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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)
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)
Registrant's telephone number, including area code: 617-424-2000
------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
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)
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.
Class Outstanding at March 24, 1998
-------------------------- -----------------------------
Common Stock, $1 par value 48,514,973 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part Document
- ---- --------
III Portions of definitive proxy statement dated March 31, 1998 for Annual
Meeting of Stockholders to be held May 5, 1998.
1
Boston Edison Company
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Form 10-K Annual Report
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December 31, 1997
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Part I Page
- -----------------------------------------------------------------------------
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
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:
1997 1996 1995
- ---------------------------------------------------------------------------
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%
===========================================================================
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:
Percentage of Company Average Cost of Fuel
Generation by Source (%) ($ per Million BTU)
-------------------------------- --------------------------------
1997 1996 1995 1994 1993 1997 1996 1995 1994 1993
- ------------------------------------------------------------------------------
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
==============================================================================
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
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.
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.
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:
(in thousands) 1998 1999 2000 2001 2002
- ------------------------------------------------------------------------------
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
==============================================================================
(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.
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:
Year
Unit Location Capacity(a) Type Installed
- ------------------------------------------------------------------------------
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)
==============================================================================
(a) In megawatts (MW) based on winter capability audit results.
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.
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.
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.
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
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)
10
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
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
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:
1997 1996
- ------------------------------------------------------------------------------
High Low High Low
- ------------------------------------------------------------------------------
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
==============================================================================
(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:
1997 1996
- -----------------------------------------------------------
First quarter $0.470 $0.470
Second quarter $0.470 $0.470
Third quarter $0.470 $0.470
Fourth quarter $0.470 $0.470
===========================================================
(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:
Ratio of earnings to fixed charges 2.95
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.51
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).
1997 1996 1995 1994 1993
- -----------------------------------------------------------------------------
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
=============================================================================
(a) Includes $0.44 per share restructuring charge. Excluding the
restructuring charge, 1995 earnings per share were $2.52.
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.
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
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:
(in thousands)
- ------------------------------------------------------
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
======================================================
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
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
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:
(in thousands)
- ------------------------------------------------------
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
======================================================
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
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
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.
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.
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
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
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.
24
Item 8. Financial Statements and Supplementary Financial Information
- ---------------------------------------------------------------------
Consolidated Statements of Income
years ended December 31,
(in thousands, except earnings per share) 1997 1996 1995
- ---------------------------------------------------------------------------
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
===========================================================================
Consolidated Statements of Retained Earnings
years ended December 31,
(in thousands) 1997 1996 1995
- ---------------------------------------------------------------------------
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
===========================================================================
(a) Refer to Note B.7. to the Consolidated Financial Statements.
The accompanying notes are an integral part of the consolidated financial
statements.
25
Consolidated Balance Sheets
December 31,
(in thousands) 1997 1996
- ------------------------------------------------------------------------------
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
==============================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
26
Consolidated Statements of Cash Flows
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
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
The accompanying notes are an integral part of the consolidated financial
statements.
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
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
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.
30
Regulatory assets consisted of the following:
December 31,
1997 1996
- --------------------------------------------------------------------
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
====================================================================
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
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
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.
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:
December 31,
(in thousands) 1997 1996
- ------------------------------------------------------------------------------
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
==============================================================================
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:
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
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
=============================================================================
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:
1997 1996 1995
- -----------------------------------------------------------------------------
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%
=============================================================================
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
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.
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.
37
Net pension cost consisted of the following components:
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
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
=============================================================================
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:
1997 1996 1995
- -----------------------------------------------------------------------------
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%
- -----------------------------------------------------------------------------
38
The plans' funded status were as follows:
December 31,
(in thousands) 1997 1996
- -----------------------------------------------------------------------------
Supplemental Supplemental
Retirement Retirement Retirement Retirement
Plan Plan Plan Plan
- -----------------------------------------------------------------------------
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)
=============================================================================
(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.
We used the following assumptions for calculating the plans' year-end funded
status:
1997 1996
- -----------------------------------------------------------------------------
Discount rate 7.25% 7.75%
Compensation increase rate 4.25% 3.90%
- -----------------------------------------------------------------------------
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
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:
years ended December 31,
(in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
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
=============================================================================
We used the following assumptions for calculating postretirement benefits
cost:
1997 1996 1995
- -----------------------------------------------------------------------------
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%
- -----------------------------------------------------------------------------
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%.
40
The PBOP program's funded status was as follows:
December 31,
(in thousands) 1997 1996
- -----------------------------------------------------------------------------
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)
=============================================================================
(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.
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:
(in thousands, except per share amounts) 1997
- ---------------------------------------------------
Net income
Actual $144,642
Pro forma $144,572
Earnings per share
Actual $2.71
Pro forma $2.71
41
Stock option activity of the Plan was as follows:
- ---------------------------------------------------------------------------
Options outstanding at January 1, 1997 0
Options granted 298,400
Options forfeited (25,400)
- ---------------------------------------------------------------------------
Options outstanding at December 31, 1997 273,000
===========================================================================
Summarized information regarding stock options outstanding at December 31,
1997:
Weighted
Range of Average Remaining Weighted Average
Exercise Prices Contractual Life (Years) Exercise Price
- --------------- ------------------------ ----------------
$25.75-$26.00 9.44 $25.84
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:
Expected life (years) 4.0
Risk-free interest rate 6.44%
Volatility 16%
Dividends 7.28%
Compensation cost recognized in income for our stock-based compensation awards
in 1997 was $275,000.
42
Note I. Capital Stock
December 31,
(dollars in thousands, except per share amounts) 1997 1996
- -----------------------------------------------------------------------------
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
=============================================================================
Dividends declared per share of common stock were $1.88 in 1997 and 1996 and
$1.835 in 1995.
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares
authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
- -----------------------------------------------------------------------------
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
=============================================================================
Mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
- -----------------------------------------------------------------------------
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
=============================================================================
1. Common Stock
Common stock issuances in 1995 through 1997 were as follows:
Number Total Premium on
(in thousands) of Shares Par Value Common Stock
- -----------------------------------------------------------------------------
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
=============================================================================
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
December 31,
(in thousands) 1997 1996
- -----------------------------------------------------------------------------
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
=============================================================================
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:
(dollars in thousands) 1997 1996 1995
- -----------------------------------------------------------------------------
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%
- -----------------------------------------------------------------------------
In addition, at December 31, 1997, BETG had $7.5 million outstanding under a
revolving credit agreement.
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:
Carrying Fair
(in thousands) Amount Value
- ------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------
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:
(in thousands)
- ------------------------------------------------------
1998 $ 21,938
1999 18,958
2000 16,738
2001 12,356
2002 11,194
Years thereafter 91,874
- ------------------------------------------------------
Total $173,058
======================================================
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
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.
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.
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.
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:
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
- ------------------------------------------------------------------------------
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
==============================================================================
(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.
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:
(in thousands)
- ------------------------------------------------------
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
======================================================
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:
Contract Units of Capacity Sold
Expiration ----------------------
Contract Customer Date % MW
- ------------------------------------------------------------------------------
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
==============================================================================
(a) Subject to certain adjustments.
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.
51
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
Earnings
Available Earnings
Operating Operating Net for Common Per Average
Revenues Income Income Shareholders Common Share(a)
- ----------------------------------------------------------------------------
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
(a) Based on the weighted average number of common shares outstanding during
each quarter.
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure
- --------------------
Not applicable.
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.
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.
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:
1. Financial Statements:
Page
----
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
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.
55
Exhibit SEC Docket
------- ----------
Exhibit 3 Articles of Incorporation and By-Laws
- --------- -------------------------------------
Incorporated herein by reference:
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
56
Exhibit SEC Docket
------- ----------
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
57
Exhibit SEC Docket
------- ----------
Filed herewith:
4.1.4.2 Second Amendment to Revolving Credit
Agreement dated July 1, 1997
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.
Exhibit SEC Docket
------- ----------
Exhibit 10 Material Contracts
- ---------- ------------------
Incorporated herein by reference:
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
58
Exhibit SEC Docket
------- ----------
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
59
Exhibit SEC Docket
------- ----------
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
60
Exhibit SEC Docket
------- ----------
Exhibit 12 Statement re Computation of Ratios
- ---------- ----------------------------------
Filed herewith:
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
61
Exhibit SEC Docket
------- ----------
Exhibit 23 Consent of Independent Accountants
- ---------- ----------------------------------
Filed herewith:
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
62
Exhibit SEC Docket
------- ----------
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
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.
/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
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
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