175 75 $10.78 $0.17 $15.70 $0.17
Area Mercury 20,000 400 161 15.98 0.25 20.90 0.25
Area H. P. Sodium 9,500 100 41 8.82 0.14 13.74 0.14
Area H. P. Sodium 16,000 150 61 9.96 0.16 14.88 0.16
Area H. P. Sodium 25,000 250 103 12.82 0.20 17.74 0.20
Flood Mercury 20,000 400 161 $16.39 $0.26 $21.31 $0.26
Flood Mercury 60,000 1,000 389 23.90 0.37 28.82 0.37
Flood H.P. Sodium 25,000 250 103 13.36 0.21 18.28 0.21
Flood H.P. Sodium 45,000 400 164 16.99 0.27 21.91 0.27
</TABLE>
Installation "A" Lighting service supplied under this rate shall be
installed on an existing approved Company pole or post
carrying utilization voltage. The Company at its
option may approve other structures supplied by the
customer.
Installation "B" The Company will furnish, install and maintain one
pole and section of secondary wire not to exceed 150
feet for lighting service supplied under this rate.
Standard Offer Charge (Optional)
- ---------------------
Energy Charge Per Delivered kWh 2.800 cents
Basic Energy Service (Optional) As in effect per Tariff
- --------------------
TRANSMISSION SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
to reflect changes in the FERC-approved Transmission Tariffs.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 184
M.D.P.U. No. 854
Sheet 2
Canceling M.D.P.U. No. 831
BOSTON EDISON COMPANY
OUTDOOR LIGHTING RATE S-3
-------------------------
ACCESS SERVICE COST ADJUSTMENT
The Delivery Charges under this rate shall be adjusted from time to time
in the manner described in the Company's Access Cost Adjustment Provision to
reflect changes occurring on or after the retail access date.
STANDARD OFFER SERVICE
Standard Offer Service is available under this tariff for existing or new
Customers who have not yet chosen a supplier other than the Company on or
after the retail access date, when retail choice becomes available to all
customers. A Standard Offer Service Customer will pay the Rate for Standard
Offer Service set forth above in addition to the Rates for Retail Delivery
Service. A customer who has selected another supplier is not eligible for
Standard Offer Service.
Standard Offer Service may be terminated by a Customer provided that
notice of the change of supplier was received by the Company five (5) or more
business days before the next scheduled meter read date.
BASIC SERVICE
Any Customer who has received service at their present location from a
supplier other than the Company, and does not have a current supplier, is not
eligible to receive Standard Offer Service. In this case, a Customer will
receive Basic Service from the Company in accordance with the terms and price
for Basic Service as approved by the Department of Public Utilities.
GENERAL CONDITIONS
(1) The Company will furnish, install and maintain the lamps,
luminaires, brackets and photoelectric controls and will supply
electric service to operate the lamps.
(2) Lamps will be operated by photoelectric control, with hours of
operation aggregating approximately 4,200 hours per year, from dusk
to dawn.
(3) Service and necessary maintenance will be performed only during the
regularly scheduled working hours of the Company. Burned-out lamps
will be replaced upon notification of the outage by the customer to
the Company. No reduction in billing shall be allowed for lamp
outages.
(4) "Company poles" shall include poles owned jointly by the Company
with others. Approval of poles, pole locations and structures for
the installations shall be at the sole discretion of the Company.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 185
M.D.P.U. No. 854
Sheet 3
Canceling M.D.P.U. No. 831
BOSTON EDISON COMPANY
OUTDOOR LIGHTING RATE S-3
-------------------------
(5) Any required equipment other than the above will be installed and
maintained at the customer's expense.
(6) The customer shall assume all risks of loss or damage to his
equipment and property installed in connection with the lighting
systems.
BILLING
All bills shall be rendered monthly. However, the Company reserves the
right to render bills on a bimonthly basis. Billing kilowatthours include
lamp wattage plus accessory wattage.
TERM OF CONTRACT
As specified in agreement for service. Customer may terminate delivery
service on or after the expiration of such specified term of service by giving
at least (90) days' notice in writing.
TERMS AND CONDITIONS
The schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 186
M.D.P.U. No. 855
Sheet 1
Canceling M.D.P.U. No. 832
BOSTON EDISON COMPANY
MISCELLANEOUS CHARGES
---------------------
Applicable as Designated in Rate Schedules
------------------------------------------
DUPLICATE SERVICE CHARGE
If a customer desires the Company to provide duplicate service, or to
provide special capacity in other ways, the Company may make arrangements for
that purpose, making a charge therefore, which will be $4.22 per kilowatt per
month where only high tension distribution facilities are required, otherwise
the charge will be $6.80 per kilowatt per month. The foregoing are in
addition to the charges of the rate under which service is supplied and in
addition to any installation, or extension, charge.
In the context of this charge, duplicate service is defined as a
replicated installation of service equipment, where the Company has separately
provided the necessary distribution facilities to meet the total electrical
requirements of the customer. Those facilities may already include overhead
and underground circuits, conduit systems, pole lines, transformers and
service connections. This service is further characterized by the presence of
a double-throw switch at the customer's service location to prevent parallel
operation of these services.
MASTER METERED MULTIPLE OCCUPANT BUILDING LOSSES CHARGES
In multiple occupant buildings where a separate privately owned
transformer(s) is required to provide electricity at a secondary utilization
voltage (acceptable to the Company for metering purposes) to each customer
beyond the Company's secondary transformer, and where each customer is
separately metered, the Company will require the installation of approved
master metering equipment at a suitable location immediately beyond the
secondary side of the Company's transformer(s) at the building owner's
expense.
The master metering equipment shall be used to determine the electrical
losses incurred between the Company's secondary transformer(s) and the
individual customer-occupant metering equipment.
The building owner(s), or other person(s) responsible for the so-called
"public meter" use at the premises, shall pay the charges for the electrical
losses as determined under the applicable filed general service or residence
rate. This charge shall be calculated initially on the basis of five percent
of the kilowatthour use and demand recorded by the master metering equipment
during the monthly billing period. This percentage will be reviewed
periodically by the Company and adjusted to reflect the actual losses. The
customer of record will be notified of the percentage used as the basis of
billing for this charge.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 187
M.D.P.U. No. 855
Sheet 2
Canceling M.D.P.U. No. 832
BOSTON EDISON COMPANY
MISCELLANEOUS CHARGES
---------------------
INDUCTION GENERATION CHARGE
This charge applies to Customers without demand metering when the Company
supplies the reactive needs of the Customer's induction generator. The charge
is $1.89 per kilowatt per month of the generator nameplate rating, and is
waived if the customer installs capacitors to meet the reactive needs of the
generator.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 188
M.D.P.U. No. 856
Sheet 1
Canceling M.D.P.U. No. 833
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-C
-----------------------------
AVAILABILITY
Service under this rate is available only to customers who have a Service
Agreement in effect on the Retail Access Date and who are taking service under
one of the Company's time of use rates whose billing demand is determined by
an interval data recording device. This credit will apply to loads which are
available for interruption when a) the Company's or the New England Power
Pool's reliability is threatened; or b) the Company is near its expected peak
load. In order to receive this credit, the customer must execute a Service
Agreement in which the Interruption Option for each season, the Terms of
Contract, and the Interruptible Contract Demand for each season are specified.
This rate is closed to new participants effective on the Retail Access Date.
INTERRUPTIBLE CONTRACT DEMAND
An Interruptible Contract Demand shall be specified in the Service
Agreement for each season of October through May and June through September,
and each will be subject to the automatic modifications stipulated in the
Penalty provision. Prior to receiving the initial Demand Credit during a
season, the load must be interrupted at the request of the Company and the
Demonstrated Load Reduction must be greater than or equal to the Interruptible
Contract Demand for that season.
If the Demonstrated Load Reduction is greater than the 130% of the
Interruptible Contract Demand during three consecutive requests for
interruption in the same season, then the customer may choose to increase
that season's Interruptible Contract Demand, subject to the approval of the
Company.
The customer must notify the Company in writing when the load designated
as interruptible will not be available for interruption due to plant shutdowns
for vacation periods or for any other similar reason. The Interruptible
Contract Demand will be changed to zero without penalty for such periods and
the credits will be prorated based upon the number of weekdays.
MINIMUM INTERRUPTIBLE CONTRACT DEMAND
The Minimum Interruptible Contract Demand for either season shall be the
greater of a) 75 kW; or b) the average, for the months in the season, of the
difference between the customer's peak billing demand and the average demand
during the peak period. The Company at its discretion may waive the
requirement specified in part (b) for loads of known magnitude. However, any
additional metering expense must be borne by the customer.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 189
M.D.P.U. No. 856
Sheet 2
Canceling M.D.P.U. No. 833
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-C
-----------------------------
DEMONSTRATED LOAD REDUCTION
For each incidence of interruption, the Demonstrated Load Reduction is
equal to the difference of a) the average demand during the same hours of the
day when the interruption was requested for the three uninterrupted days in
the same billing period in which the customer registered the highest demands;
and b) the average demand during the interruption period. For loads of known
magnitude, the Company at its discretion may employ an alternative method to
determine the Demonstrated Load Reduction. In such cases, the alternative
method will be specified in the Service Agreement.
INTERRUPTION OPTIONS
Customers wishing to take service must select one of the following
options for each season:
<TABLE>
<CAPTION>
Maximum Interrupted Hours Minimum Interrupted
------------------------- -------------------
October-May June-September Per Day Hours Per Day
----------- -------------- ------- -------------
<S> <C> <C> <C> <C>
Option A: 200 100 10 4
Option B: 100 50 6 4
Option C: 66 34 6 4
</TABLE>
DEMAND CREDIT
The following credits will apply to each kilowatt of Interruptible
Contract Demand per month and will be posted to the bill rendered in the next
subsequent billing month based upon the Interruption Option and the Term of
Contract:
<TABLE>
<CAPTION>
Contract-Term Option A Option B Option C
------------- -------- -------- --------
<S> <C> <C> <C>
Five Years:
October - May $4.34 per kW $2.17 per kW $1.43 per kW
June - September $11.23 $5.62 $3.71
Three Years:
October - May $3.47 $1.74 $1.14
June - September $8.98 $4.50 $2.97
One Year:
October - May $1.74 $0.87 $0.57
June - September $4.49 $2.25 $1.48
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 190
M.D.P.U. No. 856
Sheet 3
Canceling M.D.P.U. No. 833
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-C
-----------------------------
If the Interruptible Contract Demand or Interruption Option changes
during a month, then the credit will be prorated. The credit will be posted
to the bill rendered in the next subsequent billing month or as soon
thereafter as is practicable. In any event, no credit will apply until the
first interruption at the request of the Company in the applicable season.
ADVANCE NOTICE OF INTERRUPTIONS
The Company will give at least one hour advance notice of interruption
and will attempt, but shall not be obligated, to provide a longer notice
period.
PENALTY FOR NON-INTERRUPTED LOADS
Reduced Compliance: If a Demonstrated Load Reduction in a given season is
- ------------------ greater than or equal to the Minimum Interruptible
Contract Demand for that season and less than the
Interruptible Contract Demand for that season, then
the Interruptible Contract Demand in the Service
Agreement for that season automatically will be
reduced to the Demonstrated Load Reduction effective
as of the date of the incidence of reduced compliance.
Non-Compliance: If a Demonstrated Load Reduction in a given season
- -------------- falls below the Minimum Interruptible Contract Demand
for that season, then the customer's Service Agreement
will be changed to reflect fewer interruptions for
that season effective as of the date of the non-
compliance incidence. Customers on Option A will be
moved to Option B. Customers on Option B will be
moved to Option C. If the customer was on Option C,
then the Interruptible Contract Demand for that season
in which the non-compliance occurred will be changed
to zero for a period of at least one year except with
the written concurrence of the Company to earlier
resumption.
TERM OF CONTRACT
Customers may select contract periods of one, three or five years. If
total annual subscriptions under this credit and Interruptible Load Credit I-N
reach a level of 30 MW, the Company may discontinue further subscriptions.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 191
M.D.P.U. No. 856
Sheet 4
Canceling M.D.P.U. No. 833
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-C
-----------------------------
EXISTING CONTRACT TERMINATION
All Service Agreements in effect on the Retail Access Date will remain
in effect for the specified contract life unless the Customer decides to
terminate his/her Standard Offer Service. Termination of Standard Offer
Service will terminate the Service Agreement for this rate. No existing
Service Agreement will be renewed or extended beyond the current contract
life.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 192
M.D.P.U. No. 857
Sheet 1
Canceling M.D.P.U. No. 834
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-N
-----------------------------
AVAILABILITY
Service under this rate is available only to customers who have an
Interruptible Service Agreement in effect on the Retail Access Date and who
are taking service under one of the Company's time of use rates. This credit
will apply to loads which are available for interruption at the request of
NEPOOL and which are approved by the Company as qualifying as Type II
Interruptible Loads under NEPOOL's Criteria, Rules and Standards Number 16
(CRS-16) as it exists from time to time. Such loads must adhere to the
requirements therein including metering, auditing and notice of interruptions.
The Company will provide detailed requirements upon request. This rate is
closed to new participants effective on the Retail Access Date.
DEFINITION OF INTERRUPTIBLE LOAD
Interruptible loads are those which are normally supplied by the Company
during peak hours and which may be interrupted at the discretion of and under
the control of the Company or any power pool of which the Company is a member.
Such loads will be interrupted to reduce the Company's peak capacity
requirements. Seasonal Interruptible loads are Interruptible loads which are
zero during a portion of the year.
DEMAND CREDIT
<TABLE>
<CAPTION>
October-May June-September
----------- --------------
<S> <C> <C> <C>
Residential Rate R-4: ($0.03642) ($0.12747) per kWh of Interrup-
tible Energy per Month
General Service Rate T-1: ($0.03494) ($0.11794) per kWh of Interrup-
tible Energy per month
General Service Rate T-2: ($4.92) ($13.35) per kW of Interruptible
Demand per month
General Service Rate G-3: ($5.28) ($13.07) per kW of Interruptible
Demand per month
</TABLE>
DETERMINATION OF INTERRUPTIBLE DEMAND
The Interruptible Demand (kW) will be the maximum peak billing demand as
specified in the applicable firm service tariff of the separately metered
interruptible load. The Company may accept loads of known magnitude for which
separate metering is not necessary, provided such loads are acceptable to
NEPOOL. For loads not separately metered the Interruptible Demand will be
identified in the Interruptible Service Agreement for each season of October
through May and
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 193
M.D.P.U. No. 857
Sheet 2
Canceling M.D.P.U. No. 834
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-N
-----------------------------
June through September, and will be equal to the minimum demand of the
specified equipment or processes.
DETERMINATION OF INTERRUPTIBLE ENERGY
The Interruptible Energy (kWh) will be the peak kilowatthours of the
separately metered interruptible load. The Company may accept loads of known
magnitude for which separate metering is not necessary, provided such loads
are acceptable to NEPOOL. For loads not separately metered the Interruptible
Energy will be identified in the Interruptible Service Agreement for each
season of October through May and June through September, and will be equal to
the minimum demand of the specified equipment or processes times the number of
peak hours in the billing period.
LIMITATIONS ON INTERRUPTIONS
The frequency and duration of interruptions is limited according to
NEPOOL's CRS-16 as it exists from time to time and is specified in the
Interruptible Service Agreement.
ADVANCE NOTICE OF INTERRUPTIONS
The load must be interruptible as specified in NEPOOL's Criteria, Rules
and Standards Number 16 as it exists from time to time. If the NEPOOL credit
for the interruptible load is adjusted due to the advance notification
requirements of the load, the Demand Credit received under this tariff will
receive the same adjustment and it will be specified in the Interruptible
Service Agreement.
PENALTY FOR NON-INTERRUPTION OF INTERRUPTIBLE LOADS
If upon request a customer fails to interrupt all or part of the load
contracted as interruptible for this credit, such load will immediately cease
to be eligible for this credit. In addition, the customer will be obligated
to repay the Company retroactively all credits received for such load for the
prior seventeen months.
METERING
In the event the Company determines that additional metering,
telemetering and/or automatic control equipment is required, such equipment
shall be installed and maintained by the
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 194
M.D.P.U. No. 857
Sheet 3
Canceling M.D.P.U. No. 834
BOSTON EDISON COMPANY
INTERRUPTIBLE LOAD CREDIT I-N
-----------------------------
Company at the customer's expense. Such annual expense shall also include the
costs of any dedicated communication lines or auxiliary facilities associated
with telemetering and/or controls.
TERMS OF CONTRACT
Customers who wish to receive a credit for Interruptible Load must
execute an Interruptible Service Agreement with the Company prior to
commencement of such service. The initial term of contract shall be five
years. If total annual subscriptions under this credit and Interruptible
Load Credit I-C reach a level of 30 MW, the Company may discontinue further
subscriptions or require a ten year term of contract.
EXISTING CONTRACT TERMINATION
All Interruptible Service Agreements in effect on the Retail Access Date
will remain in effect for the specified contract life unless the Customer
decides to terminate his/her Standard Offer Service. Termination of Standard
Offer Service will terminate the Interruptible Service Agreement for this
rate. No existing Interruptible Service Agreement will be renewed or extended
beyond the current contract life.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 195
M.D.P.U. No. 858
Sheet 1
Canceling M.D.P.U. No. 796
BOSTON EDISON COMPANY
ECONOMIC DEVELOPMENT RATE E
---------------------------
AVAILABILITY
For industrial development during periods of economic recession and as
part of the Company's economic development plan. The following general
conditions apply:
(a) There is a demonstrated need for rate incentives in order for the
Customer to locate or expand in the Company's service area.
(b) The Customer is engaged in a manufacturing process and creates new
employment for at least twenty-five people.
(c) The Company has available and the Customer subscribes to a minimum
new demand of 150 kilowatts per month.
(d) The Customer otherwise meets the availability requirements for
General Service Rates G-3 or T-2 (or successor rates).
(e) The Customer is working with government agencies to secure
government sponsored assistance.
(f) Not available for resale.
RATE
Applicable to the new or expanded load only:
(1) During the first year of service, the Distribution and
Transmission Charges on the otherwise applicable rates will be
decreased by forty (40) percent. The Standard Offer and Access
Charges will not be discounted.
(2) During the second year of service, the discount will be thirty
(30) percent.
(3) During the third year of service, the discount will be twenty
(20) percent.
(4) During the fourth year of service, the discount will be ten
(10) percent.
(5) Beginning with the fifth year of service, the customer will be
transferred to the applicable General Service Rate.
TERM OF CONTRACT
Four years.
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 196
M.D.P.U. No. 858
Sheet 2
Canceling M.D.P.U. No. 796
BOSTON EDISON COMPANY
ECONOMIC DEVELOPMENT RATE E
---------------------------
MISCELLANEOUS CHARGES
The charges as shown on the schedule of Miscellaneous Charges, as
applicable, shall apply to service under this rate.
TERMS AND CONDITIONS
The Schedule of Terms and Conditions, as in effect from time to time,
shall apply to service under this rate to the extent that they are not
inconsistent with the specific provisions of this rate. The Company reserves
the right to close this rate to future customers; however, once a customer
takes service under this rate, the Company will provide service in accordance
with this tariff for the four-year period provided for in the rate.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 197
M.D.P.U. No. 859
Sheet 1
BOSTON EDISON COMPANY
TRANSMISSION SERVICE COST ADJUSTMENT PROVISION
----------------------------------------------
The Transmission Service Cost Adjustment shall recover from customers
taking transmission service under Boston Edison Company's (the Company) rates
the costs charged to Boston Edison retail customers under Boston Edison's FERC
approved tariffs, or billed to Boston Edison by any other transmission
provider, and by other regional transmission or operating entities, such as
NEPOOL, a regional transmission group ("RTG"), an independent system operator
("ISO"), or other regional body, in the event that they are authorized to bill
Boston Edison directly for their services and shall include any other charges
relating to the stability of the transmission system which Boston Edison is
authorized to recover from retail customers by order of the regulatory agency
having jurisdiction over such charges. However, under no circumstances shall
the amount included in these charges recover costs which are collected by
Boston Edison in some other rate or charge.
The Transmission Service Cost Adjustment factor shall be established
annually based on a forecast of transmission costs, and shall include a full
reconciliation and adjustment for any over- or under-recoveries occurring
under the prior year's adjustment. The Company may file to change the factor
adjustments at any time should significant over- or under-recoveries occur.
Any adjustment of the Transmission Service Cost Adjustment factors shall
be in accordance with a notice filed with the Department of Public Utilities
(the Department) setting forth the amount of the proposed new factors, the
amount of the increase or decrease, and the effective delivery charge in the
Company's rates as adjusted to reflect the new factors. The notice shall
further specify the effective date of such adjustments, which shall not be
earlier than thirty days after the filling of the notice, or such other date
as the Department may authorize.
The operation of this Transmission Service Cost Adjustment clause is
subject to Chapter 164 of the General Laws.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 198
M.D.P.U. No. 860
Sheet 1
BOSTON EDISON COMPANY
ACCESS COST ADJUSTMENT PROVISION
--------------------------------
The Access Cost Adjustment shall recover on a fully reconciling basis
from all Boston Edison retail customers taking service under Boston Edison
Company's (the Company) rates all of Boston Edison's stranded investment as
set forth in the Settlement Agreement as approved by the Department on
- ----------, 1997 and shall be calculated in accordance with Attachment 3 of
said Agreement. A copy of said Agreement and the Department's approval
thereof is on file with the Department.
Each adjustment of the prices under the Company's applicable rates shall
be in accordance with a notice filed with the Department of Public Utilities
(the Department) setting forth the amount of the applicable Access Cost
Adjustment, the amount of the increase or decrease and the effective delivery
charge in the Company's rates as adjusted to reflect the new Access Cost
Adjustment amount. The notice shall further specify the effective date of
such adjustment, which shall not be earlier than thirty days after the filing
of the notice, or such other date as the Department may authorize.
The operation of this Access Cost Adjustment clause is subject to Chapter
164 of the General Laws.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
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<PAGE> 199
M.D.P.U. No. 861
Sheet 1
BOSTON EDISON COMPANY
TRANSITION TRUE-UP CHARGE
-------------------------
Within sixty (60) days following the Retail Access Date, the Company will
file with the DPU for approval a Transition True-up Charge as a final true-up
for its Fuel and Purchased Power Adjustment (including any adjustments
required to be made as a result of the Department's issuance of a GUPP order
or orders covering the period from November 1, 1995 through the Retail Access
Date) and its New Performance Adjustment Charge Tariffs. These tariffs will
be closed effective on the Retail Access Date.
The calculations of the dollar amount of over- or under-collection of
these two tariffs will be performed as they currently are, except that there
will be no estimated costs after the Retail Access Date. That dollar amount
will be collected in a uniform cents per kilowatthour charge over a three
month period. That uniform rate will be determined by dividing the calculated
dollar amount of combined over- or under-collection by the estimated number of
kilowatthours to be sold by the Company in that three month collection period.
This Transition True-up Charge will be added to the Distribution Charges
contained in these tariff schedules for billing purposes.
Filed: June _, 1997 Effective: Retail Access Date
Pursuant to Order in
DPU 96-100 dated December 30, 1996
S:\SHARED\SALESGEN\RDESIGN\98SCHED4.DOC
<PAGE> 200
Attachment 1
Exhibit 6
Rate Design Workpapers
<PAGE> 201
<TABLE>
R1 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 6,067,296 $ 6.43 $ 39,039,771.86 0.8999244
kwh $/kwh
Energy 2,846,987,874 $ 0.10858 $ 309,139,844.86
Base $ 0.06864
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 348,179,616.72
</TABLE>
<TABLE>
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 161,583,801.05 $ 39,039,771.86 $ 122,544,029.19 $ 6.43 $ 0.04305 Dist
DSM $ - $ - $ - DSM
Trans $ 6,950,880.83 $ - $ 6,950,880.83 $ - $ 0.00244 Trans
Access $ 99,929,274.38 $ 99,929,274.38 $ 0.03510 Access
Fuel $ 79,715,660.47 $ 79,715,660.47 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 348,179,616.73 $ 39,039,771.86 $ 309,139,844.87 $ 6.43 $ 0.10859
rates $ 348,167,126.52
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 202
<TABLE>
R2 (like R1) - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 349,224 $ 3.91 $ 1,367,097.17 0.8999244
kwh $/kwh
Energy 128,447,190 $ 0.07889 $ 10,132,861.82
Base $ 0.04118
DSM $ -
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 11,499,958.99
</TABLE>
<TABLE>
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 3,083,768.51 $ 1,367,097.17 $ 1,716,671.34 $ 3.91 $ 0.01338 Dist
DSM $ - $ - $ - DSM
Trans $ 311,172.79 $ - $ 311,172.79 $ - $ 0.00242 Trans
Access $ 4,508,496.37 $ 4,508,496.37 $ 0.03510 Access
Fuel $ 3,596,521.32 $ 3,596,521.32 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 11,499,958.99 $ 1,367,097.17 $ 10,132,861.82 $ 3.91 $ 0.07890
rates $ 11,499,949.13
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 203
<TABLE>
R2 (like R3) - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 23,988 $ 3.91 $ 93,905.14 0.8999244
kwh $/kwh
Energy
Winter 17,654,881 $ 0.07254 $ 1,280,736.43
Base $ 0.03484
DSM $ -
Fuel $ 0.03338
NPAC $ 0.00433
Summer 5,070,958 $ 0.08512 $ 431,659.48
Base $ 0.04742
DSM $ -
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 1,806,301.05
</TABLE>
<TABLE>
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 317,258.99 $ 93,905.14 $ 223,353.85 $ 3.91 Dist
$ 0.00946 Winter
$ 0.01110 Summer
DSM $ - $ - $ - DSM
Trans $ 55,041.62 $ - $ 55,041.62 $ - $ 0.00242 Trans
Access $ 797,676.95 Access
$ 576,608.41 $ 0.03266 Winter
$ 221,093.77 $ 0.04360 Summer
Fuel $ 636,323.49 $ 636,323.49 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 1,806,301.05 $ 93,905.14 $ 1,712,421.14 $ 3.91 $ 0.07254 Winter
$ 0.08512 Summer
rates $ 1,806,118.09
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 204
<TABLE>
R3 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 500,712 $ 6.43 $ 3,221,811.21 0.8999244
kwh $/kwh
Energy
Winter 404,022,629 $ 0.09800 $ 39,594,933.36
Base $ 0.05805
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Summer 114,426,271 $ 0.11897 $ 13,613,294.71
Base $ 0.07902
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 56,430,039.28
</TABLE>
<TABLE>
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 22,465,280.53 $ 3,221,811.21 $ 19,243,469.32 $ 6.43 Dist
$ 0.03544 Winter
$ 0.04303 Summer
DSM $ - $ - $ - DSM
Trans $ 1,250,633.15 $ - $ 1,250,633.15 $ - $ 0.00241 Trans
Access $ 18,197,556.39 Access
$ 12,989,327.52 $ 0.03215 Winter
$ 5,209,828.12 $ 0.04553 Summer
Fuel $ 14,516,569.20 $ 14,516,569.20 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 56,430,039.27 $ 3,221,811.21 $ 53,209,827.31 $ 6.43 $ 0.09800 Winter
$ 0.11897 Summer
rates $ 56,427,089.26
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 205
<TABLE>
R4 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 1,680 $ 9.99 $ 16,781.79 0.8999244
kwh $/kwh
Energy
Winter - ON 462,315 $ 0.15660 $ 72,396.61
Base $ 0.11665
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Winter-OFF 991,839 $ 0.05750 $ 57,026.95
Base $ 0.01755
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Summer-ON 146,897 $ 0.31677 $ 46,533.06
Base $ 0.27683
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Summer-OFF 463,596 $ 0.06055 $ 28,069.31
Base $ 0.02060
DSM $ 0.00224
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 220,807.72
</TABLE>
<PAGE> 206
<TABLE>
R4 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 85,524.71 $ 16,781.79 $ 68,742.92 $ 9.99 Dist
$ 0.05276 Winter-ON
$ 0.01937 Winter-OFF
$ 0.10673 Summer-ON
$ 0.02040 Summer-OFF
DSM $ - $ - $ - DSM
Trans $ 5,003.78 $ - $ 5,003.78 $ - $ 0.00242 Trans
Access $ 72,469.11 Access
$ 33,943.17 $ 0.07342 Winter-ON
$ 7,637.16 $ 0.00770 Winter-OFF
$ 26,385.64 $ 0.17962 Summer-ON
$ 4,510.79 $ 0.00973 Summer-OFF
Fuel $ 57,810.12 $ 57,810.12 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 220,807.72 $ 16,781.79 $ 204,033.58 $ 9.99 $ 0.15660 Winter-ON
$ 0.05749 Winter-OFF
rates $ 220,805.85 $ 0.31677 Summer-ON
$ 0.06055 Summer-OFF
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 207
<TABLE>
G1 w/o Demand Meters - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 562,236 $ 8.14 $ 4,573,968.05 0.8999244
kwh $/kwh
Energy
Winter 227,687,653 $ 0.09761 $ 22,223,636.60
Base $ 0.05671
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Summer 121,636,340 $ 0.16042 $ 19,512,966.20
Base $ 0.11953
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 46,310,570.85
</TABLE>
<TABLE>
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 23,171,053.54 $ 4,573,968.05 $ 18,597,085.49 $ 8.14 Dist
$ 0.04349 Winter
$ 0.07148 Summer
DSM $ - $ - $ - DSM
Trans $ 1,097,173.37 $ - $ 1,097,173.37 $ - $ 0.00314 Trans
Access $ 12,261,272.15 Access
$ 5,229,985.39 $ 0.02297 Winter
$ 7,028,147.73 $ 0.05778 Summer
Fuel $ 9,781,071.80 $ 9,781,071.80 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 46,310,570.86 $ 4,573,968.05 $ 41,733,463.78 $ 8.14 $ 0.09760 Winter
$ 0.16040 Summer
rates $ 46,309,384.91
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 208
<TABLE>
G1 with Demand Meters - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 114,024 $ 12.09 $ 1,378,092.38 0.8999244
kw $/kw
Demand >10 kw
Winter 43,537 $ 3.59 $ 156,328.24
Summer 26,449 $ 11.00 $ 290,861.68
kwh $/kwh
Energy
Winter
1st 2000 kwh 61,874,379 $ 0.09761 $ 6,039,298.55
next 150 hrs 13,615,662 $ 0.08412 $ 1,145,416.70
additional 10,083,339 $ 0.05390 $ 543,456.43
Base 1st 2000 kwh $ 0.05671
next 150 hrs $ 0.04323
additional $ 0.01300
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Summer
1st 2000 kwh 31,939,174 $ 0.16042 $ 5,123,699.24
next 150 hrs 8,258,637 $ 0.09509 $ 785,280.89
additional 5,511,738 $ 0.05695 $ 313,878.15
Base 1st 2000 kwh $ 0.11953
next 150 hrs $ 0.05419
additional $ 0.01605
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 15,776,312.26
</TABLE>
<PAGE> 209
<TABLE>
G1 with Demand Meters - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Demand Energy $/bill $/kw $/kwh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dist $ 7,080,045.84 $ 1,378,092.38 $ 5,667,016.96 $ 12.09 Dist
$ 12,190.36 $ 0.28 $ 0.03965 Winter 1st 2000 kwh
$ 0.03417 next 150 hrs
$ 0.02189 additional
$ 22,746.14 $ 0.86 $ 0.06516 Summer 1st 2000 kwh
$ 0.03862 next 150 hrs
$ 0.02313 additional
DSM $ - $ - $ - DSM
Trans $ 412,311.77 $ - $ - Trans
$ 144,107.47 $ 3.31 Winter
$ 268,192.86 $ 10.14 Summer
Access $ 4,608,030.81 Access
$ - $ 1,853,137.65 $ - $ 0.02995 Winter 1st 2000 kwh
$ 298,863.78 $ 0.02195 next 150 hrs
$ 40,434.19 $ 0.00401 additional
$ - $ 2,147,909.45 $ - $ 0.06725 Summer 1st 2000 kwh
$ 235,123.40 $ 0.02847 next 150 hrs
$ 32,078.32 $ 0.00582 additional
Fuel $ 3,675,922.01 $ 3,675,922.01 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 15,776,310.43 $ 1,378,092.38 $ 447,236.83 $ 13,950,485.76 $ 12.09 $ 3.59 $ 0.09760 Winter 1st 2000 kwh
$ 0.08412 next 150 hrs
rates $ 15,776,138.01 $ 0.05390 additional
$ 11.00 $ 0.16041 Summer 1st 2000 kwh
$ 0.09509 next 150 hrs
$ 0.05695 additional
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 210
<TABLE>
G2 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 303,168 $ 18.19 $ 5,513,859.79 0.8999244
kw $/kw
Demand >10 kw
Winter 3,489,462 $ 10.30 $ 35,955,886.94
Summer 2,017,299 $ 22.07 $ 44,514,016.80
kwh $/kwh
Energy
Winter
1st 2000 kwh 337,697,570 $ 0.09785 $ 33,043,296.69
next 150 hrs 645,393,157 $ 0.06595 $ 42,561,395.91
additional 548,255,682 $ 0.05414 $ 29,682,263.43
Base 1st 2000 kwh $ 0.05671
next 150 hrs $ 0.02481
additional $ 0.01300
DSM $ 0.00343
Fuel $ 0.03338
NPAC $ 0.00433
Summer
1st 2000 kwh 169,086,564 $ 0.16066 $ 27,166,040.90
next 150 hrs 360,563,002 $ 0.07691 $ 27,730,014.44
additional 321,971,623 $ 0.05719 $ 18,413,620.91
Base 1st 2000 kwh $ 0.11953
next 150 hrs $ 0.03577
additional $ 0.01605
DSM $ 0.00343
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 264,580,395.81
</TABLE>
<PAGE> 211
<TABLE>
G2 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Demand Energy $/bill $/kw $/kwh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dist $ 107,459,091.96 $ 5,513,859.79 $ 28,249,819.73 $ 18.19 Dist
$ 32,905,626.66 $ 9.43 $ 0.01548 Winter 1st 2000 kwh
$ 0.01043 next 150 hrs
$ 0.00856 additional
$ 40,789,785.78 $ 20.22 $ 0.02541 Summer 1st 2000 kwh
$ 0.01216 next 150 hrs
$ 0.00905 additional
DSM $ - $ - $ - DSM
Trans $ 6,756,046.01 $ - $ - Trans
$ 3,035,831.94 $ 0.87 Winter
$ 3,732,003.15 $ 1.85 Summer
Access $ 83,642,162.65 Access
$ - $ 18,360,616.88 $ - $ 0.05437 Winter 1st 2000 kwh
$ 17,761,219.68 $ 0.02752 next 150 hrs
$ 9,638,334.89 $ 0.01758 additional
$ - $ 18,136,224.85 $ - $ 0.10726 Summer 1st 2000 kwh
$ 13,250,690.32 $ 0.03675 next 150 hrs
$ 6,484,508.49 $ 0.02014 additional
Fuel $ 66,723,092.72 $ 66,723,092.72 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 264,580,393.34 $ 5,513,859.79 $ 80,463,247.53 $ 178,604,507.56 $ 18.19 $ 10.30 $ 0.09785 Winter 1st 2000 kwh
$ 0.06595 next 150 hrs
rates $ 264,579,417.84 $ 0.05414 additional
$ 22.07 $ 0.16067 Summer 1st 2000 kwh
$ 0.07691 next 150 hrs
$ 0.05719 additional
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 212
<TABLE>
G3 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 5,352 $ 237.07 $ 1,268,783.09 0.8999244
kw $/kw
Demand
Winter 3,768,643 $ 8.85 $ 33,338,385.43
Summer 2,268,278 $ 18.48 $ 41,927,866.72
kwh $/kwh
Energy
Winter
ON-peak 735,984,163 $ 0.06371 $ 46,886,350.29
OFF-peak 982,608,108 $ 0.05298 $ 52,057,154.51
Base ON-peak $ 0.02237
OFF-peak $ 0.01165
DSM $ 0.00363
Fuel $ 0.03338
NPAC $ 0.00433
Summer
ON-peak 334,393,478 $ 0.07373 $ 24,655,101.77
OFF-peak 654,425,530 $ 0.05589 $ 36,572,772.11
Base ON-peak $ 0.03240
OFF-peak $ 0.01455
DSM $ 0.00363
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 236,706,413.92
</TABLE>
<PAGE> 213
<TABLE>
G3 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Demand Energy $/bill $/kw $/kwh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dist $ 59,715,672.12 $ 1,268,783.09 $ 6,522.32 $ 237.07 Dist
$ 25,890,577.41 $ 6.87 Winter
$ - ON-peak
$ - OFF-peak
$ 32,549,789.30 $ 14.35 Summer
$ - ON-peak
$ - OFF-peak
DSM $ - $ - $ - DSM
Trans $ 6,153,090.09 $ - $ - Trans
$ 3,844,015.86 $ 1.02 Winter
$ 2,313,643.56 $ 1.02 Summer
Access $ 95,030,135.89 Access
$ 3,617,897.28 $ 0.96 Winter
$ 26,281,994.46 $ 0.03571 ON-peak
$ 24,535,724.46 $ 0.02497 OFF-peak
$ 7,054,344.58 $ 3.11 Summer
$ 15,288,469.81 $ 0.04572 ON-peak
$ 18,251,928.03 $ 0.02789 OFF-peak
Fuel $ 75,807,515.81 $ 75,807,515.81 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 236,706,413.91 $ 1,268,783.09 $ 75,270,267.99 $ 160,172,154.89 $ 237.07 $ 8.85 $ 0.06371 Winter ON-peak
$ 0.05297 OFF-peak
rates $ 236,704,699.21 $ 18.48 $ 0.07372 Summer ON-peak
$ 0.05589 OFF-peak
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 214
<TABLE>
T1 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 60 $ 10.13 $ 607.99 0.8999244
kwh $/kwh
Energy ratio to summer peak
Winter - ON 9,823 $ 0.14045 $ 1,379.65 0.46073
Base $ 0.09956
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Winter-OFF 7,092 $ 0.05390 $ 382.23 0.10610
Base $ 0.01300
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Summer-ON 6,406 $ 0.27207 $ 1,742.91 1.00000
Base $ 0.23118
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Summer-OFF 5,387 $ 0.05695 $ 306.77 0.11860
Base $ 0.01605
DSM $ 0.00319
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 4,419.55
</TABLE>
<PAGE> 215
<TABLE>
T1 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 2,514.27 $ 607.80 $ 1,906.47 $ 10.13 Dist
$ 0.07128 Winter-ON
$ 0.01641 Winter-OFF
$ 0.15471 Summer-ON
$ 0.01835 Summer-OFF
DSM $ - $ - $ - DSM
Trans $ 93.82 $ - $ 93.82 $ - Trans
$ 0.00351 Winter-ON
$ 0.00081 Winter-OFF
$ 0.00761 Summer-ON
$ 0.00090 Summer-OFF
Access $ 1,007.65 $ 1,007.65 Access
$ 0.03766 Winter-ON
$ 0.00868 Winter-OFF
$ 0.08177 Summer-ON
$ 0.00970 Summer-OFF
Fuel $ 803.82 $ 803.82 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 4,419.56 $ 607.80 $ 3,811.76 $ 10.13 $ 0.14045 Winter-ON
$ 0.05390 Winter-OFF
rates $ 4,419.50 $ 0.27209 Summer-ON
$ 0.05695 Summer-OFF
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 216
<TABLE>
T2 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 0.8999244
<150 kw 7,764 $ 27.77 $ 215,619.23
>150,<300 kw 7,704 $ 114.62 $ 883,058.49
>300,<1000 kw 6,480 $ 166.67 $ 1,079,995.72
>1000 kw 1,092 $ 374.57 $ 409,026.67
kw $/kw
Demand
Winter 4,204,405 $ 10.30 $ 43,322,756.01
Summer 3,986,644 $ 22.07 $ 87,969,873.57
kwh $/kwh
Energy
Winter
ON-peak 963,496,344 $ 0.06595 $ 63,539,175.94
OFF-peak 1,153,566,477 $ 0.05414 $ 62,453,459.55
Base ON-peak $ 0.02481
OFF-peak $ 0.01300
DSM $ 0.00343
Fuel $ 0.03338
NPAC $ 0.00433
Summer
ON-peak 434,841,597 $ 0.07691 $ 33,442,598.65
OFF-peak 719,234,559 $ 0.05719 $ 41,133,166.94
Base ON-peak $ 0.03577
OFF-peak $ 0.01605
DSM $ 0.00343
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 334,448,730.77
</TABLE>
<PAGE> 217
<TABLE>
T2 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Demand Energy $/bill $/kw $/kwh
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Dist $120,030,054.84 $ (18,602.62) Dist
<150 kw $ 215,606.28 $ 27.77 <150 kw
>150,<300 kw $ 883,032.48 $114.62 >150,<300 kw
>300,<1000 kw $1,080,021.60 $166.67 >300,<1000 kw
>1000 kw $ 409,030.44 $374.57 >1000 kw
$ 38,764,614.10 $ 9.22 Winter
$ - ON-peak
$ - OFF-peak
$ 78,696,352.56 $19.74 Summer
$ - ON-peak
$ - OFF-peak
DSM $ - $ - $ - DSM
Trans $ 8,009,806.53 $ - $ - Trans
$ 4,120,316.90 $ 0.98 Winter
$ 3,906,911.12 $ 0.98 Summer
Access $114,816,978.09 Access
$ 420,440.50 $ 0.10 Winter
$ 36,564,686.25 $0.03795 ON-peak
$ 30,154,227.71 $0.02614 OFF-peak
$ 5,381,969.40 $ 1.35 Summer
$ 21,263,754.09 $0.04890 ON-peak
$ 20,994,456.78 $0.02919 OFF-peak
Fuel $ 91,591,891.36 $ 91,591,891.36 $0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $334,448,730.82 $2,587,690.80 $131,290,604.58 $200,550,413.57 $10.30 $0.06595 Winter ON-peak
<150 kw $ 27.77 $0.05414 OFF-peak
rates $334,447,311.57 >150,<300 kw $114.62 $22.07 $0.07690 Summer ON-peak
>300,<1000 kw $166.67 $0.05719 OFF-peak
>1000 kw $374.57
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 218
<TABLE>
S2 - 1998 Unbundled Rates Seasonal in Dist and Access jsg 5/28/97
Billing Determinants and Current Revenues
<CAPTION>
# bills $/bill Revenues adj fact
<S> <C> <C> <C> <C>
Customer 35,256 $ 8.02 $ 282,694.13 0.8999244
kwh $/kwh
Energy 52,361,898 $ 0.08963 $ 4,693,326.47
Base $ 0.05193
DSM $ -
Fuel $ 0.03338
NPAC $ 0.00433
Total Revenues $ 4,976,020.60
</TABLE>
<TABLE>
<CAPTION>
Desired Collections Collected from: Rates:
Basic Monthly Energy $/bill $/kwh
<S> <C> <C> <C> <C> <C> <C>
Dist $ 1,586,920.52 $ 282,694.13 $ 1,304,226.39 $ 8.02 $ 0.02491 Dist
DSM $ - $ - $ - DSM
Trans $ 85,064.32 $ - $ 85,064.32 $ - $ 0.00162 Trans
Access $ 1,837,902.62 $ 1,837,902.62 $ 0.03510 Access
Fuel $ 1,466,133.14 $ 1,466,133.14 $ 0.02800 Fuel
NPAC $ - $ - $ - NPAC
Total $ 4,976,020.60 $ 282,694.13 $ 4,693,326.47 $ 8.02 $ 0.08963
rates $ 4,975,950.04
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98SEAS3.XLS
<PAGE> 219
<TABLE>
S1 - 1998 Unbundled Rates 5/28/97
Billing Determinants and Current Revenues
<S> <C> <C> <C> <C>
1995 Base Revenues $ 16,186,117.22 (1)
kwh $/kwh
Energy 79,264,296 $ 0.04190 $ 3,321,174.00
Fuel $ 0.03709
NPAC $ 0.00481
Total Revenues $ 19,507,291.22
Adjustment Factor X 0.8999244
---------
Total 1998 Revenues $ 17,555,088.12
Collected from Standard Offer
79,264,296 $ 0.02800 $ 2,219,400.29
New Base Collections $ 15,335,687.83 (2)
Base Rate Adjustment 0.947459 (3)=(2)/(1)
Functionalization of Base Revenues $ proportion (4)
Distribution $ 12,395,891.86 0.80830
Transmission $ 157,619.18 0.01028
Access $ 2,782,176.79 0.18142
Total $ 15,335,687.83 1.00000
Apply to Current Base Rates
(3)*(4)
Distribution 0.76583
Transmission 0.00974
Access 0.17189
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98STLITE.XLS
<PAGE> 220
<TABLE>
S-1 1998 Unbundled
<CAPTION>
old new old new
-------- ---------------------------- -------- ----------------------------
dist trans access dist trans access
---- ----- ------ ---- ----- ------
class I class I class II class II
-------- ---------------------------- -------- ----------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
0.76583 $ 8.37 $ 6.41 $ 0.08 $ 1.44 $ 13.37 $ 11.15 $ 0.08 $ 1.44
0.00974 $ 10.21 $ 7.82 $ 0.10 $ 1.75 $ 15.21 $ 12.56 $ 0.10 $ 1.75
0.17189 $ 10.21 $ 7.82 $ 0.10 $ 1.75 $ 15.21 $ 12.56 $ 0.10 $ 1.75
$ 12.24 $ 9.37 $ 0.12 $ 2.10 $ 17.24 $ 14.11 $ 0.12 $ 2.10
0.94746 $ 14.36 $ 11.00 $ 0.14 $ 2.47 $ 19.36 $ 15.73 $ 0.14 $ 2.47
$ 18.39 $ 14.08 $ 0.18 $ 3.16 $ 23.39 $ 18.82 $ 0.18 $ 3.16
$ 24.02 $ 18.40 $ 0.23 $ 4.13 $ 29.02 $ 23.13 $ 0.23 $ 4.13
$ 20.42 $ 15.64 $ 0.20 $ 3.51 $ 25.42 $ 20.38 $ 0.20 $ 3.51
$ 24.48 $ 18.75 $ 0.24 $ 4.21 $ 29.48 $ 23.48 $ 0.24 $ 4.21
$ 28.72 $ 21.99 $ 0.28 $ 4.94 $ 33.72 $ 26.73 $ 0.28 $ 4.94
$ 36.78 $ 28.17 $ 0.36 $ 6.32 $ 41.78 $ 32.90 $ 0.36 $ 6.32
$ 48.04 $ 36.79 $ 0.47 $ 8.26 $ 53.04 $ 41.53 $ 0.47 $ 8.26
$ 9.39 $ 7.19 $ 0.09 $ 1.61 $ 14.39 $ 11.93 $ 0.09 $ 1.61
$ 11.12 $ 8.52 $ 0.11 $ 1.91 $ 16.12 $ 13.25 $ 0.11 $ 1.91
$ 12.87 $ 9.86 $ 0.13 $ 2.21 $ 17.87 $ 14.59 $ 0.13 $ 2.21
$ 16.50 $ 12.64 $ 0.16 $ 2.84 $ 21.50 $ 17.37 $ 0.16 $ 2.84
$ 24.82 $ 19.01 $ 0.24 $ 4.27 $ 29.82 $ 23.75 $ 0.24 $ 4.27
$ 18.78 $ 14.38 $ 0.18 $ 3.23 $ 23.78 $ 19.12 $ 0.18 $ 3.23
$ 22.24 $ 17.03 $ 0.22 $ 3.82 $ 27.24 $ 21.77 $ 0.22 $ 3.82
$ 25.74 $ 19.71 $ 0.25 $ 4.42 $ 30.74 $ 24.45 $ 0.25 $ 4.42
$ 33.00 $ 25.27 $ 0.32 $ 5.67 $ 38.00 $ 30.01 $ 0.32 $ 5.67
$ 49.64 $ 38.02 $ 0.48 $ 8.53 $ 54.64 $ 42.75 $ 0.48 $ 8.53
$ 7.44 $ 5.70 $ 0.07 $ 1.28 $ 12.44 $ 10.44 $ 0.07 $ 1.28
$ 7.85 $ 6.01 $ 0.08 $ 1.35 $ 12.85 $ 10.75 $ 0.08 $ 1.35
$ 9.10 $ 6.97 $ 0.09 $ 1.56 $ 14.10 $ 11.71 $ 0.09 $ 1.56
$ 10.28 $ 7.87 $ 0.10 $ 1.77 $ 15.28 $ 12.61 $ 0.10 $ 1.77
$ 13.23 $ 10.13 $ 0.13 $ 2.27 $ 18.23 $ 14.87 $ 0.13 $ 2.27
$ 17.13 $ 13.12 $ 0.17 $ 2.94 $ 22.13 $ 17.86 $ 0.17 $ 2.94
$ 14.88 $ 11.40 $ 0.14 $ 2.56 $ 19.88 $ 16.13 $ 0.14 $ 2.56
$ 15.70 $ 12.02 $ 0.15 $ 2.70 $ 20.70 $ 16.76 $ 0.15 $ 2.70
$ 18.20 $ 13.94 $ 0.18 $ 3.13 $ 23.20 $ 18.68 $ 0.18 $ 3.13
$ 20.56 $ 15.75 $ 0.20 $ 3.53 $ 25.56 $ 20.48 $ 0.20 $ 3.53
$ 26.46 $ 20.26 $ 0.26 $ 4.55 $ 31.46 $ 25.00 $ 0.26 $ 4.55
$ 34.26 $ 26.24 $ 0.33 $ 5.89 $ 39.26 $ 30.97 $ 0.33 $ 5.89
class VI $ 4.49 $ 3.44 $ 0.04 $ 0.77
class VII $ 7.40 $ 6.58 $ 0.04 $ 0.77
</TABLE>
<TABLE>
<CAPTION>
old new old new
-------- ---------------------------- -------- ----------------------------
dist trans access dist trans access
---- ----- ------ ---- ----- ------
class III class III class V class V
--------- ---------------------------- -------- ----------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
0.76583 $ 15.37 $ 13.04 $ 0.08 $ 1.44 $ 25.37 $ 22.52 $ 0.08 $ 1.44
0.00974 $ 17.21 $ 14.45 $ 0.10 $ 1.75 $ 27.21 $ 23.93 $ 0.10 $ 1.75
0.17189 $ 17.21 $ 14.45 $ 0.10 $ 1.75 $ 27.21 $ 23.93 $ 0.10 $ 1.75
$ 19.24 $ 16.01 $ 0.12 $ 2.10 $ 29.24 $ 25.48 $ 0.12 $ 2.10
0.94746 $ 21.36 $ 17.63 $ 0.14 $ 2.47 $ 31.36 $ 27.10 $ 0.14 $ 2.47
$ 25.39 $ 20.72 $ 0.18 $ 3.16 $ 35.39 $ 30.19 $ 0.18 $ 3.16
$ 31.02 $ 25.03 $ 0.23 $ 4.13 $ 41.02 $ 34.50 $ 0.23 $ 4.13
$ 27.42 $ 22.27 $ 0.20 $ 3.51 $ 37.42 $ 31.75 $ 0.20 $ 3.51
$ 31.48 $ 25.38 $ 0.24 $ 4.21 $ 41.48 $ 34.85 $ 0.24 $ 4.21
$ 35.72 $ 28.63 $ 0.28 $ 4.94 $ 45.72 $ 38.10 $ 0.28 $ 4.94
$ 43.78 $ 34.80 $ 0.36 $ 6.32 $ 53.78 $ 44.27 $ 0.36 $ 6.32
$ 55.04 $ 43.42 $ 0.47 $ 8.26 $ 65.04 $ 52.90 $ 0.47 $ 8.26
$ 16.39 $ 13.82 $ 0.09 $ 1.61 $ 26.39 $ 23.30 $ 0.09 $ 1.61
$ 18.12 $ 15.15 $ 0.11 $ 1.91 $ 28.12 $ 24.62 $ 0.11 $ 1.91
$ 19.87 $ 16.49 $ 0.13 $ 2.21 $ 29.87 $ 25.96 $ 0.13 $ 2.21
$ 23.50 $ 19.27 $ 0.16 $ 2.84 $ 33.50 $ 28.74 $ 0.16 $ 2.84
$ 31.82 $ 25.64 $ 0.24 $ 4.27 $ 41.82 $ 35.11 $ 0.24 $ 4.27
$ 25.78 $ 21.01 $ 0.18 $ 3.23 $ 35.78 $ 30.49 $ 0.18 $ 3.23
$ 29.24 $ 23.66 $ 0.22 $ 3.82 $ 39.24 $ 33.14 $ 0.22 $ 3.82
$ 32.74 $ 26.34 $ 0.25 $ 4.42 $ 42.74 $ 35.82 $ 0.25 $ 4.42
$ 40.00 $ 31.90 $ 0.32 $ 5.67 $ 50.00 $ 41.38 $ 0.32 $ 5.67
$ 56.64 $ 44.65 $ 0.48 $ 8.53 $ 66.64 $ 54.12 $ 0.48 $ 8.53
$ 14.44 $ 12.33 $ 0.07 $ 1.28 $ 24.44 $ 21.80 $ 0.07 $ 1.28
$ 14.85 $ 12.64 $ 0.08 $ 1.35 $ 24.85 $ 22.12 $ 0.08 $ 1.35
$ 16.10 $ 13.60 $ 0.09 $ 1.56 $ 26.10 $ 23.08 $ 0.09 $ 1.56
$ 17.28 $ 14.50 $ 0.10 $ 1.77 $ 27.28 $ 23.98 $ 0.10 $ 1.77
$ 20.23 $ 16.76 $ 0.13 $ 2.27 $ 30.23 $ 26.24 $ 0.13 $ 2.27
$ 24.13 $ 19.75 $ 0.17 $ 2.94 $ 34.13 $ 29.23 $ 0.17 $ 2.94
$ 21.88 $ 18.03 $ 0.14 $ 2.56 $ 31.88 $ 27.50 $ 0.14 $ 2.56
$ 22.70 $ 18.66 $ 0.15 $ 2.70 $ 32.70 $ 28.13 $ 0.15 $ 2.70
$ 25.20 $ 20.57 $ 0.18 $ 3.13 $ 35.20 $ 30.04 $ 0.18 $ 3.13
$ 27.56 $ 22.38 $ 0.20 $ 3.53 $ 37.56 $ 31.85 $ 0.20 $ 3.53
$ 33.46 $ 26.90 $ 0.26 $ 4.55 $ 43.46 $ 36.37 $ 0.26 $ 4.55
$ 41.26 $ 32.87 $ 0.33 $ 5.89 $ 51.26 $ 42.34 $ 0.33 $ 5.89
class VI
class VII
</TABLE>
<PAGE> 221
<TABLE>
S3 - 1998 Unbundled Rates 5/28/97
Billing Determinants and Current Revenues
<S> <C> <C> <C> <C>
1995 Base Revenues $ 1,960,141.18 (1)
kwh $/kwh
Energy 17,004,766 $ 0.04190 $ 712,499.70
Fuel $ 0.03709
NPAC $ 0.00481
Total Revenues $ 2,672,640.88
Adjustment Factor X 0.8999244
---------
Total 1998 Revenues $ 2,405,174.84
Collected from Standard Offer
17,004,766 $ 0.02800 $ 476,133.45
New Base Collections $ 1,929,041.39 (2)
Base Rate Adjustment 0.984134 (3)=(2)/(1)
Functionalization of Base Revenues $ proportion (4)
Distribution $ 1,302,464.14 0.67519
Transmission $ 29,709.96 0.01540
Access $ 596,867.29 0.30941
Total $ 1,929,041.39 1.00000
Apply to Current Base Rates
(3)*(4)
Distribution 0.66447
Transmission 0.01516
Access 0.30450
</TABLE>
S:\SHARED\SALESGEN\RDESIGN\98STLITE.XLS
<PAGE> 222
<TABLE>
S-3 1998 Unbundled
<CAPTION>
old new old new
-------- -------------------------------- -------- ---------------------------------
dist trans access dist trans access
---- ----- ------ ---- ----- ------
class A class A class B class B
-------- -------------------------------- -------- ---------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
0.66447 $ 11.12 $ 7.39 $ 0.17 $ 3.39 $ 16.12 $ 12.31 $ 0.17 $ 3.39
0.01516 $ 16.50 $ 10.96 $ 0.25 $ 5.02 $ 21.50 $ 15.88 $ 0.25 $ 5.02
0.30450 $ 9.10 $ 6.05 $ 0.14 $ 2.77 $ 14.10 $ 10.97 $ 0.14 $ 2.77
$ 10.28 $ 6.83 $ 0.16 $ 3.13 $ 15.28 $ 11.75 $ 0.16 $ 3.13
0.98413 $ 13.23 $ 8.79 $ 0.20 $ 4.03 $ 18.23 $ 13.71 $ 0.20 $ 4.03
$ 16.91 $ 11.24 $ 0.26 $ 5.15 $ 21.91 $ 16.16 $ 0.26 $ 5.15
$ 24.66 $ 16.39 $ 0.37 $ 7.51 $ 29.66 $ 21.31 $ 0.37 $ 7.51
$ 13.78 $ 9.16 $ 0.21 $ 4.20 $ 18.78 $ 14.08 $ 0.21 $ 4.20
$ 17.53 $ 11.65 $ 0.27 $ 5.34 $ 22.53 $ 16.57 $ 0.27 $ 5.34
</TABLE>
<PAGE>
ATTACHMENT 2
BOSTON EDISON COMPANY
STORM FUND
<PAGE> 223
ATTACHMENT 2
BOSTON EDISON COMPANY
STORM FUND
<PAGE> 224
Establishment of Storm Contingency Fund
Policies and Procedures
Boston Edison Company shall establish an $8M storm contingency fund to
pay for the incremental operations and maintenance (O&M) costs incurred by the
Company as the result of major storms. Major storms shall be defined as those
storms with incremental O&M costs over $1.0 million occurring after the date
the settlement proposal is approved by the Department of Public Utilities
(DPU). The fund shall be established and maintained as follows:
1. Effective upon DPU approval of this agreement, Boston Edison. will
initially fund the storm contingency fund with an $8 million contribution
from proceeds received by the Company through the sale of Clean Air Act
Emission Allowances. After storm costs have been paid from the fund,
Boston Edison. will restore the balance to a level of $8M by contributing
funds from distribution maintenance expenses up to a maximum of $3M a
year until the fund reaches the $8M level. The accounting entry to
record any funding from distribution maintenance expenses will be booked
as follows:
DR Account 598 Maintenance of Misc. Distribution Plant
CR Account 254 Storm Contingency Fund
2. Upon the occurrence of a major storm, all incremental O&M costs incurred
as a result of the storm shall be offset against the balance in Account
254 (storm contingency fund). Incremental O&M costs are defined as the
costs which Boston Edison. will incur as a direct result of a storm which
are over and above Boston Edison.'s normal costs of doing business.
These costs shall include such things as overtime paid to employees to
restore service to customers, rest time wages incurred as a result of
storm restoration (as stipulated in union contracts), outside vendor
costs, lodging and meal charges, material and supply charges, and other
related miscellaneous storm costs. The storm fund is not intended to
reimburse Boston Edison. for incremental capital costs. The accounting
entry to record the incremental costs up to the amount in the storm fund
will be the following:
DR Account 254 Storm Contingency Fund
DR Account 407.3 Regulatory Debits - Storm Fund
CR Account 407.4 Regulatory Credits - Storm Fund
CR Account 131 Cash
3. If the cumulative incremental costs of major storms exceed the balance
in Account 254 (storm contingency fund), such excess shall be deferred
by Boston Edison. by a debit to Account 182, Deferred Charges - Storm
Fund. Interest on the remaining
<PAGE> 225
balance will be accounted for as described in item 4. The accounting
entry to record the excess costs will be the following:
DR Account 182.3 Deferred Charges - Storm Fund
CR Account 131 Cash
4. Interest shall be accrued monthly on any positive or negative balance in
the fund, calculated in accordance with the Terms and Conditions for
interest expense on customer deposits. The accounting entry on Boston
Edison.'s books shall be:
DR Account 431 Other Interest Expense
CR Account 254 Storm Contingency Fund
If the fund is in a negative position, the entry on Boston Edison.'s
books will be:
DR Account 182.3 Deferred Charges - Storm Fund
CR Account 419 Interest Income
5. Within six months of the occurrence of a major storm, Boston Edison. will
file an account documenting all amounts charged to the fund with the DPU
and Attorney General (AG). The DPU or the AG may challenge any items
charged to this account by filing notification with the Company within 90
days of the Company's filing.
<PAGE>
ATTACHMENT 3
------------
BOSTON EDISON COMPANY
---------------------
FORMULA FOR CALCULATING ACCESS CHARGES
--------------------------------------
<PAGE> 226
ATTACHMENT 3
------------
BOSTON EDISON COMPANY
---------------------
FORMULA FOR CALCULATING ACCESS CHARGES
--------------------------------------
<PAGE> 227
FORMULA FOR CALCULATING ACCESS CHARGES
Settlement Agreement
Formula for Calculating Access Charges
Access Charge Summary (Schedule 1, Page 1)
The Access Charge is calculated in Schedules 1 and 2 attached. The
Access Charge is made up of two components:
a fixed component described in Section 1 below; and
a variable component described in Section 2.
In general the dollar amounts in the fixed component do not change, but
are set at the time of the Agreement. The amounts in the variable
component are forecast and are reconciled to the actual charges in the
reconciliation account.
1.0 The Fixed Component of the Access Charge (Schedule 1, Page 2)
-------------------------------------------------------------
The fixed component of the Access Charge consists of the various
elements described in more detail in Sections 1.1 through 1.9 below.
With the exception of the amounts calculated from time to time for
Adjustments for Residual Value Credits (Schedule 1, page 2, column G),
the amounts shown on Schedule 1, page 2 shall be fixed and shall not be
subject to change as part of any future reconciliation of the access
charge.
1.1 Amortization of Plant and Regulatory Assets (Schedule 1, Page 2,
----------------------------------------------------------------
Col. C) -
------- Revenues shown in Col. B sufficient to amortize Plant
and Regulatory Assets commencing on January 1, 1998 and ending
December 31, 2009. The balance of Plant and Regulatory Assets
balances made up as follows:
1.1(a) Plant balances (Schedule 1, Page 5)
----------------------------------- shall include the
December 31, 1995(1) net book value, of the following
BECo generation-related investments unrecovered as of
January 1, 1998, excluding any capital additions made
after December 31, 1995:
(i) All fossil units including: Mystic Station
generation, including units 1,2&3; New Boston
Station; L Street; Edgar Station; and Wyman
unit 4.
[FN]
____________________
(1) The balances in Schedule 1 will be adjusted for relevant DPU or FERC audit
adjustments.
<PAGE> 228
(ii) All Jet units including: L Street; Edgar;
Mystic; Framingham; and West Medway.
(iii) Pilgrim Nuclear Station, less the 25.73133%
share (Contract Share) covered by Pilgrim
unit sales contracts (Contract Customers).
This plant balance shall also include the
balances for materials and supplies, nuclear
intangibles and allocated share of nuclear
Stabilizer Line.
(iv) Step up transformers at BECo's generating units
which are excluded from BECo's transmission
rates.
(v) General plant allocated to generation.
(vi) Generation related property held for future use.
(vii) LaGrange Street property in Newton,
Massachusetts (1995 FERC Form 1, p. 221).
1.1(b) Regulatory Assets (Schedule 1, Page 6)
-------------------------------------- shall include
generation's share (net of the Pilgrim Contract Share)
of the following December 31, 1995(2) obligations or net
book balances that are unrecovered as of December 31,
1997:
(i) FAS 109.
(ii) National Energy Policy Act (NEPA) payments.
(iii) Unamortized ITC (Investment Tax Credit).
(iv) FAS 106 Deferral and Transition Obligations.
1.2 Carrying Charge Component (Schedule 1, Page 2, Col. B) -
------------------------------------------------------
Revenues sufficient to provide an overall pre-tax carrying charge
on stranded investment shown on Capital shown on Schedule 1, page
14(3), which is based on a combined State and Federal income tax
rate of 39.225 percent multiplied by the average of the beginning
and ending balances in each calendar year beginning in the year
of the Retail Access Date, of the sum of the following:
1.2(a) Unrecovered net book value of BECo's generation
investments as defined in 1.1(a) above and as
calculated on Page 5 of Schedule 1; plus
[FN]
____________________
(2) The balances in Schedule 1 will be adjusted for relevant DPU or FERC audit
adjustments.
(3) The carrying charge on capital shown on Schedule 1, page 14 shall be used
as the return whenever referenced throughout this Agreement. However, the
return so calculated will be adjusted in accordance with Section 1.7.
<PAGE> 229
1.2(b) Unrecovered net book value of generation related
Regulatory Assets as defined in 1.1(b) above and as
calculated on Page 6 of Schedule 1; less
1.2(c) Deferred Taxes as shown in Schedule 1, Page 14, Col. C,
which are calculated on Schedule 1, page 13, as equal to
the combined State and Federal Income Tax rate of 39.225
percent, multiplied by the sum of the unrecovered:
(i) net book value of BECo's generation investment;
plus
(ii) net book value of generation related regulatory
assets; less
(iii) balance of generation investment for tax
purposes; less
(iv) balance of generation related regulatory assets
for tax purposes.
1.3 Transmission Wheeling (Schedule 1, Page 2, Col. D) -
--------------------------------------------------
Forecast costs associated with the transmission of electricity
from BECo's entitlements as of 12/31/95 in Wyman Unit 4, which
is located off BECo's transmission system, together with support
payments to Central Maine Power which are necessary for the
transmission of this entitlement. These costs are excluded from
recovery under BECo's open access transmission tariffs.
1.4 Residual Value Credits - Fossil (Schedule 1, Page 2, Col. F) -
------------------------------------------------------------
BECo shall implement Fossil Residual Value Credits (FRVCs) as
a direct offset to the Access Charges authorized under this
Settlement. The FRVCs shall be calculated as follows:
1.4(a) Fossil sale or spin-off proceeds (including sale of
generation related property held for future use and
La Grange Street property in Newton received by BECo;
less
1.4(b) Any revenues lost or gained by BECo between the Retail
Access Date and the divestiture date measured by the
difference between the revenue from the unit that BECo
would have collected from the fully allocated (e.g.
including A&G) generation portion of DPU 92-92 rates and
the market revenues from the units plus any Access
Charge revenues related to the unit sold. However, the
total lost revenues so calculated shall not exceed
$0.008 per kilowatt-hour times the number of kilowatt-
hours delivered by BECo during the period between the
Retail Access Date and the date of divestiture(4); less
[FN]
____________________
(4) If BECo sells its generating facilities in more than one transaction, the
revenues lost shall be allocated based on unit capacity costs in the FERC
tariff #6 in effect at the signing of this Agreement.
<PAGE> 230
1.4(c) BECo's share of capital investments for that unit
demonstrated to be prudently incurred after December 31,
1995, excluded from the plant balances in Section 1.1
above; less
1.4(d) The book value at date of sale of items included as
consideration of the sale proceeds that are not included
in the recovered balances shown on pages 3 and 4 or
recovered elsewhere in this attachment. Such items may
include materials and supplies, as well as fossil fuel.
1.4(e) Reasonable costs associated with the sale process
including any reasonable internal costs (such internal
costs cannot exceed $1,000,000) incurred for the
performance of tasks that otherwise would have been
outsourced as well as the cost of refinancing associated
with the units' sale or spin-off; less
1.4(f) Any reasonable cost of removal or site clean up costs of
the fossil facilities including any such costs incurred
by BECo to prepare the facilities for sale and any such
costs for which BECo remains liable for up to ten years
following the sale of said facilities.
The closings associated with the sale of BECo's assets may occur
at different times. Thus, after Retail Access Date, as part of
the annual update of the Access Charge the balance remaining at
year end from the items above that have not already been included
in a previous FRVC shall be credited to the Fixed Component of
the Access Charge in equal annual monthly amounts over the period
commencing on the date that the FRVC is implemented through
December 31, 2009. However, if the balance of items above not
previously included in a FRVC exceeds $13 million, an interim
FRVC for the outstanding balance of the items above will be
implemented to start the flow back to customers within three
months of receipt of funds. The annualized amount of each year's
FRVC credit shall be calculated as an annuity based on the
amortization and the pretax carrying charge on the unamortized
credit balance net of tax impacts as outlined in Sections 1.1
and 1.2 above. Since both proceeds and costs are recovered
through this account there are some FRVCs that may be negative.
However, the sum of all the FRVCs for all the years may not be
less than zero. If the sale of assets, whose costs have been
included in the Access Charge, occurs after December 31, 2009,
BECo shall implement a Residual Value Credit following that date
to amortize the proceeds with the return specified above, over
no more than five years.
1.5 Residual Value Credit - Nuclear (Schedule 1, Page 2, Col. F) -
------------------------------------------------------------
A plan for the market valuation (excluding decommissioning
liabilities and funds) of Pilgrim will be filed on or before
January 1, 1999 and the valuation will be completed by
December 31. 2002. Within three months after the completion
of the market valuation as provided for in this section or in
Section 1.8 below, BECo shall
<PAGE> 231
implement a Pilgrim Residual Value Credit (PRVC) as a direct
offset to the Access Charges authorized under this Settlement.
The PRVC shall be calculated as follows:
1.5(a) The market valuation times 74.26867% ("BECo's Share");
less
1.5(b) BECo's Share of undepreciated capital investments
incurred after December 31, 1995, excluded from the
plant balances in Section 1.1 above; less
1.5(c) BECo's Share of reasonable costs associated with the
sale or market valuation process including any
reasonable internal costs (such internal costs shall
not exceed $1,000,000) incurred for the performance of
tasks that otherwise would have been outsourced as well
as the cost of refinancings; less
1.5(d) BECo's Share of any cost of removal or site clean up
costs not otherwise reflected in Decommissioning or
Post-Shutdown Costs as defined in Section 2.1.(c) of
this Attachment. If the unit is sold but the
Decommissioning liability remains with BECo, BECo will
continue to collect the Decommissioning amounts through
the Variable Component of the Access Charge. If the
decommissioning liability is transferred to the buyer
as part of the sale, BECo will cease collection of the
decommissioning amount as reflected in the
reconciliation account Section 2.9(a)(ii) below.
The PRVC from Pilgrim shall be credited to the Fixed Component
in equal annual amounts over the period commencing on the date
the PRVC is implemented through December 31, 2009. The
annualized amount of the PRVC credit shall be calculated as an
annuity based on the amortization and the pretax carrying charge
on the unamortized credit balance net of tax impacts as outlined
in Sections 1.1 and 1.2 above.
<PAGE> 232
1.6 Valuation of Pilgrim if shutdown prior to market valuation under
----------------------------------------------------------------
section 1.5 above
-----------------
If BECo notifies the DPU of its decision to shutdown Pilgrim
prior to completion of the market valuation plan outlined above,
then BECo will perform the following steps:
1.6(a) Within three working days of shutdown notification BECo
will publish a notice in the Wall Street Journal and
send letters to the CEOs of all utilities with nuclear
operations that the plant is available for sale to
qualified buyers and that any party interested in
purchasing Pilgrim may file a statement of intent to
purchase the unit with an indicative bid within ten
working days of the published notice with BECo. Such
filing will require a bidder's deposit of $1 million.
1.6(b) Within ten working days of the receipt of the statement
of intent to purchase the unit, BECo will provide the
DPU with an evaluation of such indicative bids. An
appropriate summary of the evaluation will be made
available to the public by Boston Edison. If within 60
days of receipt of the evaluation, the DPU does not
order BECo to sell the plant, then the market value will
be deemed zero for purposes of this section. The
Company may proceed with decommissioning the plant. The
deposits will be returned to bidders. After
commencement of decommissioning any proceeds from the
site or unit not otherwise credited to decommissioning
will be credited to customers as part of the annual
reconciliation under Section 2.9 of this agreement.
1.6(c) If the DPU requires the Company to sell Pilgrim, BECo
will recover all nuclear operating costs through the
access charge reconciliation account as described in
section 2.2(b) and the deposits will be returned to all
bidders.
1.7 Residual Value Credit - For Changes in Carrying Charges Including
-----------------------------------------------------------------
Refinancings, Repurchases, Retirements of Securities and
--------------------------------------------------------
Securitization
--------------
1.7(a) If directed by the legislature, BECo shall be required
to implement securitization on a timely basis, if
implementation would produce net savings to consumers
after taking into account all transaction costs
including call provisions and prepayments, if
applicable.
1.7(b) Any and all financing savings associated with the
issuance of securities by the Company, a government
agency, or any corporation established by the government
that pledge, assign, or have security interest in the
assets and/or the cash flows associated with any portion
of the Access Charge ("securitization") shall be
allocated to the Access Charge through the Adjustment
for Residual Value Credits on Page 2 of Schedule 1. The
amount will be calculated by multiplying the average
balance of the
<PAGE> 233
securitized amount by the reduction in the "Carrying
Charge." The average balance of the securitized amount
will be the actual daily average of the amount of the
"Average Net Balance" of Schedule 1, page 14, column E,
that has been securitized after adjustment for issue
costs. The reduction in the "Carrying Charge" will be
the difference between the rate of return on the
securitization issues and the "Carrying Charge" of
10.88% shown on Schedule 1, page 14 as adjusted for any
and all previous changes in capital costs as provided in
this Section. Neither the Carrying Charge on Capital
nor the interest rate on securitized debt is intended to
represent an agreement as to an allowed rate of return
as determined in a retail rate case, nor is it to be
used for any other purposes (such as AFUDC), nor does it
establish precedent for future proceedings, nor is it
binding on the parties except with respect to the
matters set forth in this Agreement.
1.7(c) The Carrying Charge rate on Schedule 1, page 14 will be
updated for the actual State and Federal Income Tax
rates and the difference in the Annual Return on
Unamortized Balance will be debited or credited to the
Access Charge through the Residual Value Credit.
1.8 Residual Value Credit - Carrying charge on FAS 106 unfunded
-----------------------------------------------------------
balances -
-------- The difference between the carrying charge provided
for in Section 1.2 and the discount rate for FAS 106 that is used
to calculate the updated balance in Section 1.9 below shall be
applied to the unfunded FAS 106 balance, net of any deferred tax
impact, and this amount shall be credited to the Residual Value
Credit account.
1.9 Residual Value Credit for Updated balances for Specific
-------------------------------------------------------
Regulatory Assets as of 12/31/97 -
-------------------------------- As of 12/31/97 BECo shall
reconcile the balances in Section 1.1(b) for the unrecognized
transition obligation, prior service cost, and unrecognized gains
or losses in the accumulated post-retirement benefit obligation
associated with the FAS 106 transition obligation; and the
pension obligation under FAS 87 for the amount of unrecognized
transition obligation, prior service obligation and unrecognized
gains and losses only to the extent that such gains and losses
exceed five percent of plan assets or liabilities. BECo shall
make cash contributions to the respective trust funds for the FAS
106 and FAS 87 obligations under this section and Section 2.5 as
rapidly as permitted under tax law up to the level of revenues
collected for this purpose.(5) Any revenues associated with
these obligations that cannot be immediately funded shall be put
into a separate account on the books to be reserved with carrying
charges at the rate provided in Section 1.2 until tax deductible
funding becomes possible. For this purpose, the FAS 87 pension
obligation includes section 401(h) post-retirement health care
benefits. The one-time adjustment associated with FAS
[FN]
____________________
(5) BECo's post divestiture FAS 106 and FAS 87 gains or losses recognized on
BECo's books shall be reflected in distribution rates to customers and
shall neither be retained nor borne by BECo.
<PAGE> 234
106 and FAS 87, whether positive or negative, shall be subtracted
from or added to the schedules for prospective recovery of FAS
106. In addition, BECo will reconcile the balances for the FAS
109 regulatory asset. The changes in each of the balances will
be only the generation portion of these balances. This amount
will be amortized over the period ending December 31, 2009 with
the appropriate carrying charges used for the individual
regulatory assets and credited or debited through the Residual
Value Credit account.
2.0 The Variable Component of the Access Charge
-------------------------------------------
The variable component of the access charge is shown on Schedule
1, page 3. The amounts in the variable component are forecast
and are reconciled to the actual charges in the reconciliation
account. This charge includes:
2.1 Pilgrim Fixed Operating Costs, Decommissioning and Other Post
-------------------------------------------------------------
Shutdown Costs (Schedule 1, page 3, Column B) -
--------------------------------------------- The amounts in
this schedule are made up of three components as described in
Sections 2.1(a), 2.1(b) and 2.1(c) below:
2.1(a) Revenues sufficient to cover Pilgrim Fixed Operating Costs -
---------------------------------------------------------- In
each of the years 1998, 1999 and 2000 Boston Edison shall receive
revenues equal to the lower of $23 million (as adjusted below)
or the sum of BECo's Share of Pilgrim's annual property taxes
(excluding any Pilgrim property tax recovered under Section 2.4
below), NRC fees, insurance and the cost of minimum security
requirements. In any calendar year, the $23 million will be
reduced by $2 million a year for every percent the capacity
factor of the unit is below 68%, however, the amount will never
be negative. If less than a full year is applicable, the amount
under this section shall be prorated to a monthly amount. If
BECo informs the DPU of its decision to permanently shut down
Pilgrim, future revenues under this Section 2.1(a) will cease
on the date of such notification and the year to date capacity
factor will be used. If Pilgrim is sold, the revenues covering
fixed operating costs included in this section will continue to
be received but will be flowed through to the purchaser.
2.1(b) Pilgrim Decommissioning Costs -
----------------------------- Decommissioning costs for
Pilgrim will be the estimated nuclear decommissioning costs shown
on Schedule 1, Page 8. These costs include all charges, for,
decommissioning and site restoration. Any net incremental
decommissioning costs caused by operations after the later of the
Retail Access Date or the date when the Department prescribes a
method of distinguishing net incremental decommissioning costs
from decommissioning costs as described in DPU 96-100 page 288,
(December 30 1996) shall be excluded. Recovery of these
decommissioning costs shall be subject to the regulatory
authority of the agencies having jurisdiction over the operation
and collection of such funds. The decommissioning funds received
under this section will be placed in irrevocable trusts
maintained in accordance with 18 C.F.R. 35.32, 35.33, and
relevant State, or Federal laws and regulations which may be in
effect from time to time. Upon the completion of decommissioning
any
<PAGE> 235
remaining balances in the decommissioning trust accounts will be
returned to customers through a credit to the Reconciliation
Account. Decommissioning amounts will be adjusted as
decommissioning studies for Pilgrim are updated. These
decommissioning studies will be updated no less than every two
years and the updated decommissioning amounts will be reflected
in the reconciliation account under Section 2.9(a)(ii) below. By
June 30, 1998, BECo will prepare a detailed early shutdown plan
that can be updated easily and that can form the basis to
expedite the preparation of a NRC Post-Shutdown Decommissioning
Activities Report (PSDAR) under 10 C.F.R. 50.82 in the event of
early shutdown.
2.1(c) Pilgrim Post-Shutdown Costs -
--------------------------- Upon BECo's notification to the
DPU of its decision to permanently shut down Pilgrim, BECo's
Share of Pilgrim's reasonable post shutdown costs not recovered
through the decommissioning account will be recovered as an
addition to the "actual decommissioning" reconciliation account
on Schedule 2, page 1. The shutdown notification to the DPU
shall include BECo's estimate of the post shutdown costs not
covered by the decommissioning fund for the 24 month period
following the shutdown date. Within 60 days of receipt of BECo's
estimate, the DPU shall either (1) notify BECo of its approval of
the estimate or (2) schedule a hearing to resolve questions
regarding the estimate. BECo shall be allowed to collect
revenues through the Access Charge based upon its estimate,
subject to refund after a final order has been issued by the DPU.
Such refunds, if any, shall include interest (at the Carrying
charge on Capital as shown in Schedule 1, page 14) on the
overcollected amount balance. Notwithstanding DPU approval of
the budget estimate, the actual costs will be reconciled (with an
explanation of significant variances) and recovered as described
in Section 2.9
If as a result of its failure to file with the NRC a PSDAR within
one year from the later of:
(i) the date of notification to the DPU of its
decision to shut down Pilgrim; or
(ii) expiration of the 60 day period identified in
section 1.6(b),
BECo is unable to use moneys from the decommissioning fund for
decommissioning, the monthly amounts recovered under this section
2.1(c) will be reduced by 2% per month until the level of 76% is
reached. The amount recovered will remain at 76% until such time
as BECo files a PSDAR with the NRC at which time the recovery
shall return to 100%.
2.2 Above Market Payments to Power Suppliers (Schedule 1, Page 3,
-------------------------------------------------------------
Col. E )
-------- will be:
<PAGE> 236
2.2(a) all payments by BECo for Long-Term Power Supply Contracts
including any decommissioning or post shutdown costs for
Connecticut Yankee and Mass Yankee; less
2.2(b) the market value realized from the resale of electricity
purchased under the contracts into the wholesale market or if
the supply contracts are used to support the standard offer, the
market price will be deemed to be the standard offer prices paid
by the customers; plus
2.2(c) Economic Buyout Payments agreed to by BECo after June 1, 1997
associated with those contracts.
Long-Term Power Supply Contracts shall be all power supply
contracts in place as of December 31, 1995, between BECo and a
third party supplier, continuing to the termination date of each
contract. Supply Contracts are listed on Schedule 1, page 9 of
this Attachment. Economic Buyout Payments will be all reasonable
payments by BECo associated with the early termination of Long-
Term Power Supply Contracts or costs incurred to reduce payments
under those contracts.
2.3 Above Market Fuel Transportation (Schedule 1, Page 3, Col. G)
-------------------------------------------------------------
as shown in Schedule 1, Page 12, will be the sum of BECo's
continuing long-term payment obligations associated with
(i) Capacity Payments to Gas Pipelines less (ii) the market
value of that capacity (see Schedule 1, page 12).
2.3(a) Capacity and Fixed Energy Payments to Interstate Natural Gas
Pipelines will be all capacity and fixed energy payments for
Interstate Pipeline Capacity Contracts in effect as of
December 31, 1995. They include contracts with:
(1) Iroquois Gas Transmission System, L.P.
(2) Tennessee Gas Pipeline Company
(3) Texaco Natural Gas Inc.
(4) Associated Gas Services Inc.
(5) Phibro Division of Salomon Inc.
(6) Central Hudson Gas & Electric Corporation
(7) Renaissance Energy (U.S.) Inc.
(8) Boston Gas Company
2.3(b) The Market Value of Capacity Payments to Interstate Natural Gas
Pipelines will equal the actual proceeds associated with the sale
or assignment or termination of contractual obligations. For the
purposes of calculating the Access Charge and amount included in
the Reconciliation Account prior to the date that BECo's
contractual entitlements to the pipeline capacity are assigned
to a non-affiliate, the Market Value of Capacity Payments to
Interstate Natural Gas Pipelines equals the amounts shown on
page 12 of Schedule 1, which are deemed to be 50 percent of such
capacity payments.
<PAGE> 237
2.4 Payments in Lieu of Property Taxes (Schedule 1, Page 3, Col. H)
---------------------------------------------------------------
for generation facilities will include all reasonable costs
incurred by BECo (but excluding the Contract Customer Portion of
Pilgrim costs) or its affiliates associated with payments in lieu
of property taxes to the cities and towns in which BECo owns
generating facilities as of December 31, 1995 to mitigate the
loss of tax revenues that those cities and towns would otherwise
incur in connection with restructuring. For the purposes of
calculating the Variable Component of the Access Charge on page 3
of Schedule 1, the Payments in Lieu of Property Taxes are assumed
to be zero.
2.5 Employee Severance and Retraining (Schedule 1, Page 3, Col. I)
--------------------------------------------------------------
will include all reasonable costs and expenses incurred by BECo
(but excluding the Contract Customer Portion of Pilgrim costs)
or its affiliates associated with the adjustment of their
workforces in connection with the implementation of retail access
or divestiture, including, but not limited to early retirement,
severance, retraining and other reasonable costs. For the
purposes of calculating the Variable Component of the Access
Charge on page 3 of Schedule 1, the Employee Severance and
Retraining Costs are assumed to be zero.
2.6 Damages, Costs, or Net Recoveries from Claims (Schedule 1, Page
---------------------------------------------------------------
3, Col. J)
---------- by or against third parties shall include all damages,
costs, or recoveries associated with BECo's generating business
(but excluding the Contract Customer Portion of Pilgrim costs)
which accrued prior to the divestiture date and which were not
assigned to BECo's successor in interest, recovered from BECo's
insurance carriers, or the result of gross negligence. For the
purposes of calculating the Variable Component of the Access
Charge on page 3 of Schedule 1, Damages, Costs, or Net Recoveries
from claims were assumed to be zero.
2.7 Performance Based Rate for Pilgrim (Schedule 1, Page 3, Col. K)
---------------------------------------------------------------
Performance Based Rates for Pilgrim will include the sum of the
following three items:
2.7(a) So long as BECo continues to operate Pilgrim, from the Retail
Access Date through December 31, 2000. Performance Based Rates
will include:
(i) 25 percent of the total reasonable operating costs (but
excluding the Contract Customer Portion of Pilgrim costs),
including payroll and property taxes and other variable
costs and post 12/31/95 capital additions, on a cost of
service basis associated with Pilgrim that are not
otherwise recovered in the Access Charge under section 2.4
Payments in Lieu of Property Taxes or Section 2.5 Employee
Severance and Retraining: less
(ii) the revenues (but excluding the Contract Customer Portion
of Pilgrim revenues) from sales of 25 percent of Pilgrim's
capacity and related energy produced (but excluding the
Contract Customer Portion of Pilgrim energy and
<PAGE> 238
capacity). These revenues exclude revenues collected
under Sections 1.5, 1.6, 2.1, 2.4, 2.5 and 2.6 above.
2.7(b) If Pilgrim is required to support the Standard Offer, BECo will
receive the prices shown on Attachment 4 "Term Sheet for Bidding
Standard Offer Service Including Fuel Index", Section 3 "Payments
by Distribution Company" in the table "Distribution Company
Rates". To the extent that Pilgrim forgoes market revenues
higher than the Standard Offer because of its requirement to
support the Standard Offer and it operates at a loss, it may
recover such loss up to the amount of the revenues foregone
through this account in the succeeding year. In so far as the
annual amount in Section 2.7(a) above is positive (i.e. costs
exceed revenues) a loss shall be deemed to have occurred. Thus
the profit to loss calculation excludes the Pilgrim Contract
Customers revenues and expenses and it excludes revenues under
Sections 1.5, 1.6, 2.1, 2.4, 2.5 and 2.6 above.
2.7(c) The PBR for Pilgrim shall recover BECo's share of the book value
of the actual final nuclear fuel core at shutdown which will be
recovered in equal amounts, including a carrying charge on the
unrecovered balance at the Carrying Charge Rate shown on Schedule
1, page 14, as adjusted by Sections 1.2 and 1.7 over three years
after shutdown.
2.8 Base Total Variable Component (Schedule 1, Page 3, Col. L)
---------------------------------------------------------- is the
sum of the variable components outlined in section 2.1 through
2.7 above.
2.9 The Reconciliation Account (Schedule 1, Page 3, Col. M)
-------------------------------------------------------
is calculated in Schedule 2.
2.9(a) Annual Reconciliation Adjustment (Schedule 2, Page 2, Col. B)
-------------------------------------------------------------
is calculated on Schedule 2, Page 1 and will be the sum of the
two following components:
(i) Revenue Adjustment (Schedule 2, Page 1, Col. B through
Col. F) is calculated as follows: The estimated retail
kWh delivered in Col. B are subtracted from the actual
retail kWh delivered in Col. C to arrive at the surplus
or (deficit) kWh in Col. D. The balance in Col. D is
multiplied by the Access Charge Billed in Col. E to
arrive at an over collection or (shortfall) in Col. F.
(ii) Variable Cost Adjustment (Schedule 2, Page 1, Col. G
through Col. R) adjusts the base total variable component
(2.8 above) for the actual costs experienced for the items
in 2.1 through 2.7 above.
2.9(b) Deferral of Retail Access Date (Schedule 2, Page 2, Col. C)
----------------------------------------------------------- This
amount is calculated as follows: for each month that Retail
Access Date is delayed, the monthly amount of the fixed component
of the Access Charge shown on Schedule 1, Page 1, Col. C will be
accumulated. This amount will be reduced by the monthly amount
of the annual amortization shown Schedule 1, Page 5, Col. F and
<PAGE> 239
Schedule 1, Page 6, Col. D as adjusted by section 1.9 and the
associated return computed in accordance with section 1.2 of this
Agreement. The monthly adjustment shall be accumulated in the
Reconciliation Account established below, and will be reflected
in the adjustments to the Access Charge commencing on January 1,
2001.
2.9(c) Asset Balance Adjustments, Actual Generation & Related
------------------------------------------------------
Transmission (Schedule 2, Page 2, Col. D)
----------------------------------------- The Transmission
Wheeling referenced under Section 1.3 above will be adjusted in
this account so that only the actual expense incurred by BECo
will be recovered in the Access Charge. The Generation Related
Transmission on Schedule 1, Page 5 will be adjusted for the
actual amount not recovered in the transmission rates.
2.9(d) Access Charge Mitigation (Schedule 2, Page 2, Col. E)
----------------------------------------------------- From
January 1, 2001 through December 31, 2009, an Access Charge
Mitigation Incentive shall increase the Variable Cost Component
when BECo mitigates the Access Charge and reduces the cumulative
average of the cents per kilowatt-hour Access Charge below the
1998 Access Charge 3.51 cents as shown on Schedule 1 page 1,
Col. H. The schedule of rewards for each level of the cumulative
average Access Charge in each year from 2001 through 2009 is
shown on Schedule 1, page 4.
2.9(e) Annual Shortfall/Excess (Schedule 2, Page 2, Col. F)
---------------------------------------------------- is the total
of items 2.9(a) through 2.9(d) above.
2.9(f) Annual Pre-tax Carrying Charge Component (Schedule 2, Page 2,
-------------------------------------------------------------
Col. G)
------- is the balance of the prior year in the account as shown
in Col. I multiplied by the Carrying Charge Rate shown on
Schedule 1, Page 14, as updated by Sections 1.2 and 1.7.
2.9(g) Collection of Prior Year Balance, Including Interest (Schedule 2,
-----------------------------------------------------------------
Page 2, Col. H)
--------------- is the amount collected in rates as shown on
Schedule 1, page 3, Col. N. This amount cannot allow the Base
Access Charge to exceed 3.51 cents/kWh in 1998 or 3.35 cents/kWh
in later years. If the amount to be recovered would cause the
Access Charge to exceed 3.51 cents/kWh in 1998, the amount will
be reduced to 3.51 cents/kWh and the remainder will be left in
the reconciliation account and will earn a return. If the amount
to be recovered would cause the Access Charge to exceed 3.35
cents/kWh in any year after 1998, the amount will be reduced to
cause the Access Charge to equal 3.35 cents/kWh and the remainder
will be left in the reconciliation account and will earn a
return. However, any Reconciliation Account adjustments that
cause the annual Access Charge to increase or decrease by more
than 0.2 cents per kilowatthour over the prior year shall be
amortized with a carrying charge over the succeeding three years.
2.9(h) End of Year Account (Schedule 2, Page 2, Col. I)
------------------------------------------------ reflects the
ongoing balance in the reconciliation account. It reflects the
prior year's balance adjusted for
<PAGE> 240
current year adjustments, return on the outstanding balance less
recoveries or payments in the current year.
<PAGE> 241
<TABLE>
Boston Edison Company Attachment 3
Summary of Access Charges Schedule 1
Page 1 of 14
<CAPTION>
Estimate of Base
Line BECo. Total Access
# Year GWH Sales Fixed Component Variable Component Access Charge Charge
- ---- --------- --------------- ------------------ ------------- ------
$ in Millions cents per kWh $ in Millions cents per kWh $ in Millions cents per kWh
Col. A Col. B Col. C Col. D Col. E Col. F Col. G Col. H
(Col.C/Col.B) (Col.E/Col.B) (Col.C+Col.E) (Col.G/Col.B)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1 1998 13,045 $208 1.60 $250 1.91 $458 3.51
2 1999 13,187 192 1.46 250 1.89 442 3.35
3 2000 13,329 202 1.51 245 1.84 447 3.35
- ----------------------------------------------------------------------------------------------------------------------
4 2001 13,445 137 1.02 223 1.66 360 2.68
5 2002 13,547 131 0.96 213 1.57 343 2.53
6 2003 13,693 124 0.91 221 1.62 345 2.52
7 2004 13,822 118 0.85 226 1.63 344 2.49
8 2005 13,839 112 0.81 233 1.69 345 2.49
- ----------------------------------------------------------------------------------------------------------------------
9 2006 13,920 106 0.76 232 1.67 338 2.43
10 2007 14,024 100 0.71 226 1.61 326 2.32
11 2008 14,019 94 0.67 216 1.54 310 2.21
12 2009 14,159 88 0.62 220 1.55 308 2.18
13 2010 14,301 1 0.01 230 1.61 231 1.61
- ----------------------------------------------------------------------------------------------------------------------
14 2011 14,444 1 0.01 208 1.44 209 1.45
15 2012 14,588 1 0.01 140 0.96 141 0.97
16 2013 14,734 1 0.01 101 0.69 103 0.70
17 2014 14,881 1 0.01 60 0.40 61 0.41
18 2015 15,030 1 0.01 68 0.46 70 0.46
- ----------------------------------------------------------------------------------------------------------------------
19 2016 15,181 1 0.01 59 0.39 60 0.40
20 2017 15,332 0 0.00 0 0.00 0 0.00
21 2018 15,486 0 0.00 0 0.00 0 0.00
22 2019 15,641 0 0.00 0 0.00 0 0.00
Legend:
------
Col. B Per DPU 96-23 filing dated February 16, 1996 Col. E Schedule 1, Page 3, Col. N
Col. C Schedule 1, Page 2, Col. H
NOTE: Numbers may not add due to rounding on this Schedule
06/06/97 12:00 PM
</TABLE>
<PAGE> 242
<TABLE>
Boston Edison Company Attachment 3
Summary of Access Charges Schedule 1
Fixed Component Page 2 of 14
$ in Millions
<CAPTION>
Pre-Tax Amortization Net Fixed
Return on of Component
Generation Generation Transmission Adjustment Including
Related Related in Support Base for Adjustment for
Investment and Investment and of Remote Total Residual Residual
Line Regulatory Regulatory Generating Fixed Value Value
# Year Assets Assets Assets Component Credit Credit
- ---- ------ ------ ------ --------- ------ ------
Col. A Col. B Col. C Col. D Col. E Col. F Col. G
(Cols. B+C+D) (Col.E+Col.F)
<S> <C> <C> <C> <C> <C> <C> <C>
1 1998 $86 $121 $1 $208 $0 $208
2 1999 72 119 1 192 0 192
3 2000 63 138 1 202 0 202
- ----------------------------------------------------------------------------------------------------------------------
4 2001 54 82 1 137 0 137
5 2002 48 82 1 131 0 131
6 2003 42 82 1 124 0 124
7 2004 35 82 1 118 0 118
8 2005 29 82 1 112 0 112
- ----------------------------------------------------------------------------------------------------------------------
9 2006 23 82 1 106 0 106
10 2007 17 82 1 100 0 100
11 2008 11 82 1 94 0 94
12 2009 6 82 1 88 0 88
13 2010 1 1 0 1
- ----------------------------------------------------------------------------------------------------------------------
14 2011 1 1 0 1
15 2012 1 1 0 1
16 2013 1 1 0 1
17 2014 1 1 0 1
18 2015 1 1 0 1
- ----------------------------------------------------------------------------------------------------------------------
19 2016 1 1 0 1
20 2017 0 0 0 0
21 2018 0 0 0 0
22 2019
Total Amortization 1,112
Legend:
------
Col. B Schedule 1, Page 14, Col. F
Col. C Amorization used to levellize rates for 1998 - 2000, straight line plus excess NCIO thereafter until
the assets are fully depreciated
Col. G Actual Market Valuation will be credited in Reconciliation Account
06/06/97 12:00 PM
</TABLE>
<PAGE> 243
<TABLE>
Boston Edison Company Attachment 3
Summary of Access Charges Schedule 1
Variable Component Page 3 of 14
$ in Millions
<CAPTION>
Nuclear
Decomm. Power Contracts
& other =========================== Future Above Payments
Post Power Assumed Above Power Market in Lieu of
Line Shutdown Total Market Market Contract Fuel Property
# Year costs Obligation Value Payments Buyouts Transport Taxes
- ---- -------- ---------- ----- -------- ------- --------- -----
Col. A Col. B Col. C Col. D Col. E Col. F Col. G Col. H
(Col.C - Col.D)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1 1998 36 318 114 204 $0 $10 $0
2 1999 37 327 124 203 0 10 0
3 2000 37 324 124 199 0 8 0
- -----------------------------------------------------------------------------------------------
4 2001 14 329 120 209 0 0 0
5 2002 15 315 117 198 0 0 0
6 2003 15 327 121 206 0 0 0
7 2004 16 334 124 210 0 0 0
8 2005 16 346 129 217 0 0 0
- -----------------------------------------------------------------------------------------------
9 2006 17 346 130 216 0 0 0
10 2007 17 342 133 208 0 0 0
11 2008 18 335 137 198 0 0 0
12 2009 18 342 140 201 0 0 0
13 2010 19 356 145 211
- -----------------------------------------------------------------------------------------------
14 2011 19 304 116 188
15 2012 20 202 82 120
16 2013 171 69 101
17 2014 109 48 60
18 2015 118 50 68
- -----------------------------------------------------------------------------------------------
19 2016 98 39 59
20 2017
</TABLE>
<TABLE>
<CAPTION>
Employee Damages, PBR for
Severance Costs, or Net Nuclear Units Base
and Recoveries Remaining after Total Recon- Total
Line Retraining from Market Variable ciliation Variable
# Year Costs Claims Valuation Component Account Component
- ---- ----- ------ --------- --------- ------- ---------
Col. A Col. I Col. J Col. K Col. L Col. M Col. N
(Col. L + Col. M)
<S> <C> <C> <C> <C> <C> <C> <C>
1 1998 $0 $0 $0 $250 $0 $250
2 1999 0 0 0 250 (0) 250
3 2000 0 0 0 245 0 245
- --------------------------------------------------------------------------------------------------
4 2001 0 0 0 223 0 223
5 2002 0 0 0 213 0 213
6 2003 0 0 0 221 0 221
7 2004 0 0 0 226 0 226
8 2005 0 0 0 233 0 233
- --------------------------------------------------------------------------------------------------
9 2006 0 0 0 232 0 232
10 2007 0 0 0 226 0 226
11 2008 0 0 0 216 0 216
12 2009 0 0 0 220 0 220
13 2010 230 0 230
- --------------------------------------------------------------------------------------------------
14 2011 208 0 208
15 2012 140 0 140
16 2013 101 0 101
17 2014 60 0 60
18 2015 68 0 68
- --------------------------------------------------------------------------------------------------
19 2016 59 0 59
20 2017 0 0 0
Legend:
------
Col. B Schedule 1, Page 7, Col. B, plus Page 8 Col.D
Col. C Schedule 1, Page 9, Col.N
Col. D GWH on Page 10 multiplied by forecast Market price from MECO's filing DPU 96-25
Col. G Schedule 1, Page 12, Col. D
Col. F & H-K Forecast as zero
Col. L Col. B + Col. E + Col. F + Col. G + Col. H + Col. I + Col. J + Col. K
Col. M Schedule 2, Page 2, Col. I for the prior year, but this amount cannot allow the
rate on Schedule 1, Page 1 Column H to exceed 3.51 any excess will be deferred as
explained under section 2.9
Col. B-K Actual costs will be used for reconciliation as shown in Schedule 2 page 1
06/06/97 12:00 PM
</TABLE>
<PAGE> 244
<TABLE>
Boston Edison Company Attachment 3
Access Charges Schedule 1
Access Charge Mitigation Incentive Page 4 of 14
Mechanism -- Illustrative Calculation
<CAPTION>
Cumulative
Rolling Nominal
Base Average Annual Impact
Access Access Cumulative Incremental on
Line Charge Charge Bonus Bonus Access
# Year (cents/kWh) (cents/kWh) Allowed Required Charge
- ---- ----------- ----------- ------- -------- ------
Col. A Col. B Col. C Col. D Col. E Col. F
<S> <C> <C> <C> <C> <C> <C> <C>
1 1998 3.51 3.51 0.0 0.00 ---------------------------------------
2 1999 3.35 3.43 0.0 0.00 Legend:
3 2000 3.35 3.40 0.0 0.00 ------
- --------------------------------------------------------------------------- Col. B Schedule 1, Page 1, Col. H
4 2001 2.68 3.22 8.9 11.5 0.09 Col. C Cumulative average of current
5 2002 2.53 3.08 15.1 8.6 0.06 & prior years shown in Col. B
6 2003 2.52 2.99 20.4 7.7 0.06 Col. D For any given year based
7 2004 2.49 2.92 25.0 7.2 0.05 upon cumulative average
8 2005 2.49 2.87 28.7 6.2 0.04 access charge, interpolate
- -------------------------------------------------------------------------------- bonus from the table below:
9 2006 2.43 2.82 32.1 6.0 0.04 Col. E (Col. D current year -
10 2007 2.32 2.77 35.3 6.0 0.04 Col. D prior year) *
11 2008 2.21 2.72 38.3 6.1 0.04 (1 + WACC AT) ^ n, where
12 2009 2.18 2.67 40.7 5.4 0.04 n = number of years since
1998 +1, and WACC AT is
the weighted cost of capital
after-tax equal to 6.61%
Col. F Col. E / GWH sales shown on
Sch 1, Page 1, Col. B current
year
---------------------------------------
</TABLE>
<TABLE>
Assumptions:
1998 $ NPV Cumulative Bonus/(Penalty)
<CAPTION>
Rolling Average
Access Charge 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
- ------------- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1.00 $21 $38 $52 $63 $72 $80 $85 $90 $93 $96 $97 $98
1.20 20 36 49 60 68 76 81 86 89 91 92 93
1.40 19 34 47 57 65 72 77 81 84 86 88 88
1.60 18 32 44 53 61 68 73 77 79 81 83 83
1.80 17 31 41 50 58 64 68 72 75 77 78 78
2.00 16 29 39 47 54 60 64 68 70 72 73 74
2.20 14 25 34 41 47 52 56 59 61 62 63 64
2.40 12 21 29 35 40 44 47 50 51 53 54 54
2.60 10 17 23 28 33 36 39 41 42 43 44 44
2.80 8 13 18 22 25 28 30 32 33 34 34 34
3.00 5 10 13 16 18 20 22 23 24 24 25 25
3.20 3 6 8 10 11 12 13 14 14 15 15 15
3.40 1 2 3 3 4 4 4 5 5 5 5 5
3.50 0 0 0 0 0 0 0 0 0 0 0 0
06/06/97 12:00 PM
</TABLE>
<PAGE> 245
<TABLE>
Boston Edison Company Attachment 3
Unrecovered Plant Balances Schedule 1
$ in Millions Page 5 of 14
<CAPTION>
Applicable
Annual
DPU Depreciation
Form 1 for 1998 and
line Source Reference 12/31/95 12/31/97 Beyond
------ --------- -------- -------- ------
Col. A Col. B Col. C Col. D Col. F
<S> <C> <C> <C> <C> <C> <C>
1 Nuclear Land p.205 $6.7 $6.7
2 Nuclear Plant in Service p.205 1,181.9 1,181.9 rate
3 Nuclear CWIP p.216 1.1 1.1
4 Nuclear Accumulated Depreciation p.219 (444.3) (537.3) 3.93% $46.5
5 Nuclear Intangible 27.0 27.0
6 Amortization of Nuclear Intangible (9.8) (11.5) 3.28% 0.9
7 Nuclear Stabilization Line p.232 0.6 0.4 0.1
8 Nuclear Materials & Supplies Acct 15451 31.6 31.6
9 Amortization of Materials & Supplies A/C 15462/15463 (9.5) (12.9) 1.7
10 End of life unamortized final Nuclear Core p 203 (av 1993/5) 27.5 27.5
-------------------
11 TOTAL Nuclear (sum of lines 1 - 10) $812.8 $714.4
12 LESS Contract Customers 25.73133% of line 11 (209.1) (183.8) (12.7)
-----------------------------------------------------------------------------------------------
13 Net Pilgrim (a) (Line 11 minus line 12) $603.7 $530.6
-----------------------------------------------------------------------------------------------
14 Fossil Land (*) p.205 $7.1 $7.1
15 Fossil Plant in Service (*) p.205 842.7 842.7 rate
16 Fossil CWIP p.216 3.3 3.3
17 Fossil Accumulated Depreciation(*) p.219 (317.1) (375.5) 3.47% 29.2
18 Jets Land p.207 0.0 0.0
19 Jets Plant in Service p.207 42.3 42.3 rate
20 Jets Accumulated Depreciation p.209 (21.6) (23.9) 2.76% 1.2
21 LaGrange Street p.221 0.8 0.8
22 Generation Related Transmission Plant 10.0 10.0
23 Amortization of generation related Transmission Plant (6.3) (6.7) 1.80% 0.2
24 Generation Related General Plant 34.5 34.5
25 Amortization of generation related General Plant (9.2) (15.2) 3.0
- ---------------------------------------------------------------------------------------------------------------------
26 Total Generation unrecovered Plant Balance (sum of lines 13 - 24) $1,190.3 $1,050.0 $33.6
- ---------------------------------------------------------------------------------------------------------------------
Legend:
- ------
* Fossil Fuel Plants Plant Balances include the Edgar and L Street sites 1112.2331
(a) Nuclear Plant Balances represent the BECo. portion only; Contract Customers share is excluded
(b) Col C represents 1995 per book numbers from the DPU Form 1
(c) Col D represents the 1995 per book numbers in Col.(c) adjusted for two years depreciation at the rates in
Col.(F)
NOTE: Additional voluntary depreciation not included in current base rates are specifically excluded
(e.g. $22 million in 1996 for Mystic 4,5&6)
This additional depreciation does not reduce the recoverable amount of the generating assets above.
06/06/97 12:00 PM
</TABLE>
<PAGE> 246
<TABLE>
Boston Edison Company Attachment 3
Generation Related Regulatory Asset Balances Schedule 1
$ in Millions Page 6 of 14
<CAPTION>
Applicable
Annual
Amortization
Balance as of for 1998 and
Regulatory Asset 12/31/95 12/31/97 Beyond
---------------- -------- -------- ------
line # Col. A Col. B Col. C Col. D
<S> <C> <C> <C> <C> <C>
1 FAS 109 $19.2 $20.3 $1.7 (a)
2 FAS 106 Deferral 6.8 6.8 (b)
3 FAS 106 Transition Obligation 57.0 50.3 3.4 (b)
4 Unamortized Investment Tax Credit (26.2) (22.9) (1.7) (a)
5 National Energy Policy Act (NEPA) 9.3 7.6 0.8 (c)
---------------------------------------------------------------------
6 Total $66.2 $62.2 $4.2
---------------------------------------------------------------------
Notes:
(a). Allocation based on direct net plant adjusted for Pilgrim contract customer share
(b). Allocation based on direct labor adjusted for Pilgrim contract customer share
(c). Nuclear adjusted for Pilgrim contract customer share (25.73133%)
06/06/97 12:00 PM
</TABLE>
<PAGE> 247
<TABLE>
Boston Edison Company Attachment 3
Boston Edison Share of Fixed Nuclear Operating Costs Schedule 1
$ in Millions Page 7 of 14
<CAPTION>
Fixed
Line Operating
# Year Costs
- ---- -----
Col. A Col. B
<S> <C> <C>
1 1998 $23
2 1999 23
3 2000 23
- --------------------------------------------------------------------------------
4 2001
5 2002
6 2003
Note: There is no allocation to Pilgrim Contract Customers
06/06/97 12:00 PM
</TABLE>
<PAGE> 248
<TABLE>
Boston Edison Company Attachment 3
Total Annual Decommissioning Cost Schedule 1
$ in Millions Page 8 of 14
<CAPTION>
Line Year Boston
# ---- Contract Edison
- Col. A Pilgrim Customers Share
------- --------------------
Col. B Col. C Col. D
<S> <C> <C> <C> <C>
1 1998 $18 $5 $13
2 1999 18 5 14
3 2000 19 5 14
- ------------------------------------------------------------------------------
4 2001 19 5 14
5 2002 20 5 15
6 2003 21 5 15
7 2004 21 5 16
8 2005 22 6 16
- ------------------------------------------------------------------------------
9 2006 22 6 17
10 2007 23 6 17
11 2008 24 6 18
12 2009 25 6 18
13 2010 25 7 19
- ------------------------------------------------------------------------------
14 2011 26 7 19
15 2012 27 7 20
16 2013
Col. B $14 million in 1991 inflated at 3% per year
Col. C Pilgrim Contract Customers share being 25.73133% of Col.B
Col. D Col. B - Col. C
06/06/97 12:00 PM
</TABLE>
<PAGE> 249
<TABLE>
Boston Edison Company Attachment 3
Power Contract Obligations
Annual Obligations in Millions of Dollars Schedule 1
(Includes both energy and capacity costs)
Page 9 of 14
<CAPTION>
Ocean Ocean Hydro
Line Conn Canal State State NEA NEA Mass MBTA MBTA Quebec Mass -----
# Yankee 1 1 2 (A) (B) L'Energia Power Jet 1 Jet 2 1&2 Yankee Total
- ------ - - - --- --- --------- ----- ----- ----- ------ ------ -----
Col.A Col.B Col.C Col.D Col.E Col.F Col.G Col.H Col.I Col.J Col.K Col.L Col.M Col.N
---------------------------------------------------------------------------------------------------------
Share of Unit 9.5% 25.0% 23.5% 23.5% 46.6% 29.0% 73.0% 44.3% 100.0% 100.0% 11.2% 9.5%
---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1 1998 $21 $25 $25 $27 $76 $50 $25 $50 $2 $0 $11 $6 $318
2 1999 21 26 25 27 76 54 26 53 2 0 11 6 327
3 2000 20 27 24 26 76 58 27 52 2 0 10 0 324
4 2001 21 23 24 26 76 63 27 56 2 0 10 0 329
5 2002 23 0 26 25 76 67 28 58 2 0 10 0 315
- --------------------------------------------------------------------------------------------------------------------
6 2003 24 0 23 27 76 72 29 61 2 3 9 0 327
7 2004 26 0 24 26 76 78 30 61 2 3 9 0 334
8 2005 27 0 24 26 76 84 31 65 2 3 8 0 346
9 2006 29 0 24 26 76 90 25 65 0 3 8 0 346
10 2007 16 0 24 25 76 97 26 68 0 3 8 0 342
- --------------------------------------------------------------------------------------------------------------------
11 2008 0 0 24 26 76 104 27 67 0 3 7 0 335
12 2009 0 0 24 26 78 112 29 66 0 0 7 0 342
13 2010 0 0 24 26 85 120 30 65 0 0 7 0 356
14 2011 0 0 0 19 86 97 31 64 0 0 6 0 304
15 2012 0 0 0 0 100 0 32 64 0 0 6 0 202
- --------------------------------------------------------------------------------------------------------------------
16 2013 0 0 0 0 102 0 0 63 0 0 5 0 171
17 2014 0 0 0 0 104 0 0 0 0 0 5 0 109
18 2015 0 0 0 0 113 0 0 0 0 0 5 0 118
19 2016 0 0 0 0 94 0 0 0 0 0 4 0 98
20 2017 0 0 0 0 0 0 0 0 0 0 0 0 0
- --------------------------------------------------------------------------------------------------------------------
21 2018
22 2019
06/06/97 12:00 PM
</TABLE>
<PAGE> 250
<TABLE>
Boston Edison Company Attachment 3
Annual Obligations in GWH
Schedule 1
Page 10 of 14
<CAPTION>
Line Conn Ocean Ocean Mass MBTA MBTA Total
# Yankee Canal 1 State 1 State 2 NEA 1 NEA2 L'Energia Power Jet 1 Jet 2 Purchases
- ------ ------- ------- ------- ----- ---- --------- ----- ----- ----- ---------
Col.A Col. B Col.C Col.D Col.E Col.F Col.G Col.H Col.I Col.J Col.K Col. L
------------------------------------------------------------------------------------------------
Share of Unit 9.5% 25.0% 23.5% 23.5% 46.6% 29.0% 73.0% 44.3% 100.0% 100.0%
-----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1 1998 634 541 540 1,167 726 350 642 1 0 4,600
2 1999 661 532 533 1,166 726 364 729 1 1 4,713
3 2000 715 555 556 1,170 728 366 602 1 1 4,693
4 2001 568 533 545 1,166 726 365 731 1 1 4,636
5 2002 554 555 1,166 726 364 707 1 1 4,075
- -----------------------------------------------------------------------------------------------------------------
6 2003 533 534 1,167 726 365 755 2 1 4,082
7 2004 556 557 1,170 728 366 669 1 1 4,047
8 2005 533 545 1,167 726 365 732 1 1 4,069
9 2006 554 556 1,166 725 365 630 1 3,996
10 2007 533 534 1,166 725 364 644 1 3,966
- -----------------------------------------------------------------------------------------------------------------
11 2008 556 557 1,170 728 366 543 0 3,921
12 2009 556 557 1,170 728 366 543 3,921
13 2010 556 557 1,170 728 366 543 3,921
14 2011 418 1,170 546 366 543 3,044
15 2012 1,170 366 543 2,079
- -----------------------------------------------------------------------------------------------------------------
16 2013 1,170 543 1,714
17 2014 1,170 1,170
18 2015 1,170 1,170
19 2016 878 878
20 2017
- ------------------- ---------
Termination Dates 6/29/07 10/31/01 12/31/10 9/30/111 9/14/16 9/14/11 12/31/12 12/31/13 12/31/05
06/06/97 12:00 PM
</TABLE>
<PAGE> 251
<TABLE>
Boston Edison Company Attachment 3
Annual Utility Unit Sales Power Contracts Schedule 1
$ in Millions Page 11 of 14
<CAPTION>
Line
# Year Total
- ---- -----
Col. A Col. B
<S> <C> <C>
1 1998 $0
2 1999 0
3 2000 0
4 2001 0
5 2002 0
6 2003 0
7 2004 0
8 2005 0
9 2006 0
10 2007 0
11 2008 0
12 2009 0
Note: Pilgrim Contract Customers are credited to the individual
Access Charge pages
Note: FERC wholesale contracts are revenue credited to the Distribution Charge
06/06/97 12:00 PM
</TABLE>
<PAGE> 252
<TABLE>
Boston Edison Company Attachment 3
Annual Fixed Costs of Gas Transportation Schedule 1
Contractual Commitments Page 12 of 14
$ in Millions
<CAPTION>
Line Total
# Total Assumed Excess
- Transportaion Market Over
Year Cost Value (A) Market
---- ---- ---------- ------
Col. A Col. B Col. C Col. D
<S> <C> <C> <C> <C>
1
2 1998 $19 $10 $10
3 1999 20 10 10
4 2000 17 8 8
- ----------------------------------------------------------------------------------
5 2001 0 0 0
6 2002 0 0 0
7 2003 0 0 0
8 2004 0 0 0
9 2005 0 0 0
- ----------------------------------------------------------------------------------
10 2006 0 0 0
11 2007 0 0 0
12 2008 0 0 0
Note: These Gas Transportation Charges relate to New Boston
(A) 50% is deemed recoverable through the market.
06/06/97 12:00 PM
</TABLE>
<PAGE> 253
<TABLE>
Boston Edison Company Attachment 3
Summary of Acess Charges Schedule 1
Deferred Taxes on Fixed Component Page 13 of 14
$ in Millions
<CAPTION>
Book Basis Tax Basis
------------------------------ -------------------------------
Balance Balance
Balance Generation Total Balance Generation Excess
Net Book Related Net Net Tax Related Total Book Deferred
Line Value of Regulatory Book Value of Regulatory Tax Over Taxes @
# Year End Generation Assets Basis Generation Assets Basis Tax 39.225%
- -------- ---------- ------ ----- ---------- ------ ----- --- -------
Col. A Col. B Col. C Col. D Col. E Col. F Col. G Col. H Col. I
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1 1997 $1,050 $62 $1,112 $481 $50 $531 $581 $228
2 1998 935 57 992 217 47 264 727 285
3 1999 821 52 873 193 44 237 636 249
4 2000 688 47 735 171 40 211 523 205
- ---------------------------------------------------------------------------------------------------------------------
5 2001 612 41 653 150 37 187 466 183
6 2002 535 36 571 130 34 163 408 160
7 2003 459 31 490 109 30 139 351 138
8 2004 382 26 408 90 27 117 291 114
9 2005 306 21 327 81 23 104 222 87
- ---------------------------------------------------------------------------------------------------------------------
10 2006 229 16 245 73 20 93 152 60
11 2007 153 10 163 66 17 83 80 32
12 2008 76 5 82 61 13 74 7 3
13 2009 0 (0) 0 58 10 68 (68) (27)
12 2010
- ---------------------------------------------------------------------------------------------------------------------
13 2011
14 2012
Annual Amortization
Legend:
------
Col. B, line 1 Schedule 1 page5 Col D, line 25 - amortized as shown in Schedule 3 page 1
Col. C, Line 1 Schedule 1 page6 Col C, line 6 - amortized as shown in Schedule 3 page 1
Col. D Col B + Col. C
Col. E Schedule 3 page 2
Col. G Col E + Col. F
Col. H Col D- Col. G
Col. I Col H * Composite Tax Rate of 39.225
06/06/97 12:00 PM
</TABLE>
<PAGE> 254
<TABLE>
Boston Edison Company Attachment 3
Summary of Access Charges Schedule 1
Carrying Charge on Fixed Component Page 14 of 14
$ in Millions
<CAPTION>
Annual
Return on
Unamortized
Balance Balance
of Average Using
Line Fixed Deferred Net Net Carrying Charge
# Year End Component Taxes Balance Balance on Capital
- -------- --------- ----- ------- ------- ----------
Col. A Col. B Col. C Col. D Col. E Col. F
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1 1997 $1,112 $228 $884 -------------------------------------
2 1998 992 285 706 795 86 Carrying Charge
3 1999 873 249 623 665 72 Year End
4 2000 735 205 529 576 63 Capital Structure 1995
- ---------------------------------------------------------------------- LTD Taxable 47.63%
5 2001 653 183 470 500 54 Preferred 8.92%
6 2002 571 160 411 441 48 Common Equity 43.45%
7 2003 490 138 352 382 42 100.00%
8 2004 408 114 294 323 35
9 2005 327 87 239 267 29 Cost Rates
- ---------------------------------------------------------------------- LTD Taxable 8.31%
10 2006 245 60 185 212 23 Preferred 8.22%
11 2007 163 32 132 158 17 Common Equity 7.99%
12 2008 82 3 79 105 11 Total Weighted Cost Rates 8.16%
13 2009 0 (27) 27 53 6
12 2010 Reimbursement for taxes
- ---------------------------------------------------------------------- on equity component 2.71%
Legend: Carrying Charge Rate 10.88%
------ -------------------------------------
Col. B Schedule 1, Page 13, Col. D
Col. C Schedule 1, Page 13, Col. I Total weighted cost rate
Col. D Col. B - Col. C less tax shield on debt 6.61%
Col. E (Col. D prior year + Col. D current year) / 2
Col. F Col. E * Total Carrying Charge of 10.88%
06/06/97 12:00 PM
</TABLE>
<PAGE> 255
<TABLE>
Boston Edison Company Attachment 3
Reconciliation Adjustment - Illustrative Calculation
Schedule 2
Page 1
<CAPTION>
Revenue Adjustments Boston Edison Company Variable Cost Adjustments
---------------------------------------------------- --------------------------------------------------
Actual
Base Actual Power
Estimated Actual Delta Access Revenue Total Actual Power Contracts
kWh kWh kWh Charge Excess/ Variable Nuclear Total Market
Year Delivered Delivered Delivered Billed (Shortfall) Component Decommissioning Obligations Value
- ---- --------- --------- --------- ------ ----------- --------- --------------- ----------- ------
Col. A Col. B Col. C Col. D Col. E Col. F Col. G Col. H Col. I Col. J
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998 13,045 13,045 0 3.51 $0 $250 $36 $318 $114
1999 13,187 13,187 0 3.35 0 250 37 327 124
2000 13,329 13,329 0 3.35 0 245 37 324 124
- ----------------------------------------------------------------------------------------------------------------
2001 13,445 13,445 0 2.68 0 223 14 329 120
2002 13,547 13,547 0 2.53 0 213 15 315 117
2003 13,693 13,693 0 2.52 0 221 15 327 121
2004 13,822 13,822 0 2.49 0 226 16 334 124
2005 13,839 13,839 0 2.49 0 233 16 346 129
- ----------------------------------------------------------------------------------------------------------------
2006 13,920 13,920 0 2.43 0 232 17 346 130
2007 14,024 14,024 0 2.32 0 226 17 342 133
2008 14,019 14,019 0 2.21 0 216 18 335 137
2009 14,159 14,159 0 2.18 0 220 18 342 140
2010 14,301 14,301 0 1.61 0 230 19 356 145
- ----------------------------------------------------------------------------------------------------------------
2011 14,444 14,444 0 1.45 0 208 19 304 116
2012 14,588 14,588 0 0.97 0 140 20 202 82
2013 14,734 14,734 0 0.70 0 101 0 171 69
2014 14,881 14,881 0 0.41 0 60 0 109 48
2015 15,030 15,030 0 0.46 0 68 0 118 50
- ----------------------------------------------------------------------------------------------------------------
2016 15,181 15,181 0 0.40 0 59 0 98 39
2017 15,332 15,332 0 0.00 0 0 0 0 0
2018 15,486 15,486 0 0.00 0 0 0 0 0
</TABLE>
<TABLE>
<CAPTION>
Boston Edison Company Variable Cost Adjustments
--------------------------------------------------------------------------------------------------------------
Actual Actual
Actual Actual Damages, PBR for
Actual Above Actual Employee Costs, Nuclear Units Annual
Power Market Payments Severance or net Remaining Actual Reconciliation
Power Fuel in Lieu of and Recoveries after Total Delta Adjustment
Contract Transportation Property Retraining from Market Variable Variable Excess/
Year Buyouts Costs Taxes Costs Claims Valuation Component Component Shortfall
- ---- ------- ----- ----- ----- ------ --------- --------- --------- ---------
Col. A Col. K Col. L Col. M Col. N Col. O Col. P Col. Q Col. R Col. S
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1998 $0 $10 $0 $0 $0 $0 $250 $0 ($0)
1999 0 10 0 0 0 0 250 0 0
2000 0 8 0 0 0 0 245 0 0
- ---------------------------------------------------------------------------------------------------------------------
2001 0 0 0 0 0 0 223 0 0
2002 0 0 0 0 0 0 213 0 0
2003 0 0 0 0 0 0 221 0 0
2004 0 0 0 0 0 0 226 0 0
2005 0 0 0 0 0 0 233 0 0
- ---------------------------------------------------------------------------------------------------------------------
2006 0 0 0 0 0 0 232 0 0
2007 0 0 0 0 0 0 226 0 0
2008 0 0 0 0 0 0 216 0 0
2009 0 0 0 0 0 0 220 0 0
2010 0 0 0 0 0 0 230 0 0
- ---------------------------------------------------------------------------------------------------------------------
2011 0 0 0 0 0 0 208 0 0
2012 0 0 0 0 0 0 140 0 0
2013 0 0 0 0 0 0 101 0 0
2014 0 0 0 0 0 0 60 0 0
2015 0 0 0 0 0 0 68 0 0
- ---------------------------------------------------------------------------------------------------------------------
2016 0 0 0 0 0 0 59 0 0
2017 0 0 0 0 0 0 0 0 0
2018 0 0 0 0 0 0 0 0 0
Legend:
------
Col. B See Schedule 1, Page 1, Col. B
Col. C For demonstration purposes Actual kWh's delivered assumed to equal the Estimated kWh's delivered.
Col. D Col. C - Col. B
Col. E See Schedule 1, Page 1, Col. H
Col. F Col. D * Col. E
Col. G See Schedule 1, Page 3, Col. L
Cols. H - P For demonstration purposes Actual Variable Components are assumed to equal the Estimated Variable
Component illustrated on Schedule 1, Page 3
Col. Q Col. H + Col. I - Col. J + Col. K + Col. L + Col. M + Col. N + Col. O + Col. P
Col. R Col. Q - Col. G
Col. S Col. R - Col. F
06/06/97 12:00 PM
</TABLE>
<PAGE> 256
<TABLE>
Boston Edison Company Attachment 3
Reconciliation Account - Illustrative Calculation
Schedule 2
Page 2
<CAPTION>
Adjustment Annual Collection of
Deferral of for Actual Access Pre-Tax Prior Year
Access FAS 106, Charge Annual Return Balance End of Year
Reconciliation Charge FAS 87, and Mitigation Shortfall/ on Including Account
Year Adjustment Date FAS 109 Incentive Excess Balance Interest Balance
---- ---------- ---- ------- --------- ------ ------- -------- -------
Col. A Col. B Col. C Col. D Col. E Col. F Col. G Col. H Col. I
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1997 0
1998 (0) 0 0 0 (0) (0) 0 (0)
1999 0 0 0 0 0 0 0 0
2000 0 0 0 0 0 0 0 0
- -------------------------------------------------------------------------------------------------------------------
2001 0 0 0 (a) 0 0 0 0
2002 0 0 0 (a) 0 0 0 0
2003 0 0 0 (a) 0 0 0 0
2004 0 0 0 (a) 0 0 0 0
2005 0 0 0 (a) 0 0 0 0
- -------------------------------------------------------------------------------------------------------------------
2006 0 0 0 (a) 0 0 0 0
2007 0 0 0 (a) 0 0 0 0
2008 0 0 0 (a) 0 0 0 0
2009 0 0 0 (a) 0 0 0 0
2010 0 0 0 (a) 0 0 0 0
- -------------------------------------------------------------------------------------------------------------------
2011 0 0 0 (a) 0 0 0 0
2012 0 0 0 (a) 0 0 0 0
2013 0 0 0 (a) 0 0 0 0
2014 0 0 0 (a) 0 0 0 0
2015 0 0 0 (a) 0 0 0 0
- -------------------------------------------------------------------------------------------------------------------
2016 0 0 0 (a) 0 0 0 0
Legend:
- ------
Col. B Schedule 2, Page 1, Col S Col. F Col. B + Col. C + Col. D + Col. E
Col. C Calc. per Attach 6, para 2.9 (b) Col. G Col. I Prior Year * 10.88%
Col. D Calc. per Attach 6, para 2.9 (c) Col. H Schedule 1, Page 3, Col.M
Col. E Schedule 1, Page 4, Col. E, but Col. I Col. I Prior Year + (Col. F + Col. G + Col. H
assumed zero until actually earned Current Year)
Note (a) actual earned incentive will be shown in this column when actually earned from the incentive mechanism on page 4
06/06/97 12:00 PM
</TABLE>
<PAGE>
ATTACHMENT 4
BOSTON EDISON COMPANY
TERM SHEET FOR BIDDING STANDARD OFFER
SERVICE INCLUDING FUEL INDEX
<PAGE> 257
ATTACHMENT 4
BOSTON EDISON COMPANY
TERM SHEET FOR BIDDING STANDARD OFFER
SERVICE INCLUDING FUEL INDEX
<PAGE> 258
The Standard Offer Auction
Proposed Design
It is the parties' intent that the bidding process for securing
standard offer service be as competitive as possible and proceed in a timely
manner. Therefore, based on the parties' current understanding of the
timeframe for the Retail Access Date and divestiture, the parties believe at
this time that the Final RFP for Standard Offer Service should be issued no
sooner than the execution of purchase and sale agreements on the sale or
transfer of Boston Edison's interest in Mystic 7 and New Boston 1 and 2 but,
in any event, no later than six months after the Retail Access Date.
A. Administrative Process and Time Line
The Standard Offer Auction (the "Auction") will be administered and
conducted via a common process for all distribution companies. Bids will
be submitted and evaluated through a Request for Proposal process. The
principal steps and approximate timing of the Auction are outlined below.
September 1997 - Preliminary RFP Issued
-------------- ----------------------
The Preliminary RFP will detail all of the major elements,
requirements and commercial terms and conditions of the final RFP
that will be issued in 1998. Boston Edison will work with other
NEPOOL distribution companies to try to establish common standards
that will facilitate suppliers administration of bids to different
utilities. Its purpose is to give potential bidders the necessary
information to determine whether they intend to participate in the
Auction. Specific pre-bid qualifications will be established
including an audited statement of financial qualifications and other
relevant information to ascertain a bidder's ability to perform.
The preliminary RFP will also establish NEPOOL membership as a
criterion for auction participation. Neither the terms of the
Preliminary RFP nor Final RFP shall require a bidder to hold title
to the power needed to fulfill its obligations under its bid.
Pre-bid applications including required bidder qualification
information are due by (a date to be specified in the Preliminary
RFP) along with a modest non-refundable administration fee of
$1,000.
February 1998 - List of Qualified Bidders Submitted to the DPU
------------- ----------------------------------------------
for informational purposes)
<PAGE> 259
April 1998 - Final RFP Issued (including a standard contract)
---------- ----------------
Boston Edison recognizes that there is a balance of objectives
between issuing the RFP early to promote early development of the
market and issuing the RFP after the Retail Access Date when the
commencement of the Standard Offer Obligation is known and the
initial migration of large customers from the Standard Offer can
be assessed.
May 1998 - Bids Due
-------- --------
Bids would be accepted only from pre-qualified bidders and must
include a deposit of $5,000 for each MWh/Hr the bidder proposes to
supply over the duration of the Standard Offer. For example, if a
bidder proposed to supply 500 MWh/Hr per year for seven years, its
deposit would total $17,500,000 ($5,000 x 500 MWh/Hr x 7 yrs). This
deposit is refunded in the event that a bidder is not selected. If
successful, at the bidder's election, the deposit can either be
refunded or applied toward the performance bond (described below).
June 1998 - Winning Bidders Selected
--------- ------------------------
Contracts are expected to be executed between bidders and the
distribution companies and become effective upon the bidders (now
considered "suppliers" in this description) establishing a
"performance bond" in the amount of $50,000 per MWh/Hr to be
supplied under the Standard Offer. The performance bond would be
returned to the supplier upon completion of its contractual
obligations.
Notwithstanding the above schedule, the timing of the Standard Offer
bidding process will be coordinated with generation divestiture and
the Retail Access Date as described in the introductory paragraph to
this Attachment 4.
In addition, the date for filing a List of Qualified Bidders with
the Department shall not precede the issuance of the Final RFP by
more than 60 days.
B. Important Auction Rules and Conditions
1. Minimum Bid Elements -
-------------------- In order to conduct a fair and effective
Auction, all bids from pre-qualified bidders must include a
"Percentage Discount Off the Distribution Company Rates" (the
"Discount") and the "Peak Demand Amount" as described and applied
below. These two elements will be the only criteria by which
winning bidders are chosen. All bids from pre-qualified bidders
will otherwise be considered to be equivalent.
2. The Auction Procedures -
---------------------- Boston Edison shall implement the auction
procedures described below for determining the suppliers of Standard
Offer Service. However, these procedures may be revised if
necessary to promote the following
<PAGE> 260
goals: i) maximize the number of auction participants as a means
of optimizing discounts offered to Boston Edison; ii) ensure an
economically efficient process that will result in the highest
discounts appropriate to market conditions in Massachusetts; iii)
and minimize opportunities for collusion among bidders.
a. Brand Name Identification and Back Up Service Power Auction -
-----------------------------------------------------------
This is a zero discount bid that will supply power that is not
provided under sections b. or c. below. The successful bidder
will be entitled to have its brand name shown on the customer's
bill as the Back Up Service Power Provider. Where several bids
are received, the bidder that wins the highest quantities in b.
and c. below will be awarded the Back Up Service Contract.
b. Seven year Flat Discount Auction -
-------------------------------- This is a single, constant
discount to be in effect for all seven years of the Distribution
Company Rates, expressed as a percentage greater than 0%, with
larger discounts being viewed more favorably. Winning bidders
are to be paid based upon the next highest discount bid whether
determined by the Seven Year Flat Discount Auction or by the
lowest discount bid in the next best Alternative Individual
Auction Increment, discussed below (a second price or Vickery
auction).(1) The bids in this auction shall be sealed until
the Alternative Individual Year Auction set forth below is
completed.
c. Alternative Individual Year Auction ("Alternative Auction") -
-----------------------------------
This Alternative Auction shall take place immediately following
the Seven Year Flat Discount Auction. Bidders will be required
to bid separately for each year, and unlike the Seven Year Flat
Discount Auction, a bid for any single year may not be
conditioned on success in any other year. Thus, the Alternative
Auction shall allow bidders to specify different discounts in
different years. Bid amounts must be in increments of 50
megawatthours per hour which will be delivered as specified
below. Prices in the Alternative Auction shall be open to other
bidders, but the identity of the bidders associated with the
prices will not be identified. The Alternative Auction will
continue for multiple rounds until the next bid fails to improve
the discount offered in the prior bid by one percent.
Following completion of the bidding, Boston Edison shall rank
the bids for each individual year, with larger discounts viewed
more favorably, and shall identify the best bids in each year
that would fill a 50 megawatthour per hour increment covering
all seven years of the purchase period. Boston Edison will then
repeat the process for as many increments as possible until the
bids no longer cover all seven years in the period.
[FN]
____________________
(1) For example, if the best four winning bids (out of 10 submitted) met the
distribution company's expected demand at Discounts of 12.5%, 10%, 9% and
7% respectively, the first winning bidder would receive a discount of 10%,
the second winning bidder 9%, the third 7%, and the fourth would receive
the Discount bid by the first losing bidder (who bid 6.5%).
<PAGE> 261
d. Selection of Suppliers from Both Auctions -
----------------------------------------- The increments from
the Alternative Individual Year Auction will then be compared
to the Seven year Flat Discount Auction by assigning the
Alternative Individual Auction Increment with the lowest
discount bid in any single year of the increment. In the event
of ties, the earliest, highest discount shall have priority.
Suppliers in the Alternative Individual year Auction shall be
held to their bids, unlike the second price or Vickery auction
used in the Seven year Flat Discount Auction.
3. Payment by Distribution Company -
------------------------------- The distribution company is
responsible for paying suppliers at the following Distribution
Company Rates, reduced by the applicable Discount, for all energy
the supplier delivers (less losses) in the respective year. These
rates are flat annual values and do not include a demand or capacity
component and will not be adjusted for seasonal or time of day
factors.
<TABLE>
Distribution Company Rates
--------------------------
<S> <C>
1998 3.2 cents/kWh
1999 3.5
2000 3.8
2001 3.8
2002 4.2
2003 4.7
2004 5.1
</TABLE>
For example, if a supplier bid a Discount of 5.5% and delivered
500 GWH to ultimate customers in 1999, that supplier would receive
$16,537,500 from the distribution company (3.5 cents/kWh x (1-.055)
x 500 GWH x 1,000,000 kWh/GWH x .01 $/cents).
A fuel index adjustment mechanism, applied to Distribution Company
Rates, may provide additional revenues to suppliers in the event
that large, unexpected increases in market oil and gas prices occur.
This adjustment is further described below.
4. Peak Demand Amount -
------------------ Bids shall specify a Peak Demand Amount
expressed in MWh/Hr that the bidder commits to supply to the
distribution company in each year of the Standard Offer. This
amount represents the nominal maximum amount of energy a supplier
is responsible to provide the distribution company in any given
hour as measured at the ultimate customer's meter and accounting
for all distribution and transmission losses. The amount of the
bid deposit and the performance bond will be determined based on
the Peak Demand Amount times the number of years that the Peak
Demand Amount will be provided. Suppliers are responsible for all
electric delivery losses and any necessary transmission arrangements
and costs. The minimum bid amount will be 50 MWh/Hr.
<PAGE> 262
5. Right to Bid a Joint Supply -
--------------------------- Prequalified bidders will have the
right, subject to any provision of law, to submit joint bids
pursuant to which one supplier may provide less than the full
amount of Delivered Energy as long as the other suppliers on the
joint bid provide the remainder of the Delivered Energy obligation,
and the total performance bond is posted and in effect for the seven
years.
6. Higher Discounts Ensure a Right to a Longer Term of Supply -
----------------------------------------------------------
Customers have the right to leave the Standard Offer at any time
to receive service in the competitive energy market (subject to a
minimal notice provisions). In addition, residential and G-1
customers have a limited right to return to Standard Offer service
in the first year after the retail access date. As such, the amount
of energy required from suppliers under the Standard Offer may
likely decline over time. Supplier(s) who are in the increment with
the highest Assigned Discount will have the right to provide energy
for the longest period of time. With declining customer load due to
departures from Standard Offer service, lower Discount suppliers
whose Delivered Energy amount exceeds the distribution company's
needs will have their Delivered Energy amounts reduced and Standard
Offer supply contracts ultimately terminated.
7. Load Responsibility and Allocation -
---------------------------------- Suppliers are responsible for
a percentage of the distribution company's Standard Offer real-time
customer energy demand (minute by minute, hour by hour, day by day)
including but not limited to any installed or operating reserves or
other requirement required by NEPOOL or any Independent System
Operator. This includes changes in customer demand for any reason,
including but not limited to seasonal factors, normal daily load
patterns, increased usage, demand side management activities,
extremes in weather, etc. The only exception is for the loss of
Standard Offer customers as described in the section immediately
above. Responsibility is allocated to a supplier based on its
Delivered Energy bid divided by the estimated hourly Standard Offer
energy demand of the distribution company.
8. Responsibility for Electric Delivery Losses -
------------------------------------------- Suppliers will provide
all losses, in kilowatts and kilowatt-hours, from the supplier's
generation sources to the customer meter.
C. Adjustment to Distribution Company Rates
Distribution Company Rates, in B.3. above, are subject to upward
adjustment if there are substantial increases in the market prices of
No. 6 residual fuel oil (1% sulfur) and natural gas after 1999, as
described in the following section. If invoked, prices would change as
a function of the amount by which market fuel prices exceed the
predetermined price "trigger" levels. These triggers have been set to
allow a large dead-band in which no increases to Distribution Company
Rates would apply.
<PAGE> 263
D. Standard Offer Fuel Index
The Customer Rate in effect for a given billing month is multiplied by a
"Fuel Adjustment" that is set equal to 1.0 and thus has no impact on
Distribution Company Rates unless the "Market Gas Price" plus "Market Oil
----
price" for the billing month exceeds the "Fuel Trigger Point" then in
effect, where:
Market Gas Price is the average of the values of "Gas Index" for the
----------------
most recent twelve months through and including the billing month,
where:
Gas Index is the average of the daily settlement prices for the last
---------
three days that the NYMEX Contract (as defined below) for the month
of delivery trades as reported in the "Wall Street Journal",
expressed in dollars per MMBtu. NYMEX Contract shall mean the New
York Mercantile Exchange Natural Gas Futures Contract as approved
by the Commodity Futures Trading Commission for the purchase and
sale of natural gas at Henry Hub;
Market Oil Price is the average of the values of "Oil Index" for the
----------------
most recent twelve months through and including the billing month, where:
Oil Index is the average for the month of the daily low quotations
---------
for cargo delivery of 1.0% sulfur No. 6 residual fuel oil into New
York harbor, as reported in "Platt's Pilgrim U.S. Markets can" in
dollars per barrel and converted to dollars per MMBtu by dividing
by 6.3; and
If the indices referred to above should become obsolete or no longer
suitable, the distribution company shall file alternate indices with
the Department.
Fuel Trigger Point is the following amounts, expressed in dollars per
------------------
MMBtu, applicable for all months in the specified calendar year:
<TABLE>
<S> <C>
2000 $5.35/MMBtu
2001 $5.35
2002 $6.09
2003 $7.01
2004 $7.74
</TABLE>
In the event that the Fuel Trigger Point is exceeded, the Fuel Adjustment
value for the billing month is determined based according to the following
formula:
Fuel = (Market Gas Price + $.60/MMBtu) + (Market Oil Price + $.04/MMBtu)
Adjustment -----------------------------------------------------------------
Fuel Trigger Point + $.60 + $.04/MMBtu
Where:
<PAGE> 264
Market Gas Price, Market Oil Price and Fuel Trigger Point are as
defined above. The values of $.60 and $.04/MMBtu represent for gas
and oil respectively, estimated basis differentials or market costs
of transportation from the point where the index is calculated to a
proxy power plant in the New England market.
For example, if at a point in the year 2002 the Market Gas Price and
Market Oil price total $6.50 ($3.50/MMBtu plus $3.00/MMBtu respectively),
the Fuel Trigger Point of 6.09 would be exceeded. In the case the Fuel
Adjustment value would be
($3.50 + $.60/MMBtu) + ($3.00 + $.04/MMBtu) = 1.0609
----------------------------------------------------
$6.09 + $.60 + $.04/MMBtu
The Customer Rate paid to the distribution company is increased by this
Fuel Adjustment factor for the billing month, becoming 4.4548 cents/kWh
(4.2 x 1.0609).
In subsequent months the same comparisons are made and, if applicable, a
Fuel Adjustment determined.
Incremental revenues received by the distribution company as the result
of a Fuel Adjustment would be allocated to Standard Offer suppliers in
proportion to the Standard Offer energy provided by a supplier to the
distribution company in the applicable billing month.
<PAGE>
ATTACHMENT 5
BOSTON EDISON COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
<PAGE> 265
ATTACHMENT 5
BOSTON EDISON COMPANY
PERFORMANCE STANDARDS
UNDER RETAIL ACCESS TARIFFS
<PAGE> 266
Attachment 5
Page 1 of 3
Under the retail access tariffs, Boston Edison shall establish
performance standards for reliability and customer service. The standards are
designed so Boston Edison will incur various penalties depending upon its
level of performance below an agreed upon target level. The standards are set
based on averages of historic data, as shown on page 3 of this Attachment.
SERVICE RELIABILITY PERFORMANCE STANDARD
The Service Reliability Performance Standard shall be defined as the
duration of outages per customer served. An outage is the unscheduled loss of
electric service to more than one customer for more than five minutes. The
duration per customer served is the total length of time in minutes that an
average customer is without service per year. Excluded from reliability
measurement are extraordinary events, such as major disasters, earthquakes,
wildfires, floods, hurricanes, tornadoes, ice storms, wind storms or other
weather events beyond the control of the Company.
The schedule penalties under the Service Reliability Performance Standard
is as follows:
<TABLE>
<CAPTION>
Duration
of Outages
(minutes) Penalties
---------- ---------
<S> <C>
Less than 142 0
143 to 154 ($125,000)
155 to 166 ($250,000)
167 to 177 ($500,000)
More than 177 ($1,000,000)
</TABLE>
<PAGE> 267
Attachment 5
Page 2 of 3
CUSTOMER SERVICE PERFORMANCE STANDARD
The Customer Service Performance Standard is the level of customer
favorability. Boston Edison will commission annual surveys of its customers
to determine their overall level of favorability with Boston Edison.
Measurement shall be based on the combination of very favorable and favorable
responses to customer survey participants questioned to their opinion of the
Boston Edison company.
The Schedule of penalties under the Customer Service Performance Standard
is as follows:
<TABLE>
<CAPTION>
% of Responses
Favorable or
Very Favorable Penalties
-------------- ---------
<S> <C>
77 or greater 0
76% to 74% ($125,000)
73% to 71% ($250,000)
70% to 68% ($500,000)
Less than 67% ($1,000,000)
</TABLE>
<PAGE> 268
Attachment 5
Page 3 of 3
BOSTON EDISON COMPANY
DEVELOPMENT OF PERFORMANCE STANDARDS
FOR SERVICE RELIABILITY AND CUSTOMER SERVICE
<TABLE>
Service Reliability Customer Service:
Duration of Outages Customer Satisfaction
<CAPTION>
% of
----
Respondents
-----------
Favorable or
------------
Year Year Very Favorable
---- ---- --------------
<S> <C> <C> <C>
1995 117 1995 82%
1994 133 1994 83%
1993 114 1993 82%
1992 84 1992 85%
1991 95 1991 85%
1990 111 1990 82%
1989 112 1989 81%
1988 171 (*)1988 76%
1987 131 1987 79%
1986 119 1986
Average 119 Average 82%
Std. Deviation 24 Std. Deviation 3%
- ------------------------------- --------------------------------
Performance Standard 142 Performance Standard 77%
- ------------------------------- --------------------------------
</TABLE>
Duration per Customer Served (Minutes) = (*) Survey question changed from
Customer Minutes Interrupted customer opinion "your electric
---------------------------- company" to "Boston Edison
Number of customers served Company"
<TABLE>
Customer Credit Schedule
<CAPTION>
% of Respondents
Duration Customer Favorable or Customer
of Outages Credit Very Favorable Credit
<S> <C> <C> <C>
up to 142 $0 less than 68% $1,000,000
143 to 154 $125,000 68% to 70% $500,000
155 to 166 $250,000 71% to 73% $250,000
167 to 177 $500,000 74% to 76% $125,000
more than 178 $1,000,000 77% $0
</TABLE>
(increments of 1/2 a standard deviation)
4:04 PM 3/10/97
<PAGE>
ATTACHMENT 6
BOSTON EDISON COMPANY
ENVIRONMENTAL PLAN
for
INDUSTRY RESTRUCTURING
<PAGE> 269
ATTACHMENT 6
BOSTON EDISON COMPANY
ENVIRONMENTAL PLAN
for
INDUSTRY RESTRUCTURING
<PAGE> 270
Electric Utility Restructuring Plan
-----------------------------------
Boston Edison Company - Proposal for Environmental Component
------------------------------------------------------------
I. Purpose and Outline
-------------------
The purpose of the environmental component of an electric industry
restructuring plan is to provide a means such that a competitive industry
structure supports and furthers the efforts of environmental regulators to
reduce the environmental impacts of electricity generation. There are
multiple approaches towards attaining this objective. A few of these are:
1. Continued implementation of Clean Air Act programs and
requirements. Clearly there has already been substantial
environmental improvement in recent years through programs such
as EPA's Acid Rain Program and significant additional improvement
is virtually certain through implementation of state and regional
ozone control programs. These programs will continue,
irrespective of industry restructuring, and it is not
unreasonable to anticipate even further requirements as a result
of national ambient air quality standards review or Clean Air Act
reauthorization.
2. Old source review approaches such as that laid out in the
restructuring proposal filed in DPU 96-25, and which is also
described below.
3. Generation performance standards (GPS) approaches based upon
establishment of regional caps and implementation of market
trading systems for allowances issued under those trading caps.
4. Environmental comparability approaches based upon level playing
field principles applied to generation within a state or region
as well as to electricity imports into a state or region.
5. Unit, or system specific commitments for emissions reductions
consistent with one or more of the above generic approaches.
Boston Edison's environmental proposal draws from each of these approaches.
We remain committed to continued implementation of programs and requirements
pursuant to the Clean Air Act. We have also reviewed the old source
performance standard approach as set forth in the settlement filing in DPU
96-25. Boston Edison and its affected units are already in substantial
compliance with emissions levels that would result from this approach.
Section II, below, reiterates this generic proposal and Section III, below,
contains Boston Edison's commitment to this proposal for its affected units.
Finally, Boston Edison has also reviewed approaches being developed to
implement Generation Performance Standards for NOx on a regional basis as well
as to incorporate principles of environmental comparability. These and other
elements which go beyond current Clean Air Act requirements or the old source
review approach are addressed in Section IV, below.
<PAGE> 271
II. Generic Old Source Proposal
---------------------------
1. The program is designed to require all older fossil-fueled
electric generating units throughout the U.S. to meet "old source
performance standards" ("OSPS") for NOx and SO2 on January 1 of
the year following the year a unit becomes 40 years old. The 40
year time period starts from the year a unit commenced commercial
operation. For those units that are 40 years or older in the
year the program becomes effective, they will be required to meet
OSPS by January 1 of the following year. The end point for this
program is the year 2010; therefore, all units will be assumed to
be 40 years old on or before December 31, 2009.
2. As of the date the program becomes effective, each existing
operating unit will receive "allowances" for that unit's
emissions of NOx and SO2. Each allowance equals one ton of
allowable emissions. Unit-specific allowances are aggregated
to become a utility company-wide cap.
3. New units or repowered units subject to New Source Performance
Standards, that commence commercial operation after the date the
program is implemented, will not receive allowances; and thus
not be included under the program. Emissions from new or
repowered units will not be included in determining a company's
overall cap of NOx or SO2.
4. Unit-specific allowances are calculated as follows:
a. For units 40 years old or older, or by the year 2010:
Yearly Net Electrical Conversion
Generation X Heat Rate X Emission Rate X Factor = Tons/Year
(kWh) (Btu/kWh) (lbs./MMBtu) 1
----------
9
2x10
The elements of the formula are derived as follows:
i) Yearly Net Electrical Generation = average kWh
of the highest eight (8) of ten (10) year period
of 1986-1995, as reported on U.S. Department of
Energy Form EIA - 767, Schedule IV.
ii) Heat Rate = 10,000 Btu/kWh
iii) Emission Rate = 0.30 lbs/MMBtu for SO2
0.15 lbs/MMBtu for NOx
PROVIDED, however, that if a unit's required emission rate
is lower than the rates listed above, the lowest, most
stringent emission rate applies.
<PAGE> 272
iv) Conversion Factor = factor required to convert
differing measures used in formula to result in
tons per year of emissions.
b. For units less than 40 years old:
NOx --- Same formula as in 4.a. above, except that
emission rate is set at the regulatory limit.
SO2 --- Allowances as allocated under Acid Rain Program,
Title IV of federal Clean Air Act.
5. Each utility company may meet its allowance cap by any
combination of control technologies, fuel switching, unit
retirements, operational changes and/or retirements of purchased
or surplus allowances. Selection of any one or a combination of
more than one of these options to meet the company cap will be at
the sole discretion of the utility company.
6. SO2 allowances may be traded freely in the market as allowed
under the Clean Air Act, Title IV Acid Rain Program regulations.
Unused allowances may be banked and carried forward also as
allowed under the Acid Rain Program regulations.
7. It is anticipated that a NOx trading program will be established
similar to the federal SO2 program. Unused NOx allowances also
may be banked, provided, however, that allowance withdrawals from
the bank may be subject to a "flow control" mechanism as
specified in the Ozone Transport Commission model rule.
8. With respect to jointly-owned units, their participation in the
program will be governed in the same manner as jointly-owned
units rate governed under the federal Acid Rain Program.
9. The final emission reductions applicable on January 1, 2010, will
be subject to the following "trigger" mechanisms which assure
that a substantive portion of the national emissions inventory
is subject to this program:
a. If in calendar year 2005, the actual NOx emissions of the
emissions inventory in the Ozone Transport Region ("OTR")
and in the East Central Area Reliability Coordination
Agreement ("ECAR") and the Mid-America Interconnected
Network ("MAIN") of the North American Electric Reliability
Council (hereinafter collectively referred to as "the
Region") are reduced by no less than 50% from the calendar
year 1996 actual NOx emissions of the emissions inventory in
the Region, then implementation of the OSPS for NOx will be
on January 1, 2010. If a reduction of NOx emissions of 50%
or greater is not achieved in calendar years 2005, the
actual emissions of the emissions inventory in the Region
will be measured in each successive calendar year until such
time as the prescribed level of
<PAGE> 273
reduction from the year 1996 baseline is actually achieved,
and implementation of the OSPS NOx requirements will be five
(5) years from the year the emission reduction of 50% or
greater is actually achieved.
b. If the SO2 allowances allocated under Title IV of the
federal Clean Air Act to the emissions inventory in the
Region in the year 2007 are 50% or less of the SO2
allowance allocation made in the year 2000, then
implementation of the OSPS for SO2 will be on January 1,
2010. If a reduction of 50% or greater is not achieved in
the year 2007, the SO2 allocation will be reviewed in each
successive year until such time as the prescribed level of
reduction from the year 2000 baseline is actually achieved,
and implementation of the OSPS SO2 requirement will be three
(3) years from the year the reduction in allowance
allocation of 50% or greater from the year 2000 baseline is
actually achieved.
The NOx- and SO2-specific triggers described above will be
implemented independent of one another.
III. Boston Edison Specific Requirements Under Old Source Proposal
------------- -----------------------------------------------
1. The specific emission reductions included in this proposal apply
to the following major fossil-fueled power plants:
Mystic Station, Everett, MA
Unit Nos. 4, 5, 6 and & 7
New Boston Station, South Boston, MA
Unit Nos., 1 and 2
Boston Edison Company is the owner and operator of the Mystic and
New Boston Stations. Boston Edison may meet its allowance cap by
any combination of control technologies, fuel switching, unit
retirements, operations changes and/or retirements of purchased
or surplus allowances.
2. The program start date for Mystic and New Boston Stations is
2000. The dates when the Mystic and New Boston units will be
subject to OSPS are as follows:
<TABLE>
<CAPTION>
Unit No. Mystic Station New Boston Station
-------- -------------- ------------------
<S> <C> <C>
1 - 2005(1)
2 - 2005
4 2000(2) -
5 2000
6 2000 -
7 2010(3) -
</TABLE>
[FN]
____________________
(1) Unit #1 is 40 years old in 2005, Unit # 2 in 2007.
(2) The average 40 year anniversary for the three units is 2000.
(3) Unit #7's 40 year anniversary is 2015.
<PAGE> 274
3. The emission profile for all the Mystic and New Boston units
under the program, absent any triggers described in Section II.9
above and Section III.5 below, are illustrated in the attached
graphs.
4. With respect to SO2, as can be seen from the emission profile
graph, Boston Edison's annual system emissions are currently well
below the cap established by the program. Even with increased
utilization of fuel oil above current levels, the annual system
emissions will be at or below the program cap.
5. With respect to NOx, the following additional trigger applies to
Boston Edison:
. On January 1, 2003, New Boston Unit Nos. 1 & 2 will receive
allowances calculated pursuant to Section II.4.a. of this
proposal if in calendar year 2000 the actual NOx emissions
of the emissions inventory in the region is reduced by no
less than 50% from the emissions of the emissions inventory
in the Region in the baseline year of 1990. If a reduction
of 50% or greater is not achieved in calendar year 2000, the
actual emissions of the emissions inventory will be measured
in each successive calendar year until such time as the
prescribed level of reduction from the year 1990 baseline is
actually achieved. New Boston Unit Nos., 1 & 2 will receive
allowances pursuant to Section II.4.a of this proposal in
the third year after the prescribed reductions in the
emissions inventory are actually achieved; provided,
however, that in no event shall the date the units are
subject to the OSPS requirements of Section II.4 go beyond
January 1, 2005 for New Boston Unit Nos. 1 & 2.
IV. Additional Commitments
----------------------
1. It is the intention that all environmental requirements herein
pertaining to specific units would carry forward in the event
such units were divested by Boston Edison. Provisions pertaining
to the sale of specific units, when considering the existence of
requirements imposed herein on a system-wide basis, will be
developed in cooperation with the parties to effectuate the
intent of this proposal.
2. Boston Edison is prepared to support and commit to the further
reductions of Nitrogen Oxides (NOx) emissions as defined under
the recently proposed Generation Performance Standards (GPS) Cap
and Trade Program. The EPA and other federal agencies appear to
agree that additional controls for NOx are required within the
Ozone Transport Assessment Group (OTAG) region in order to reduce
the current 3 million tons of NOx emissions each ozone season to
1 million tons or less. Based on the best available scientific
information, there is evidence and support for speedier
reductions than called for in the OTC MOU, and the GPS program
accomplishes this.
Lowering emission caps cannot be done on a state-by-state basis.
It must be done by advancing more aggressive national or regional
environmental goals. The 1 Million Ton NOx GPS Cap & Trade
Program would bring all utilities in the OTAG Region into
compliance with these desired emission reduction goals over a
three year timeframe. Specifically, the program calls for:
<PAGE> 275
By May 1, 1999 all utility emissions would be capped at 1.6
million tons
By May 1, 2000 the cap would be reduced to 1.3 million tons
By May 1, 2001 the cap would be reduced to 1.0 million ton
The program establishes annual ozone season unit emission rates,
based on the three year phased reduction cap, by which unit
allowances may be allocated. NOx allowances for the ozone season
would be allocated to Boston Edison units in an amount determined
by the formulas set forth in the GPS program. Since this is a
regional program and since current emissions from Boston Edison
units are well below those of other regional utilities, our
commitment to implement such reductions would be conditioned upon
adoption of the GPS program either in Massachusetts, Connecticut
and one other New England state or in Massachusetts and four
other OTR states upwind of Massachusetts.
3. Boston Edison supports the position outlined by Commissioner
Struhs of the Massachusetts Department of Environmental
Protection in his October 29, 1996 letter in Docket DPU 96-25
concerning the principle of environmental performance and
operational efficiency applying to all entities that intend to
sell electricity in Massachusetts. We recognize the difficulty
in implementing such a standard of environmental comparability
on a regional basis but propose to work with DEP and other
parties in order to effectuate such a principle through
appropriate legislative or regulatory action.
<PAGE>
ATTACHMENT 7
BOSTON EDISON COMPANY
JURISDICTIONAL SEPARATION OF TRANSMISSION
AND DISTRIBUTION FACILITIES PURSUANT TO
FERC ORDER 888
<PAGE> 276
ATTACHMENT 7
BOSTON EDISON COMPANY
JURISDICTIONAL SEPARATION OF TRANSMISSION
AND DISTRIBUTION FACILITIES PURSUANT TO
FERC ORDER 888
<PAGE> 277
BECO Evaluation of FERC's Seven Factor Test
<PAGE> 278
Table of Contents
<TABLE>
<CAPTION>
Page
----
<S> <C> <C>
I. Summary 1
II. Federal and State Jurisdictional Requirements per FERC Order 888 3
III. Definition of BECO Retail Distribution System 4
IV. Definition of BECO Transmission System 11
V. Attachments 12
</TABLE>
<PAGE> 279
I. Summary
The Federal Energy Regulatory Commission ("FERC" or "Commission") in
its Order 888 proposed a seven factor test to differentiate between
transmission facilities subject to FERC's jurisdiction and distribution
facilities subject to state rate-making authority. FERC has affirmed its
exclusive authority over all transmission and distribution facilities for
wholesale wheeling and the transmission component of unbundled interstate
retail wheeling. The seven-factor test set forth in Order 888 is designed to
identify the characteristics of local distribution systems that differentiate
them from transmission systems. The seven-part test proposed by the
Commission is intended to be evaluated on a case by case basis and is based
on the actual use of the distribution and transmission system.
Boston Edison Company ("BECO") is a traditional vertically integrated
public utility serving a compact urban population center immediately
surrounding the City of Boston. In anticipation of regulatory changes
designed to promote competition at the wholesale and retail levels, the
Company was functionally reorganized on January 1, 1996 to segregate nuclear
and fossil generation, retail distribution, and transmission activities under
the BECO Corporate umbrella, along with several unregulated subsidiaries.
BECO concludes that its existing organizational structure is in
accordance with the Commission's definition of transmission and local
distribution facilities based on actual use of the transmission and
distribution systems. Separate business units have been established for
Nuclear and Fossil Generation functions. The wires business has been further
segregated within the Electric Delivery Section of the Customer Business Unit.
The Electric Delivery Section
<PAGE> 280
includes the retail transmission and distribution resources which are subject
to state rate-making jurisdiction today. Within the Electric Delivery
Section, all transmission facilities are now consolidated within the
Transmission Group.
<PAGE> 281
II. Overview of Federal and State Jurisdictional Requirements per FERC
Order 888
In Order 888, the FERC addresses its exclusive jurisdictional claim
over unbundled transmission in interstate commerce used by public utilities
for retail wheeling up to the point of local distribution. The Commission
also exercised exclusive jurisdiction over all facilities, whether
transmission or distribution, used for wholesale wheeling. To determine the
jurisdictional bright line for retail access purposes, the Commission proposed
the seven factor test of local distribution. This test of functional and
technical characteristics of facilities would define local distribution
facilities.
Under Order 888, the Commission will defer jurisdiction over local
distribution facilities to state commissions if the state commission applies
the seven criteria set forth in Order 888. Accordingly, this report is
prepared for use before the Massachusetts Department of Public Utilities, as
well as FERC, when evaluating the jurisdictional separation between
transmission and distribution facilities.
<PAGE> 282
III. Definition of Boston Edison Company Distribution System
The local distribution systems of Boston Edison Company are typically
5, 15, or 25 kV class systems. These systems are radial in nature, serving
retail load in the vicinity of the local distribution facilities. The local
distribution systems are typically supplied from the 115 kV transmission
system through one or more step-down transformers. Metering that measures
the total kilowatt hours flowing into each local distribution area at each
delivery point is on the low voltage side of the step-down transformers.
Attachment 1 illustrates a typical interface between the transmission and
distribution systems.
Boston Edison utilizes four types of common distribution systems for
delivery of energy at the retail level. All four types are served from the
115 kV transmission system through one or more step-down transformers. The
four types of distribution systems are:
1. Radial 4 kV or 14 kV distribution - radial distribution system serving
retail customers directly through their service transformers.
2. Primary Network - A system of 14 kV feeders supplying local Primary
Network Units consisting of 14/4 kV transformers which supply a network
of 4 kV distribution circuits. Each end of each 4 kV distribution
circuit is supplied from a different Primary Network Unit.
3. Secondary Network - A system of 14 kV feeders supplying transformers
stepping the voltage down to either (a) 120/208 v secondaries connected
in a network of secondary mains or to (b) 277/480 v secondaries
connected in a spot network supplying individual
<PAGE> 283
major customers. Boston Edison Company operates six major network
substations which each supply a different geographic area of the
downtown portion of the city of Boston.
4. Distribution System Supply Lines - A system of 14 kV or 24 kV feeders
supplying individual major customers at the 14 kV level or supplying
14 kV and 4 kV distribution substations.
Distribution circuits of Type 1 are radial by definition. Distribution
Systems Types 2 and 3, primary and secondary networks, involve local
networking at the low voltage level for the purposes of improving distribution
system reliability. Although power may be supplied from more than one
transmission/distribution interface, power flow is always into the geographic
area served by the distribution facilities. Distribution facilities are not
used to transmit bulk power from one geographic area to another. The power
is consumed within the distribution service area. The radial distribution
circuits often terminate at an open tie switch to an adjacent circuit.
However, opening or closing tie points on the distribution system has no
effect on the integrity or reliability of the bulk transmission system.
Attachment 2 is a list of Boston Edison Company transmission/
distribution interface points. This attachment identifies each supply point
by station number and location, transmission voltage, distribution voltage,
and the type of distribution system supplied from that location.
The distribution systems of the Boston Edison Company meet the seven
part test for distribution systems as described below:
<PAGE> 284
1. Local distribution facilities are in close proximity to retail
customers.
Boston Edison Company's distribution facilities are in close
proximity to retail customers, as these are the circuits that emanate
from local distribution substations and serve customers in a limited
geographical area. These circuits typically are installed overhead
or underground along public roads.
Attachment 3 shows an example of a radial 4 kV distribution
circuit. Attachment 4 is an example of a radial 14 kV distribution
circuit. A 14 kV distribution circuit typically covers a larger area
than a 4 kV circuit but is still local in nature.
Attachment 5 shows an example of the territory served by a
typical 4 kV distribution substation. This particular distribution
system serves customers in a portion of the Town of Framingham, plus
a small number of customers in several adjacent towns.
Boston Edison Company operates three separate 4 kV primary
networks located in Roxbury, Somerville and Brookline. Each of these
primary networks serve a separate geographic portion of these
communities. The company also operates six separate secondary networks
in the City of Boston. Each secondary network serves a different
geographic portion of the City. There are no electrical ties of
distribution voltage between secondary networks.
The 14 kV and 24 kV distribution system supply lines, which are
the fourth type of distribution system, emanate from a 115/14 kV or
115/24 kV step-down station and supply large, individual customers
directly at 14 kV or supply the Company's 14 kV or 4 kV distribution
substations. These distribution substations directly supply the local
area
<PAGE> 285
load. The Company operates more than 500 4 kV distribution circuits
and more than 200 14 kV distribution circuits directly serving retail
customers.
2. Local distribution facilities are primarily radial in character.
The distribution facilities of the Boston Edison Company are
primarily radial in character, and serve a limited area from one or
more transmission supply points. These facilities typically benefit
the local area, and do not affect the operation or integrity of the
transmission system other than as local load delivery points.
As mentioned earlier, radial 4 kV and 14 kV distribution
circuits are radial by definition but may have normally-open ties with
similar circuits. These tie points, along with switches embedded in
the bodies of these circuits, are either manually operated or radio
controlled and may be used to isolate portions of circuits and restore
service to customers in the event of an outage.
Primary networks consist of a set of 4 kV feeders which
collectively supply a single local area. There are often normally-open
tie switches to adjoining radial 4 kV circuits. The three Primary
Networks are supplied radially from 115/14 kV step-down stations.
Secondary networks consist of a set of 14 kV feeders from the
respective 115/14 kV step-down stations, which radially supply a single
local area. The downtown area of the City of Boston is divided into
six separate local secondary networks. Embedded into these secondary
networks are smaller spot networks which radially supply large,
individual customers. There are no ties between secondary networks
and between spot networks.
<PAGE> 286
The 14 kV and 24 kV distribution system supply lines perform two
functions. First, they are used to radially supply individual major
customers directly at 14 kV from the 115/14 kV step-down stations.
Generally, a large customer will be supplied by two or more 14 kV
feeders. The second feeder is often used to provide backup. The
second function of distribution system supply lines is to radially
supply 14/4 kV substations or local 14 kV distribution switching
substations. In this case, the 14/4 kV substations and the 14 kV
switching substations in turn radially supply 4 kV and 14 kV radial
distribution circuits which supply the local customers.
Attachments 6 through 20 show the 14 kV and 24 kV distribution
system supply feeders and a symbol sheet containing an explanation of
the devices shown in the system diagrams. Also shown on these diagrams
are the transmission interface substations and the 4 kV distribution
substations.
3. Power flows into local distribution systems; it rarely, if ever, flow
out.
Power flow is into a local distribution system, and is metered
at the transmission/distribution interface. More than one supply point
may exist. Because these systems are radial in nature, the net power
flow will be into the system to serve the local load. If generation
exists on the distribution system, separate billing metering facilities
would be located at the local generation facility. Attachment 21 shows
an example of where generation resides on a 14 kV distribution facility
which also provides service to retail customers. The generators are
shown as J1, J2, and J3 on Attachment 21.
4. When power enters a local distribution system, it is not re-consigned
or transported on to some other market.
<PAGE> 287
Boston Edison Company's distribution systems serve retail end-
use customers. In cases where distribution facilities are also used to
serve wholesale customers, that portion of the cost of those facilities
used for wholesale services would be assigned to the wholesale
transaction. Separate metering is located at the wholesale customer to
segregate wholesale deliveries from local distribution deliveries.
Attachment 22 shows an example where the wholesale customer, Wellesley
Municipal, is served from the 14 kV bus at Station 292, a 14 kV
distribution facility. The 14 kV bus also serves retail end-use
customers in the Newton/Needham area. The 14 kV feeders supplying
Wellesley Municipal are shown as lines 41-212 and 41-213 on Attachment
22.
5. Power entering a local distribution system is consumed in a
comparatively restricted geographical area.
Boston Edison Company's distribution systems serve load in a
comparatively restricted geographical area. The geographical area
served by a local distribution system depends on the load density of
the area. For example, more than one 14 kV radial distribution circuit
would normally be required to serve a small rural town. In general,
4 kV distribution circuits have lower capacity than 14 kV circuits:
therefore, a 4 kV circuit serves an even smaller geographical area.
As mentioned previously, each of the three primary networks serves a
fraction of one community. Each of the secondary networks serves
approximately one-sixth of the downtown Boston area.
6. Meters are based at the transmission/distribution interface to measure
flows in to the local distribution system.
<PAGE> 288
Metering to measure flows into the local distribution systems of
the Boston Edison Company is based on the low voltage side of the step-
down transformers. This metering is driven by relay accuracy
instrument transformers. These meter readings will be adjusted to
include the estimated losses in the step-down transformers. The
adjusted meter readings represent the flow from the transmission system
into the distribution system at the actual transmission/distribution
interface.
7. Local distribution systems will be of reduced voltage.
The local distribution voltages of the Boston Edison Company are
4 kV, 14 kV, and 24 kV. This compares to Boston Edison Company's
transmission system voltages of 115 kV, 230 kV and 345 kV.
<PAGE> 289
IV. Definition of the Boston Edison Company Transmission System
The function of transmission facilities is to integrate generation
resources over large geographical areas and deliver the power to local
distribution supply systems. The Boston Edison Company transmission system
is used to transmit power from generation resources located on its system or
on the transmission systems of others to the loads served by the distribution
system. The transmission system is interconnected in multiple locations to
the transmission systems of neighboring utilities. Transmission lines are not
directly connected to retail customers. The transmission system is defined as
the 115 kV and above transmission lines, the 115 kV circuit breakers, busses
and associated substation facilities, and the transformers which interconnect
the 115 kV, 230 kV, and 345 kV systems. The 115/14 kV and 115/24 kV step-down
transformers and associated 14 kV and 24 kV switchgear are considered to be
part of the distribution system.
<PAGE> 290
Attachments
-----------
Attachment 1 Typical Transmission/Distribution Interface
Attachment 2 List of Transmission/Distribution Interface points
Attachment 3 Example of a radial 4 kV distribution circuit
Attachment 4 Example of a radial 14 kV distribution circuit
Attachment 5 Map of service territory of a typical 4 kV distribution
substation
Attachment 6 System Diagram Symbol Sheet
Attachment 7 Edgar Area System Diagram
Attachment 8 Station 4 L Street Area South Boston System Diagram
Attachment 9 Walpole Area System Diagram
Attachment 10 Roslindale-Needham-Hyde Park Area System Diagram
Attachment 11 Brighton-Cambridge Area System Diagram
Attachment 12 Mystic Area System Diagram
Attachment 13 Medway-Framingham Area System Diagram
Attachment 14 Waltham Area System Diagram
Attachment 15 Lexington Area System Diagram
Attachment 16 Woburn Area System Diagram
Attachment 17 Watertown Area System Diagram
Attachment 18 Dorchester Area System Diagram
Attachment 19 Newton-West Roxbury Area System Diagram
Attachment 20 South Boston Area System Diagram
<PAGE> 291
Attachment 21 Example of wholesale generation on the distribution system
Attachment 22 Wellesley municipal supplied at 14 kV
<PAGE> 292
Attachment 1
Graph of Typical Boston Edison Company Transmission/Distribution Interface -
Illustrates:
Factor 6: Meters are based at the transmission/distribution interface to
measure flows in to the local distribution system.
Factor 7: Local distribution systems will be of reduced voltage.
<PAGE> 293
<TABLE>
Attachment 2
Boston Edison Company
---------------------
Transmission/Distribution Interface Points
------------------------------------------
<CAPTION>
Transmission Distribution Distribution
Station No. Station Address Voltage in kV Voltage in kV System Type(s)
- ----------- --------------- ------------- ------------- --------------
<S> <C> <C> <C> <C>
2 Hawkins Street, Boston 115 14 3
4 L Street, South Boston 115 14 1, 4
12 Chatham Street, Boston 115 14 3
20 Cecil Place, Dedham 24 14 1, 4
53 High Street, Boston 115 14 3
65 West Street, Medway 115 14 1, 4
71 Charles Street, Boston 115 14 3
75 Bridge Street, No. Weymouth 115 14 4
106 Andrew Square, South Boston 115 14 1, 2, 4
110 Baker Street, West Roxbury 115 24 4
132 Deer Island, Boston 115 14 4
146 South Street, Walpole 115 14 1, 4
148 Chestnut Street, Needham 115 14 1, 4
211 Cove Street, Woburn 115 14 1, 4
240 Leland Street, Framingham 115 14 1, 4
250 Alford Street, Boston 115 24, 14 1, 2, 4
274 Western Avenue, Sherborn 115 14 1, 4
282 Main Street, Waltham 115 14 1, 4
292 Elliot Street, Newton Highlands 115 14 1, 4
320 Off Marret Street, Lexington 115 14 1, 4
<PAGE> 294
Attachment 2
329 Lincoln Street, Brighton 115 24, 14 1, 2, 4
342 Off Boston Post Road, Sudbury 115 14 1, 4
375 Dragon Court, No. Woburn 115 14 1, 4
391 Middlesex Street, Burlington 115 14 1, 4
402 Prospect Street, Somerville 115 14 4
416 Old Mill Road, Maynard 115 14 1, 4
433 Speen Street, Framingham 115 14 1, 4
445 Crescent Avenue, Chelsea 24 14 1, 4
450 Trapelo Road, Waltham 115 14 1, 4
455 Off Worcester Road 115 14 1
West Framingham
456 County Street, Dover 115 14 1
467 Arsenal Street, Watertown 115 14 1, 4
470 Walpole Street, Canton 115 14 1, 4
483 Dewar Street, Dorchester 115 14 4
488 Willoughby Street, Chelsea 115 14 1, 4
492 Scotia Street, Boston 115 14 3, 4
496 Hyde Park Avenue, Hyde Park 115 14 1, 4
514 Kingston Street, Boston 115 14 3
533 Hartwell Avenue, Lexington 115 14 1, 4
</TABLE>
Distribution System Types:
1 Radial 4 kV or 14 kV
2 Primary Network (PNU)
3 Secondary Network
4 Distribution Supply System (DSS)
<PAGE> 295
Attachment 3
Graph of Circuit 2406 - Station 24 - Example of a radial 4 kV distribution
circuit
<PAGE> 296
Attachment 4
Graph of Circuit 292-H2 - Station 292 - Example of a radial 14 kV distribution
circuit
<PAGE> 297
Attachment 5
Graph of 24th Station Circuits - Map of service territory of a typical 4 kV
distribution substation
<PAGE> 298
Attachment 6
System Diagram Symbol Sheet - Symbols (1) - System Diagram Sheet 1 - 24 &
13.8kV (115kV in part) - Date: December 29, 1990
<PAGE> 299
Attachment 7
Graph of Edgar Area (3) - System Diagram Sheet 3 - 24 & 13.8kV (115kV in
part) - Date: January 6, 1995 - PRELIMINARY
<PAGE> 300
Attachment 8
Graph of Station 4, L Street Area, South Boston (4) - System Diagram Sheet 4 -
13.8kV (115kV in part) - Date: April 16, 1996
<PAGE> 301
Attachment 9
Graph of Walpole Area (5) - System Diagram Sheet 5 - 24 & 13.8kV (115kV in
part) - Date: February 19, 1992 - PRELIMINARY
<PAGE> 302
Attachment 10
Graph of Roslindale-Needham-Hyde Park Area (6) - System Diagram Sheet 6 -
24 & 13.8kV (115kV in part) - Date: February 19, 1992 - PRELIMINARY
<PAGE> 303
Attachment 11
Graph of Brighton-Cambridge Area (7) - System Diagram Sheet 7 - 24 & 13.8kV
(115kV in part) - Date: February 19, 1992 - PRELIMINARY - TEMPO - MAY 27,
1993
<PAGE> 304
Attachment 12
Graph of Mystic Area (8) - System Diagram Sheet 8 - 24 & 13.8kV (115kV in
part) - Date: February 19, 1992 - PRELIMINARY
<PAGE> 305
Attachment 13
Graph of Medway-Framingham Area (9) - System Diagram Sheet 9 - 24 & 13.8kV
115kV in part) - Date: February 19, 1992 - PRELIMINARY
<PAGE> 306
Attachment 14
Graph of Waltham Area (10) - System Diagram Sheet 10 - 24 & 13.8kV (115kV in
part) - Revised Date: May 11, 1995
<PAGE> 307
Attachment 15
Graph of Lexington Area (11) - System Diagram Sheet 11 - 24 & 13.8kV (115kV
in part) - Date: February 19, 1992 - PRELIMINARY
<PAGE> 308
Attachment 16
Graph of Woburn Area (12) - System Diagram Sheet 12 - 24 & 13.8kV (115kV in
part) - Date: May 11, 1995
<PAGE> 309
Attachment 17
Graph of Watertown Area (13) - System Diagram Sheet 13 - 24 & 13.8kV (115kV
in part) - Revised Date: May 11, 1995
<PAGE> 310
Attachment 18
Graph of Dorchester Area (14) - System Diagram Sheet 14 - 24 & 13.8kV (115kV
in part) - Date: May 11, 1995
<PAGE> 311
Attachment 19
Graph of Newton-West Roxbury Area (15) - System Diagram Sheet 15 - 24 &
13.8kV (115kV in part) - Date: May 11, 1995
<PAGE> 312
Attachment 20
Graph of South Boston (16) - System Diagram Sheet 16 - 24 & 13.8kV (115kV in
part) - Date: Sept. 27, 1995 - TEMPO
<PAGE> 313
Attachment 21
Graph of Station 240, Leland Street, Framingham, Framingham Ring (240) -
Date: April 22, 1996 - Example of wholesale generation on the distribution
system
<PAGE> 314
Attachment 22
Graph of Station 292, Elliot St. at B & A R.R., Newton Highlands (292) -
Date: June 17, 1996 - Wellesley municipal supplied at 14 kV
<TABLE>
Exhibit 12.1
Boston Edison Company
Computation of Ratio of Earnings to Fixed Charges
Year ended December 31, 1997
(in thousands)
<S> <C>
Net income from continuing operations $144,642
Income taxes 82,455
Fixed charges 116,258
--------
Total $343,355
========
Interest expense $106,899
Interest component of rentals 9,359
--------
Total $116,258
========
Ratio of earnings to fixed charges 2.95
====
</TABLE>
<TABLE>
Exhibit 12.2
Boston Edison Company
Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements
Year ended December 31, 1997
(in thousands)
<S> <C>
Net income from continuing operations $144,642
Income taxes 82,455
Fixed charges 116,258
--------
Total $343,355
========
Interest expense $106,899
Interest component of rentals 9,359
--------
Subtotal $116,258
--------
Preferred stock dividend requirements 20,642
--------
Total $136,900
========
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.51
====
</TABLE>
Exhibit 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration
statements of Boston Edison Company on Form S-3 (File Nos. 33-57840 and
33-59693) and on Form S-8 (File Nos. 33-00810, 33-7558, 33-38434, 33-48424,
33-48425, 33-59662, 33-59682 and 33-58457) and on Form S-4 (File No.
333-23439) of our report dated January 22, 1998 on our audits of the
consolidated financial statements of Boston Edison Company as of
December 31, 1997 and 1996 and for each of the three years in the period
ended December 31, 1997, which report is included in this Annual Report
on Form 10-K.
By: /s/ Coopers & Lybrand, L.L.P.
----------------------------------
Coopers & Lybrand, L.L.P.
Boston, Massachusetts
March 27, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,854,127
<OTHER-PROPERTY-AND-INVEST> 194,196
<TOTAL-CURRENT-ASSETS> 318,525
<TOTAL-DEFERRED-CHARGES> 255,499
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,622,347
<COMMON> 48,515
<CAPITAL-SURPLUS-PAID-IN> 696,137
<RETAINED-EARNINGS> 328,802
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,073,454
78,093
83,000
<LONG-TERM-DEBT-NET> 1,057,076
<SHORT-TERM-NOTES> 94,013
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 43,000
<LONG-TERM-DEBT-CURRENT-PORT> 100,667
2,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,091,044
<TOT-CAPITALIZATION-AND-LIAB> 3,622,347
<GROSS-OPERATING-REVENUE> 1,776,233
<INCOME-TAX-EXPENSE> 95,021
<OTHER-OPERATING-EXPENSES> 1,420,362
<TOTAL-OPERATING-EXPENSES> 1,515,383
<OPERATING-INCOME-LOSS> 260,850
<OTHER-INCOME-NET> (10,498)
<INCOME-BEFORE-INTEREST-EXPEN> 250,352
<TOTAL-INTEREST-EXPENSE> 105,710
<NET-INCOME> 144,642
13,149
<EARNINGS-AVAILABLE-FOR-COMM> 131,493
<COMMON-STOCK-DIVIDENDS> 91,208
<TOTAL-INTEREST-ON-BONDS> 3,280
<CASH-FLOW-OPERATIONS> 359,230
<EPS-PRIMARY> 2.71
<EPS-DILUTED> 2.71
</TABLE>
