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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, 1996
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)
8.25% 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 21, 1997 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: $1,261,389,298.
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 21, 1997
-------------------------- -----------------------------
Common Stock, $1 par value 48,514,973 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part Document
- ---- --------
III Portions of definitive proxy statement dated March 26, 1997 for Annual
Meeting of Stockholders to be held May 15, 1997.
1
Boston Edison Company
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Form 10-K Annual Report
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December 31, 1996
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Part I Page
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Item 1. Business 2
Item 2. Properties and Power Supply 7
Item 3. Legal Proceedings 9
Item 4. Submission of Matters to a Vote of Security Holders 9
Part II
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Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 13
Item 6. Selected Financial Data 14
Item 7. Management's Discussion and Analysis 15
Item 8. Financial Statements and Supplementary Financial
Information 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 51
Part III
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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 and energy services 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 Positioning in the Industry section of Item 7 for information
regarding the restructuring of the electric utility industry process currently
underway and its potential impacts 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.
In January 1997, the Company announced a plan to form a holding company
structure. The holding company structure, which is subject to shareholder and
regulatory approvals, is further described in Note A to the Consolidated
Financial Statements in Item 8.
(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 1996 the Company served an average of 657,487 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:
1996 1995 1994
- ---------------------------------------------------------------------------
Retail electric revenues:
Commercial 50% 50% 50%
Residential 27% 28% 28%
Industrial 9% 9% 9%
Other 2% 2% 2%
Wholesale and contract revenues 12% 11% 11%
===========================================================================
3
Sources and Availability of Fuel
The Company 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. 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)
-------------------------------- --------------------------------
1996 1995 1994 1993 1992 1996 1995 1994 1993 1992
- ------------------------------------------------------------------------------
Oil 16.1 17.5 27.8 31.3 33.7 3.04 2.66 2.35 2.38 2.40
Gas 33.3 39.9 31.6 24.3 25.7 3.11 2.20 2.28 2.67 2.55
Nuclear 50.6 42.6 40.6 44.4 40.6 0.41 0.43 0.50 0.51 0.52
==============================================================================
The majority of the Company's residual oil purchases consists of imported oil
acquired primarily from international suppliers. The Company has contracts
with major oil companies that can supply most of its estimated requirements,
assuming no major disruptions in oil producing regions. Within contract
provisions, the Company has the ability to purchase significant amounts of oil
in the spot market when it is economical to do so.
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 Massachusetts Department of Public Utilities (MDPU).
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.
4
Seasonal Nature of Business
The Company's 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 currently bills higher base rates to
commercial and industrial customers during the billing months of June through
September as mandated by the MDPU. Accordingly, greater than half of the
Company's annual earnings typically occurs in the third quarter. As part of
the Company's settlement agreement which is discussed in the Positioning in
the Industry section of Item 7, it is expected that the seasonal variances of
the Company's rates will be discontinued. Refer also to the Selected
Consolidated Quarterly Financial Data (Unaudited) in Item 8.
Competitive Conditions
The Company is operating in an increasingly competitive environment. Changes
in the industry include ongoing competition in wholesale power markets and
increased pressure for retail customer choice. These forces are due to a
variety of factors, including legislative and regulatory proceedings at both
federal and state levels designed to foster competition and changes in
customers expectations. Refer to the Positioning in the Industry and Outlook
for the Future sections of Item 7 for information regarding electric utility
industry restructuring and the Company's response to the competitive
environment.
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 1996 and 1995 were
$2.7 million and $2.9 million, respectively. These expenditures are
forecasted to be approximately $2 million in each of the years 1997 and 1998.
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 22, 1997, the Company had 3,323 full-time and 44 part-time utility
employees including 2,260 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. Subsidiary operations had 54 full-time employees.
Employee relations are considered satisfactory by the Company.
5
(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.
(e) Additional Information
- --------------------------
Regulation
The Company and its wholly owned subsidiary, Harbor Electric Energy Company
(HEEC), operate primarily under the authority of the MDPU, whose jurisdiction
includes supervision over retail rates for electricity and financing and
investing activities. In addition, the Federal Energy Regulatory Commission
(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 Company is required to submit annual performance standards to the MDPU
applicable to its generating units and other units from which the Company
purchases power through long-term contracts. Under this generating unit
performance program, the Company provides quarterly progress reports to the
MDPU. The MDPU has the right to reduce subsequent fuel and purchased power
billings if it finds that the Company has been unreasonable or imprudent in
the operation of its generating units or in the procurement of fuel. The
Company believes that its current provision for refunds is sufficient to cover
potential refunds.
The Nuclear Regulatory Commission (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 January 1997, the Company
submitted a request for NRC review regarding the calculation of Pilgrim's
emergency core cooling system net postive suction head. NRC practice will not
allow the plant to restart until this review is performed. The Company
anticipates that the review will be completed prior to the completion of
Pilgrim's current refueling and maintenance outage. The unit is currently
expected to return to service in late April.
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
6
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 and believes that such
continued operation is in the best interests of the Company and its customers.
Capital Expenditures and Financings
The Company's most recent estimates of capital and nuclear fuel expenditures,
allowance for funds used during construction (AFUDC), long-term debt
maturities and sinking fund requirements for the years 1997 through 2001 are
as follows:
(in thousands) 1997 1998 1999 2000 2001
- ------------------------------------------------------------------------------
Capital
expenditures (1) $140,000 $150,000 $160,000 $160,000 $140,000
Nuclear fuel
expenditures 0 $ 29,500 $ 14,000 $ 33,000 $ 16,000
AFUDC (2) $ 2,000 $ 2,000 $ 2,000 $ 2,000 $ 2,000
Long-term debt $101,600 $101,600 $ 1,600 $166,600 $ 1,600
Preferred stock
sinking fund $ 2,000 $ 2,000 $ 2,000 $ 2,000 $ 52,000
==============================================================================
(1) Includes unregulated business ventures.
(2) Excludes AFUDC on nuclear fuel.
The Company continuously reviews its capital expenditure and financing
programs. These programs and, therefore, the estimates shown above are
subject to revision due to changes in regulatory requirements and the effects
of the industry restructuring process, environmental standards, availability
and cost of capital, interest rates and other assumptions.
Utility plant expenditures in 1996 were $151 million and consisted primarily
of additions to the Company's transmission and distribution systems and
nuclear generation facility.
Refer to the Liquidity section of Item 7 for more information regarding the
Company's capital resources.
7
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. 730 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 278 Fossil 1966-1971
generators (nine)
=============================================================================
(a) In megawatts (MW) based on winter capability audit results.
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.
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, 1996, 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), 63 4 kV distribution substations with transformer
capacity of 1,205 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
8
policies. The Company currently has one proceeding before the EFSB, which
concerns proposed transmission and station facilities in Hopkinton and
Milford, Massachusetts.
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.
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 fixed and
operating costs plus 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 operated by NEPOOL 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. This operation is the responsibility of NEPOOL's central dispatch
center, the New England Power Exchange (NEPEX). 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. The
dispatching of Company-owned generating facilities by NEPEX may be affected by
minimally increasing energy requirements and any additions to New England
generation capacity.
In December 1996, NEPOOL filed with the FERC to restructure the power pool to
comply with recent FERC orders requiring open access to transmission and
changes to the membership and governance provisions of the power pooling
agreement. The filing also proposed changes which would transfer operating
responsibility of the integrated transmission and generation system in New
England to an Independent System Operator and establish a bid-based market for
unbundled energy services in lieu of the current cost-based pricing mechanism.
The FERC has allowed the transmission and governance changes to become
effective March 1, 1997, subject to refund and further orders. NEPOOL
proposed that the changes in operations responsibility and market-based
pricing would become effective in the second half of 1997. These changes were
proposed in anticipation of the restructuring of the electric utility industry
and the entrance of new providers in the energy market.
The Company's net capacity was 3,613 MW at its winter peak and 3,385 MW at its
summer peak. Its corresponding NEPOOL capacity obligations were estimated to
be 3,399 MW and 3,256 MW, respectively.
9
Item 3. Legal Proceedings
- --------------------------
The Company was named as a party in lawsuits filed in both the US District
Court and the Massachusetts Norfolk Superior Court by Subaru of New England,
Inc. and Subaru Distributors Corporation in 1992. The plaintiffs claimed
certain automobiles stored on lots in South Boston suffered pitting damage
caused by emissions from the Company's New Boston generating station. In
February 1997, the Company settled the lawsuit brought by Subaru Distributors
Corporation. The settlement did not have a material impact on the Company's
financial position or results of operations. The Subaru of New England, Inc.
lawsuit is still pending.
In 1991 the Company was named in a lawsuit brought in the United States
District Court for the District of Massachusetts (US District Court) alleging
discriminatory employment practices under the Age Discrimination in Employment
Act of 1967 concerning employees affected by the Company's 1988 workforce
reduction. In December 1996, the Company reached a settlement of this lawsuit
under which there is no finding or admission of discriminatory employment
practices. The Company anticipates full recovery from its insurance carrier
for this settlement.
Also refer to Note L.6. to the Consolidated Financial Statements in Item 8 for
a discussion of legal issues involving hazardous waste sites.
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 1996.
10
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, 1997 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, 49 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 (1990-
1993); Director (since 1991)
Chairman of the Board and Chief
Executive Officer and Director,
Harbor Electric Energy Company,
Boston Energy Technology Group,
TravElectric Services Corp. and
Boston Edison Services, Inc.;
Chairman of the Board and
Director, Rez-Tek International
Corp. and Coneco Corp.; Director,
BecoCom, Inc. and Northwind
Boston, LLC
Alison Alden, 48 Senior Vice President - Sales,
Senior Vice President - Sales, Services Services and Human Resources
and Human Resources (since 1996), Vice President -
Sales & Service (1993-1996) and
Director - Organizational
Development (1990-1993)
Director, Harbor Electric Energy
Company, Boston Energy Technology
Group and Coneco Corp.
E. Thomas Boulette, 54 Senior Vice President - Nuclear
Senior Vice President - Nuclear (since 1993), Vice President -
Nuclear Operations and Station
Director (1992-1993) and Vice
President - Operations (1989-
1992) of Maine Yankee Atomic
Power Company
11
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
L. Carl Gustin, 53 Senior Vice President - Corporate
Senior Vice President - Corporate Relations (since 1995), Senior
Relations Vice President - Marketing &
Corporate Relations (1989-1995)
John J. Higgins, Jr., 64 Senior Vice President (since 1990)
Senior Vice President
Douglas S. Horan, 47 Senior Vice President and General
Senior Vice President and Counsel (since 1995), Vice
General Counsel President and General Counsel
(1994-1995) and Deputy General
Counsel (1991-1994)
Director and General Counsel,
Harbor Electric Energy Company;
Director, Boston Energy Technology
Group and BecoCom, Inc.
James J. Judge, 41 Senior Vice President and
Senior Vice President and Treasurer (since 1995), Assistant
Treasurer Treasurer (1989-1995) and
Director - Corporate Planning
(1993-1995)
Senior Vice President, Treasurer
and Director, Harbor Electric
Energy Company and Boston Energy
Technology Group; Director,
TravElectric Services Corp.,
Boston Edison Services, Inc.,
BecoCom, Inc., Northwind Boston,
LLC and EnergyVision, LLC
Ronald A. Ledgett, 58 Senior Vice President - Fossil,
Senior Vice President - Fossil, Field Service and Electric
Field Service and Electric Delivery (since 1996), Senior Vice
Delivery President - Power Delivery (1991-
1995)
Robert J. Weafer, Jr., 50 Vice President - Finance,
Vice President - Finance, Controller and Chief Accounting
Controller and Chief Officer (since 1991)
Accounting Officer
12
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
Theodora S. Convisser, 49 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, TravElectric Services
Corp., Boston Edison Services,
Inc., Rez-Tek International Corp.,
Coneco Corp., BecoCom, Inc. and
Northwind Boston, LLC
13
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.
Following is 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 1996
and 1995:
1996 1995
- ------------------------------------------------------------------------------
High Low High Low
- ------------------------------------------------------------------------------
First quarter $30 1/8 $26 1/4 $25 1/2 $23 1/8
Second quarter $27 1/8 $23 5/8 $27 $23 3/8
Third quarter $25 3/8 $21 3/4 $27 1/2 $24 1/2
Fourth quarter $27 $21 3/4 $29 1/2 $26 3/4
==============================================================================
(b) Holders
- -----------
As of March 21, 1997, the Company had 35,630 holders of record of its common
stock.
(c) Dividends
- -------------
Following are the dividends declared per share of common stock for each of the
quarters in 1996 and 1995:
1996 1995
- -----------------------------------------------------------
First quarter $0.470 $0.455
Second quarter $0.470 $0.455
Third quarter $0.470 $0.455
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, 1996:
Ratio of earnings to fixed charges 2.91
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.41
14
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).
1996 1995 1994 1993 1992
- ---------------------------------------------------------------------------
Operating
revenues $1,666,303 $1,628,503 $1,544,735 $1,482,159 $1,411,753
Net income $ 141,546 $ 112,310 $ 125,022 $ 118,218 $ 107,298
Earnings per
share of
common
stock $ 2.61 $ 2.08(a) $ 2.41 $ 2.28 $ 2.10
Total
assets $3,729,291 $3,637,170 $3,608,699 $3,468,724 $3,286,335
Long-term
debt $1,058,644 $1,160,223 $1,136,617 $1,272,497 $1,091,073
Redeemable
preferred
stock $ 203,419 $ 206,514 $ 208,514 $ 210,514 $ 210,514
Cash
dividends
declared
per common
share $ 1.880 $ 1.835 $ 1.775 $ 1.715 $ 1.655
===========================================================================
(a) Includes $0.44 per share restructuring charge. Excluding the
restructuring charge, 1995 earnings per share were $2.52.
Certain reclassifications were made to the data reported in prior years to
conform with the current method of presentation.
15
Item 7. Management's Discussion and Analysis
- ---------------------------------------------
Positioning in the Industry
Background
Electric utilities have traditionally operated under a monopolistic regulatory
framework. Under this framework customers have been restricted to a single
electricity provider, typically a vertically integrated electric utility
engaged in the generation, transmission and distribution of electricity.
However, since the 1970's, the electric energy business has become
increasingly competitive. With the enactment of the Public Utility Regulatory
Policies Act of 1978, a new independent power producer industry commenced,
competing with traditional electric utilities for opportunities to generate
electric power. In recent years many state utility commissions, including the
Massachusetts Department of Public Utilities (MDPU), have initiated inquiries
into restructuring the electric utility industry with a goal of promoting
competition and extending to all customers the option of choosing their own
electricity suppliers. In 1996, Massachusetts electric utilities and other
interested parties participated in the industry restructuring proceeding
before the MDPU. This process culminated in the latter part of the year with
a series of settlement agreements and the issuance by the MDPU of its formal
electric industry restructuring plan.
Electric utility industry restructuring
In December 1996, we reached a settlement agreement with the Massachusetts
Attorney General and the Massachusetts Division of Energy Resources that
resolves certain necessary issues surrounding electric industry restructuring.
This agreement must be filed with and approved by the MDPU. If approved, the
settlement agreement allows retail electric customers the ability to choose
their electricity supplier (referred to as retail access). Retail access
would occur at the later of January 1, 1998 or the date when retail access is
made available to all customers of Massachusetts investor-owned utilities (the
Retail Access Date). The settlement agreement provides us with the ability to
fully recover our stranded costs incurred under the traditional electric
ratemaking structure.
Under the settlement agreement, all retail customers will have the opportunity
to select their electricity provider starting on the Retail Access Date.
Retail customers will continue to receive electric delivery service under
regulated rates. Customers who choose not to participate in the competitive
market will have the option of continuing to buy power from our electric
delivery business at "Standard Offer" prices for seven years. The "Standard
Offer" will provide customers with electric service at rates designed to give
a 10% savings in electric prices. Our electric delivery business will
purchase power for "Standard Offer" service from suppliers through a
competitive bidding process.
Commencing with the Retail Access Date, the retail delivery rates of our
distribution business will include a non-bypassable access charge designed to
recover all of our stranded costs which are currently estimated to be
approximately $3 billion. These costs include the above-market commitments
under existing purchased power contracts, our net generation plant investment,
nuclear decommissioning commitments and regulatory assets related to our
generation business.
16
As part of the settlement we have agreed to divest our fossil generating
plants no later than six months after the Retail Access Date. We expect to
continue operation of Pilgrim Nuclear Power Station with a new revenue
mechanism for recovery of Pilgrim's future costs and have agreed to estimate
the market value of the station by December 31, 2002.
Regulatory assets related to our generation business and our net generation
plant investment will be recovered with a return over a twelve-year period.
As an incentive to mitigate stranded costs, our return on equity will be
increased for mitigation prior to the Retail Access Date and as the transition
access charge declines thereafter. The aggregate amount of the access charge
will be reduced by the net proceeds from the fossil divestiture and the market
valuation of Pilgrim Station. Nuclear decommissioning commitments and
above-market commitments under existing purchased power contracts will be
collected over the lives of the underlying obligations which are expected to
exceed twelve years. Certain severance, employee training and community-
related transitional payments are also recoverable through the access charge.
Our electric delivery business will remain fully subject to rate regulation.
As part of the agreement, while there will be some rate design changes, our
base rate revenue level (non-fuel) will be frozen until the Retail Access Date
when customer choice begins.
Effective with the commencement of retail choice and pursuant to the
settlement agreement, our electric delivery business will annually file with
the MDPU a computation supporting our return on average common equity
associated with distribution system operations. The return on equity would be
subject to a floor of 6% and a ceiling of 11.75%. If the return on equity is
below 6%, we would be authorized to add a surcharge to customer rates in order
to reach the 6% floor. If the return on equity is above 11%, we would be
required to adjust customer rates by an amount necessary to reduce the
calculated return on equity between 11% and 12.5% by 50%, and a return above
12.5% by 100%. No adjustment would be made if the return on equity falls
between 6% and 11%.
The settlement also provides for the continued protection of the environment
through stringent emissions standards, a continued commitment to energy
conservation and renewable resource programs and protections for low-income
customers.
In October 1996, another major electric utility in Massachusetts, along with
the Massachusetts Attorney General, the Massachusetts Division of Energy
Resources and other parties filed a settlement agreement with the MDPU. Their
settlement agreement provides for retail choice, full compensation for
potential stranded costs and the divestiture of its fossil and hydroelectric
generating business. In addition, customers that do not choose an alternative
supplier would receive "Standard Offer" service that would provide a 10%
savings in electric prices upon the Retail Access Date. On February 26, 1997,
the MDPU issued an order accepting this utility's settlement agreement.
We anticipate that the MDPU will issue a decision on our settlement agreement
in the second or third quarter of 1997. Implementation of the settlement will
also be subject to enactment of enabling legislation by the Massachusetts
legislature and rulings by the Federal Energy Regulatory Commission (FERC).
In the first quarter of 1997, both the Massachusetts Governor and a Joint
Committee of the Massachusetts legislature filed separate bills on
restructuring the electric utility industry. The major principles of these
bills are substantially consistent with those of the MDPU restructuring plan,
including the opportunity for stranded cost recovery and reduced electricity
17
prices. The bills clarify the MDPU's authority to create the opportunity for
retail customer choice by January 1, 1998.
In December 1996, the MDPU issued its formal electric industry restructuring
plan. The stated goal of the plan is to reduce costs, over time, for all
consumers of electricity. Under the MDPU's proposal, the current monopoly
regulatory framework will evolve into a competitive market system featuring
consumer choice among providers of generation services. The transmission and
distribution of electricity will remain monopolies subject to rate regulation.
Joint ventures
We currently conduct unregulated activities through our wholly owned
subsidiary, Boston Energy Technology Group (BETG). In December 1996, BETG
signed a joint venture agreement with Residential Communications Network,
Inc., currently known as RCN Telecom Services, Inc. (RCN), to form a limited
liability company to provide local and long-distance telephone service, video,
high-speed Internet access and other telecommunications-related services (the
"Telecommunications Venture"). The unregulated entity will be owned up to 49%
by BETG, with RCN having the day-to-day management responsibility. The
projected costs of creating the "Telecommunications Venture", which is planned
to serve 1.6 million customers in the greater Boston area, is approximately
$300 million over several years. The joint venture agreement is subject to a
number of conditions which must be satisfied before formal operations begin,
including the obtaining of certain regulatory approvals.
In January 1997, BETG, through one of its wholly owned subsidiaries, signed
definitive agreements with Williams Energy Services Company (WESCO), a
subsidiary of The Williams Companies, Inc., to form EnergyVision, LLC, an
unregulated limited liability company. This "Energy Marketing Venture" will
market electricity, natural gas and energy-related services to retail
customers in the six New England states. EnergyVision began operations in
February 1997. BETG, through its subsidiary, and WESCO each own 50% of the
new company, with an expected combined initial investment of less than $10
million.
Holding Company
In January 1997, we announced a plan to form a holding company structure. The
holding company structure, which is subject to shareholder and regulatory
approvals, is intended to provide increased financial, managerial and
organizational flexibility in order to better position us to operate in the
changing electric utility industry. It will permit us to take advantage of
nonutility business opportunities in a more timely manner. In addition, the
holding company structure will clearly separate our regulated and unregulated
lines of business enabling us to pursue nonutility business ventures in a
manner consistent with the electric utility industry restructuring principles
outlined by the MDPU. The holding company structure is a well-established
form of organization for companies conducting multiple lines of business,
particularly entities engaging in both regulated and unregulated activities.
All investor-owned Massachusetts electric utilities, other than Boston Edison,
are currently organized in a holding company structure.
1992 Rate Settlement
As referred to in the following Results of Operations, the MDPU had previously
approved our three-year settlement agreement effective November 1992. This
agreement provided us with retail rate increases, allowed for the recovery of
demand side management conservation program costs, specified certain
18
accounting adjustments and clarified the timing and recognition of certain
expenses. The agreement also set a limit of 11.75% on our rate of return on
common equity for each of the calendar years 1993, 1994 and 1995, excluding
any penalties or rewards from performance incentives. The retail rate
increases consisted of two annual retail base rate increases of $29 million
effective November 1993 and November 1994 and an annual performance adjustment
charge effective November 1992 through October 2000. The performance
adjustment charge varies annually based on the performance of Pilgrim Nuclear
Power Station. This charge is further described in the Electric Sales and
Revenues section. We did not make a base rate filing upon the expiration of
the 1992 settlement agreement, therefore base rates have remained in effect at
their 1995 levels.
Results of Operations
1996 versus 1995
Earnings per share of common stock were $2.61 in 1996 compared to $2.08 in
1995. Earnings in 1995 reflected a nonrecurring before tax charge of $34
million ($20.7 million net of 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
primarily due to lower operations and maintenance and interest expenses and
higher Pilgrim performance revenues. These positive changes were partially
offset by an increase in depreciation expense.
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
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, which vary annually based on the
operating performance of Pilgrim Station, increased $14.5 million as Pilgrim
Station operated at a higher capacity in 1996. Pilgrim's annual performance
adjustment charge is discussed further in the Electric Sales and Revenues
section. 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 a decrease
in Pilgrim contract customer revenues. These revenues decreased despite
increased kWh sales due to lower operations and maintenance expense related to
Pilgrim 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
19
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 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 collection. Fuel and purchased power expenses are
substantially recoverable through fuel and purchased power revenues.
Operations and maintenance expense decreased $41 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 the Results of Operations for 1995
versus 1994 and Note F to the Consolidated Financial Statements for additional
information regarding our 1995 restructuring.
Depreciation and amortization increased $32 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.
Refer to Note B to the Consolidated Financial Statements for more information
on depreciation expense.
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. Our 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. Allowance for borrowed funds used during
construction (AFUDC), which represents the financing costs of construction,
decreased due to lower overall construction activity during 1996, shorter
construction periods, and lower short-term interest rates
20
1995 versus 1994
Earnings per share of common stock were $2.08 in 1995 compared to $2.41 in
1994. Earnings in 1995 reflect the nonrecurring before tax charge of $34
million ($20.7 million net of tax, or $0.44 per share) associated with our
corporate restructuring. The charge reflects the costs of early retirement
and severance programs implemented as part of our organizational streamlining
and reorganization into business units. Excluding the restructuring charge,
earnings per common share were $2.52 in 1995, an increase of 4.6% over 1994.
This increase is due to the $29 million annual retail base rate increase
effective November 1994, the ending of amortization of deferred cancelled
nuclear costs in 1994, a 1.2% increase in retail kWh sales and lower revenue
reserve provisions. These positive impacts were partially offset by higher
income and property taxes, nuclear outage amortization and employee benefit
expenses in 1995 over 1994 levels, and a gain recorded in 1994 related to a
favorable court ruling on an eminent domain case.
Operating revenues
Operating revenues increased 5.4% over 1994 as follows:
(in thousands)
- ------------------------------------------------------
Retail electric revenues $69,851
Demand side management revenues 8,783
Wholesale revenues (1,799)
Short-term sales and other revenues 6,933
- ------------------------------------------------------
Increase in operating revenues $83,768
======================================================
Retail electric revenues increased $69.9 million. Approximately $28 million
of the increase was due to the November 1994 base rate increase while
approximately $11 million was due to the increase in retail kWh sales. Fuel
and purchased power revenues increased $11 million as a result of the timing
effect of fuel and purchased power cost recovery. These higher revenues are
offset by higher fuel and purchased power expenses and, therefore, have no net
effect on earnings. Pilgrim performance revenues increased $9 million
primarily due to a higher performance rate effective in 1995 and a 17%
increase in generation.
A new annual conservation charge for recovery of demand side management
program costs was implemented in February 1995. Under this charge all 1995
program costs were recovered in 1995. This resulted in higher DSM revenues
and expenses than in prior years when certain program costs were deferred and
recovered over a six-year period.
Short-term sales increased as a result of higher generating availability in
1995. 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 $22 million primarily due to the
timing effect of fuel and purchased power cost collection. Excluding the
timing effect, fuel expense increased due to an 8% increase in fossil
generation while purchased power expense was substantially unchanged. Fuel
and purchased power expenses are substantially recoverable through fuel and
purchased power revenues.
21
Operations and maintenance expense increased 3.3% over 1994. This was
primarily due to an $11 million increase in the amortization of deferred
nuclear outage costs. In the third quarter of 1995 we made a retroactive
change to the amortization period of deferred nuclear outage costs from five
years to two years as discussed in Note B to the Consolidated Financial
Statements. In addition, employee benefit expenses increased primarily due to
higher postretirement benefit expenses recorded in accordance with the 1992
settlement agreement. We also incurred higher administrative costs in
positioning the company for changes in the industry, which were offset by
lower operating costs in the electric delivery business. Electric generation
costs increased only 1% in 1995, primarily due to a refueling and maintenance
outage at Pilgrim Station.
The $34 million nonrecurring restructuring charge was incurred over the third
and fourth quarters of 1995 as a result of our corporate reorganization
announced in July 1995. As part of the reorganization, 330 employees elected
to retire under enhanced retirement programs and 149 employees whose positions
were eliminated became eligible for benefits under a special severance
program. Refer to Note F to the Consolidated Financial Statements for
additional information.
Depreciation and amortization expense increased due to a higher average
depreciable plant balance.
In 1994 we fully expensed the remaining deferred costs of the cancelled
Pilgrim 2 nuclear unit.
The increase in demand side management programs expense is related to the
increase in DSM revenues. Beginning with the annual conservation charge
implemented in February 1995, DSM costs are recovered and expensed primarily
in the year incurred. The 1995 expense includes $31 million of 1995 program
costs and $14 million of amortization of costs capitalized in 1992 through
1994.
Property and other taxes increased primarily due to higher Boston property
taxes resulting from capital additions.
Our effective annual income tax rate for 1995 was 37.1% vs. 31.4% for 1994.
The higher rate is the result of a $10 million adjustment to deferred income
tax expense made in 1994 in accordance with the 1992 settlement agreement.
Other income
The net decrease in other income is primarily due to a $5.7 million gain
recognized in 1994 from a court ruling on a 1989 eminent domain taking of
certain of our property.
Interest charges
Interest on long-term debt increased due to a $125 million debenture issuance
in May 1995, partially offset by interest savings from first mortgage bond and
debenture redemptions in 1994. Other interest charges increased slightly due
to higher short-term interest rates partially offset by a lower average short-
term debt level. AFUDC decreased due to a lower construction work-in-progress
balance and shorter construction periods, partially offset by higher short-
term interest rates.
22
Electric Sales and Revenues
Electric sales
Retail kWh sales increased 2.8% in 1996. The major contributor to this
increase was the positive effect on commercial customers of a continued strong
economy in our retail service territory. The strong economy's impact in
greater Boston is illustrated by the highest commercial office occupancy rate
in 15 years. In addition, hotel occupancy rates and non-manufacturing
employment increased over 1995. The commercial sector represents
approximately 50% of our electric operating revenues. Residential sales,
which represent approximately 27% of electric operating revenues, decreased
slightly primarily due to overall milder than normal weather conditions.
Industrial sales remained relatively flat. This sector represents
approximately 9% of electric operating revenues. 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.
A 1.2% increase in retail kWh sales in 1995 was primarily due to a stronger
economy, partially offset by the impact of demand side management programs.
Total kWh sales increased 3.8% primarily due to an increase in Pilgrim
contract customer sales.
Electric revenues
Our retail electric rates are subject to the jurisdiction of the MDPU. As
discussed in the Positioning in the Industry section, we reached a settlement
agreement in December 1996 that, if approved, resolves certain necessary
issues surrounding electric industry restructuring. As part of the settlement
agreement our electric delivery business will provide "Standard Offer"
customers service at rates designed to give a 10% savings in electric prices.
Under the agreement, our base rates will remain frozen until the Retail Access
Date (the later of January 1, 1998 or the date when retail access is made
available to all customers of Massachusetts investor-owned utilities). We do
not expect that maintaining base rates at their current level until the Retail
Access Date will have a material adverse effect on our financial condition or
results of operations. After the Retail Access Date, the return on equity on
our electric delivery business will be subject to an 11.75% ceiling which is
lower than has been experienced in the recent past.
The annual performance adjustment charge from our 1992 settlement agreement
with the MDPU remains in effect through the year 2000 and provides us with
opportunities to improve our financial results. The most significant
potential impact of this performance incentive is based on Pilgrim Station's
annual capacity factor. An annual capacity factor between 60% and 68% would
provide us with approximately $54.5 million of revenues in the performance
year ended October 1997. For each percentage point increase in capacity
factor above 68%, annual revenues will increase by approximately $800,000.
For each percentage point decrease in capacity factor below 60% (to a minimum
of 35%), annual revenues will decrease by approximately $900,000. We are
currently billing customers based on an 85% capacity factor. This is a
decrease from the capacity factor of 90.9% achieved in the performance year
ended October 1996 due to the scheduled routine refueling outage that began in
February 1997. We earned $67.6 million in revenues related to Pilgrim's
capacity factor in the performance year ended October 31, 1996.
23
Pilgrim Station was shut down for approximately three months in 1994 due to a
non-nuclear problem with its electrical generator. Regularly scheduled
maintenance work was also performed during the shutdown. The power needs
usually met by the station were met by other generating plants or purchased
from other suppliers as necessary. We do not believe that the generator
damage resulted from actions within our control. Our recovery of the
incremental purchased power costs during the outage through fuel and purchased
power revenues, however, remains subject to review by the MDPU under a
generating unit performance program.
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 for changes in working capital and the payment of
dividends. During 1996, 1995 and 1994 our internal generation of cash
provided 170%, 102% and 109%, respectively of our plant expenditures. The
capital spending level, excluding nuclear fuel, forecasted for 1997 is $144
million which includes amounts for utility plant and our new business
ventures. The capital spending level over the next five years is forecasted
to be approximately $750 million. In addition to capital expenditures, we
have long-term debt and preferred stock payment requirements of $103.6 million
per year in 1997 and 1998, $3.6 million in 1999, $168.6 million in 2000 and
$53.6 million in 2001.
External financings continue to be necessary to supplement our internally
generated funds, 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, 1996, we had approximately $201 million of short-term debt
outstanding, none of which was incurred under the revolving credit agreement.
In 1994 the MDPU approved our financing plan to issue up to $500 million of
equity and long-term securities through 1996. In 1996 the MDPU approved our
request to extend this financing plan through 1998. Authority to issue
approximately $322 million remains under this plan. Proceeds from issuances
under this plan are to be used to refinance short and long-term securities and
to fund capital expenditures and working capital requirements. Refer to Notes
H and I to the Consolidated Financial Statements for additional information
relating to our financing activities. We intend to issue $100 million of two-
year debt in March 1997.
Outlook for the Future
Competitive forces within the electric utility industry continued to increase
in 1996. Changes in the industry include ongoing competition in wholesale
power markets and increased pressure for retail customer choice. These forces
are due to a variety of factors, including legislative and regulatory
proceedings at both federal and state levels designed to foster competition
and changes in customer expectations. The trend continues toward increased
competition through modified regulation of the industry. In Massachusetts,
open access to generation markets for retail customers is approaching rapidly.
The effects of competition have been evident in the wholesale energy market.
In response to the competition from other electric utilities and nonutility
generators to sell electricity for resale, we secured long-term power supply
agreements with our seven wholesale customers that set rates through 2002 and
beyond. This segment represents 3% of our operating revenues.
24
In January 1997, we filed an open access tariff with the FERC that
incorporates our transmission rates into a New England regional transmission
tariff. This filing, which is subject to approval, was made in response to
the FERC's open access transmission order that was issued in April 1996. The
order requires all utilities with transmission systems to file open access
tariffs, to provide service under those tariffs to transmission customers
comparable to service provided to their electric energy customers and to take
service under the tariffs for wholesale purchases and sales. The order also
supports the full recovery of legitimate and verifiable costs previously
incurred under federal and state regulation. The provisions in the order
provide a framework for significant changes in the electric utility industry.
We do not expect the FERC order to significantly impact the results of our
operations, which are primarily regulated by the MDPU.
Additional competition exists with alternative fuel suppliers as customers are
able to substitute natural gas, steam or oil for electricity for heating or
cooling purposes. In addition, industrial and large commercial customers may
pursue options to generate their own electric power or factor the cost of
electricity into their decisions to relocate to new service territories.
In addition to our involvement in the MDPU's restructuring proceeding, we have
actively responded to the changing electric utility industry in other ways.
In 1995 we reorganized the company into separate business units in order to
strengthen our competitiveness. The Customer, Fossil Generation, Nuclear
Generation and Corporate Services business units were designed to sharpen
management focus along our significant lines of operation while maintaining
company-wide strategic goals. The restructuring reduced our workforce which
resulted in a significant increase in labor efficiencies and cost savings. We
also continued to develop customer alliances and provided economic development
rates to some customers. These actions all illustrate our commitment to be a
competitively priced, reliable provider of energy.
In the traditional revenue requirements model, our electric revenues have been
based on the cost of providing electric service. As such, we are subject to
certain accounting standards that are not applicable to other businesses and
industries in general. We believe that we currently meet the criteria of
these standards. Statement of Financial Accounting Standards No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS 71) requires
us to defer recognition of certain costs when incurred when we expect to
receive future rate recovery of these costs. The Securities and Exchange
Commission has recently begun to focus on how the changes in the electric
utility industry have affected utilities' ability to continue to apply
regulatory accounting. The final rules issued by the MDPU or the enactment of
legislation in Massachusetts could, in the near term, cause us to no longer
meet the criteria for application of SFAS 71 for some of our operations.
Should this occur, we would be required to take an immediate noncash charge to
income for all of our affected regulatory assets and the above-market portion
of purchased power contracts. In addition, a write-down of utility plant
assets would be required 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, if competitive or regulatory change results in a
probability that future cash flows will not be sufficient to recover our
investment in those assets. Based on our settlement agreement we expect to
recover all strandable costs through a non-bypassable access charge to be paid
by customers of our electric delivery business. Under our settlement
agreement, our delivery business will remain subject to rate-regulation and,
therefore, will continue to meet the criteria of these accounting standards.
As noted earlier, under our settlement agreement we expect to continue to
operate Pilgrim Station with the ability to collect stranded costs related to
25
the unit. Although not anticipated based on our settlement agreement, the
nonrecovery of strandable costs could have a material impact on our results of
operations and financial condition. However, if laws are enacted or
regulatory decisions are made that do not offer Massachusetts electric
utilities an opportunity to recover previously reviewed, prudently incurred
commitments to provide service to our customers, we believe we have strong
legal arguments to challenge such laws or decisions. We will actively pursue
the full recovery of stranded costs and are prepared to take the action
necessary to protect the interests of our shareholders.
Other Matters
Connecticut Yankee
On December 4, 1996, the board of directors of Connecticut Yankee Atomic Power
Company (CYAPC), which owns and operates the Connecticut Yankee nuclear
electric generating unit (Connecticut Yankee), unanimously voted to retire the
Haddam Neck, Connecticut 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. We have a 9.5% equity investment in CYAPC of
approximately $10 million. Refer to Note L.4. to the Consolidated Financial
Statements for more information regarding Connecticut Yankee.
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 own or operate approximately 40 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 approximately
ten 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.
In October 1996, the Accounting Standards Executive Committee of the American
Institute of Certified Public Accountants issued Statement of Position 96-1,
Environmental Remediation Liabilities, effective in 1997. This statement
contains authoritative guidance on specific accounting issues that are present
in the recognition, measurement, display and disclosure of environmental
remediation liabilities. We do not believe that this statement will have a
material effect on our financial position or results of operations.
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, there
are uncertainties regarding the DOE's schedule of acceptance of spent fuel for
disposal. 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 spent nuclear fuel and LLW
disposal.
The 1990 Clean Air Act Amendments require a significant reduction in
nationwide emissions of sulfur dioxide from fossil fuel-fired generating
26
units. Sulfur dioxide emissions will be restricted through a market-based
system of allowances. In 1996 we sold sulfur dioxide allowances related to
the years 2000 to 2010 that are expected to be in excess of our needs.
Proceeds from the sale of these allowances were recorded as a regulatory
liability as it is probable that we will be required to refund the proceeds to
customers. We have the option to repurchase certain of these allowances at
specified prices from 2000 to 2010. We currently do not anticipate exercising
these options; however, their potential exercise will be based on numerous
factors, including the timing of the Retail Access Date. As discussed in the
Positioning in the Industry section, under our settlement agreement we have
agreed to the divestiture of our fossil generating plants no later than six
months after the Retail Access Date (the later of January 1, 1998 or the date
when retail access is made available to all customers of Massachusetts
investor-owned utilities). If regulatory approval is not obtained or is
delayed, it is possible that we could continue to operate these units. Other
provisions of the 1990 Clean Air Act Amendments involve limitations on
emissions of nitrogen oxides from existing generating units. Combustion
system modifications made to New Boston and Mystic Stations, including the
installation of low nitrogen oxides burners at New Boston, have allowed the
units to meet the provisions of the 1995 standards. Depending upon the
outcome of certain Massachusetts Department of Environmental Protection air
quality modeling studies currently in progress, the continued operation of
these units could require additional emission reductions by 1999 or years
thereafter. The extent of any additional emission restrictions and the cost
of any further modifications is uncertain at this time.
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 recently
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 closely monitor
all aspects of the EMF issue.
Litigation
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 February 1997, we settled the lawsuit
brought by Subaru Distributors Corporation. The settlement did not have a
material impact on our financial position or results of operations. The
Subaru of New England, Inc. lawsuit is still pending.
27
Refer to Note L.7. to the Consolidated Financial Statements for more
information on these lawsuits and other legal matters in which we are
involved.
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, our joint ventures, operating results, Pilgrim Station's
performance, Connecticut Yankee and environmental and legal issues.
The effects of the industry restructuring process currently underway at the
MDPU and our related settlement agreement 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 legislative action may affect the ultimate
results of the industry restructuring and our settlement agreement.
The timing and activities of our joint ventures as well as our actual
investments may 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.
Pilgrim Station's performance could differ from our expectations. The
station's capacity factor could be impacted by changes in regulations or by
unplanned outages resulting from certain operating conditions.
The ultimate liability related to the shutdown of Connecticut Yankee could
differ from the current estimate. In addition, although not anticipated, it
is possible that some portion of our share of post-operation costs may not be
recoverable from ultimate customers.
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.
28
Item 8. Financial Statements and Supplementary Financial Information
- ---------------------------------------------------------------------
Consolidated Statements of Income
years ended December 31,
(in thousands, except earnings per share) 1996 1995 1994
- ---------------------------------------------------------------------------
Operating revenues $1,666,303 $1,628,503 $1,544,735
- ---------------------------------------------------------------------------
Operating expenses:
Fuel and purchased power 588,893 535,806 513,825
Operations and maintenance 417,372 458,196 443,545
Restructuring costs 0 34,000 0
Depreciation and amortization 185,494 153,339 148,845
Amortization of deferred costs of
cancelled nuclear unit 0 0 19,791
Demand side management programs 30,825 45,125 35,438
Taxes-property and other 107,086 106,361 100,015
Income taxes 88,703 68,276 54,798
- ---------------------------------------------------------------------------
Total operating expenses 1,418,373 1,401,103 1,316,257
- ---------------------------------------------------------------------------
Operating income 247,930 227,400 228,478
Other income (expense), net 698 (575) 3,979
- ---------------------------------------------------------------------------
Operating and other income 248,628 226,825 232,457
- ---------------------------------------------------------------------------
Interest charges:
Long-term debt 94,823 106,640 102,570
Other 14,551 12,642 12,343
Allowance for borrowed funds used
during construction (2,292) (4,767) (7,478)
- ---------------------------------------------------------------------------
Total interest charges 107,082 114,515 107,435
- ---------------------------------------------------------------------------
Net income 141,546 112,310 125,022
Preferred stock dividends 15,365 15,571 15,765
- ---------------------------------------------------------------------------
Earnings available for common
shareholders $ 126,181 $ 96,739 $ 109,257
===========================================================================
Weighted average common shares outstanding 48,265 46,592 45,338
Earnings per share of common stock $ 2.61 $ 2.08 $ 2.41
===========================================================================
Consolidated Statements of Retained Earnings
years ended December 31,
(in thousands) 1996 1995 1994
- ---------------------------------------------------------------------------
Balance at the beginning of the year $ 257,344 $ 247,004 $ 218,292
Net income 141,546 112,310 125,022
- ---------------------------------------------------------------------------
Subtotal 398,890 359,314 343,314
- ---------------------------------------------------------------------------
Cash dividends declared:
Preferred stock 15,365 15,571 15,765
Common stock 90,834 86,399 80,545
- ---------------------------------------------------------------------------
Subtotal 106,199 101,970 96,310
- ---------------------------------------------------------------------------
Provision for preferred stock
redemption and issuance costs (a) 905 0 0
- ---------------------------------------------------------------------------
Balance at the end of the year $ 291,786 $ 257,344 $ 247,004
===========================================================================
(a) Refer to Note B.7. to the Consolidated Financial Statements.
The accompanying notes are an integral part of the consolidated financial
statements
29
Consolidated Balance Sheets
December 31,
(in thousands) 1996 1995
- ------------------------------------------------------------------------------
Assets
Utility plant in service, at
original cost $4,393,585 $4,315,422
Less: accumulated depreciation 1,550,317 $2,843,268 1,439,996 $2,875,426
- ------------------------------------------------------------------------------
Nuclear fuel 351,453 302,594
Less: accumulated amortization 268,509 82,944 251,951 50,643
- ------------------------------------------------------------------------------
Construction work in progress 30,376 29,573
- ------------------------------------------------------------------------------
Net utility plant 2,956,588 2,955,642
Investments in electric companies,
at equity 23,054 23,620
Nuclear decommissioning trust 132,076 102,894
Current assets:
Cash and cash equivalents 5,651 5,841
Accounts receivable 233,024 219,114
Accrued unbilled revenues 34,922 37,113
Fuel, materials and supplies,
at average cost 57,075 59,631
Other 45,146 375,818 23,607 345,306
- ------------------------------------------------------------------------------
Deferred debits:
Regulatory assets-power contracts 88,963 21,396
Other regulatory assets 113,063 128,699
Other 39,729 59,613
- ------------------------------------------------------------------------------
Total assets $3,729,291 $3,637,170
==============================================================================
Capitalization and Liabilities
Common stock equity $1,036,424 $ 989,438
Cumulative preferred stock:
Nonmandatory redeemable series 119,954 119,677
Mandatory redeemable series 81,465 84,837
Long-term debt 1,058,644 1,160,223
Current liabilities:
Long-term debt/preferred
stock due within one year $ 102,667 $ 102,667
Notes payable 201,454 126,441
Accounts payable 134,083 133,474
Accrued interest 24,378 25,113
Dividends payable 25,343 25,351
Other 115,812 603,737 138,044 551,090
- ------------------------------------------------------------------------------
Deferred credits:
Power contracts 88,963 21,396
Accumulated deferred income taxes 498,718 497,282
Accumulated deferred investment
tax credits 58,899 62,970
Nuclear decommissioning liability 133,388 113,288
Other 49,099 36,969
Commitments and contingencies
- ------------------------------------------------------------------------------
Total capitalization and liabilities $3,729,291 $3,637,170
==============================================================================
The accompanying notes are an integral part of the consolidated financial
statements
30
Consolidated Statements of Cash Flows
years ended December 31,
(in thousands) 1996 1995 1994
- -----------------------------------------------------------------------------
Operating activities:
Net income $141,546 $112,310 $125,022
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 228,259 202,294 203,222
Deferred income taxes and investment tax
credits (4,057) (25,193) (8,276)
Allowance for borrowed funds used during
construction (2,292) (4,767) (7,478)
Net changes in:
Accounts receivable and accrued
unbilled revenues (11,719) (34,626) (20,701)
Fuel, materials and supplies (2,171) 7,202 3,093
Accounts payable 609 2,978 23,196
Other current assets and liabilities (44,514) 26,485 35,217
Other, net 50,921 23,975 14,847
- -----------------------------------------------------------------------------
Net cash provided by operating activities 356,582 310,658 368,142
- -----------------------------------------------------------------------------
Investing activities:
Plant expenditures (excluding AFUDC) (151,045) (180,822) (198,771)
Nuclear fuel expenditures (52,967) (13,621) (21,934)
Demand side management expenditures 0 0 (37,007)
Sale of plant assets, net (106) 3,018 15,972
Nuclear decommissioning trust investments (29,182) (20,063) (16,771)
Electric company investments 566 1,058 (386)
- -----------------------------------------------------------------------------
Net cash used in investing activities (232,734) (210,430) (258,897)
- -----------------------------------------------------------------------------
Financing activities:
Issuances:
Common stock 12,559 64,888 10,634
Long-term debt 0 125,000 15,000
Redemptions:
Preferred stock (4,000) (2,000) (2,000)
Long-term debt (101,600) (100,600) (50,000)
Net change in notes payable 75,013 (88,345) 10,635
Dividends paid (106,010) (100,152) (95,460)
- -----------------------------------------------------------------------------
Net cash used in financing activities (124,038) (101,209) (111,191)
- -----------------------------------------------------------------------------
Net decrease in cash and cash equivalents (190) (981) (1,946)
Cash and cash equivalents at the
beginning of the year 5,841 6,822 8,768
- -----------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $ 5,651 $ 5,841 $ 6,822
=============================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized $100,810 $104,011 $ 99,287
Income taxes $ 98,668 $ 96,180 $ 46,074
The accompanying notes are an integral part of the consolidated financial
statements.
31
Notes to Consolidated Financial Statements
Note A. Nature of Operations
We are an investor-owned regulated public utility operating in the energy and
energy services 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 1996. 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. In December 1996, BETG signed a joint venture
agreement with Residential Communications Network, Inc., currently known as
RCN Telecom Services, Inc. (RCN), to form a limited liability company to
provide local and long-distance telephone service, video, high-speed Internet
access and other telecommunications-related services (the "Telecommunications
Venture"). The unregulated entity will be owned up to 49% by BETG, with RCN
having the day-to-day management responsibility. The joint venture agreement
is subject to a number of conditions which must be satisfied before formal
operations begin, including the obtaining of certain regulatory approvals. In
January 1997, BETG, through one of its wholly owned subsidiaries, signed
definitive agreements with Williams Energy Services Company (WESCO), a
subsidiary of The Williams Companies, Inc., to form EnergyVision, LLC, an
unregulated limited liability company. This "Energy Marketing Venture" will
market electricity, natural gas and energy-related services to retail
customers in the six New England states. BETG, through its subsidiary, and
WESCO each own 50% of the new company which began operations in February 1997.
In January 1997, we announced a plan to form a holding company structure. The
holding company structure, which is subject to shareholder and regulatory
approvals, is intended to provide increased financial, managerial and
organizational flexibility in order to better position us to operate in the
changing electric utility industry. It will permit us to take advantage of
nonutility business opportunities in a more timely manner. In addition, the
holding company structure will clearly separate our regulated and unregulated
lines of business enabling us to pursue nonutility business ventures in a
manner consistent with the electric utility industry restructuring principles
outlined by the Massachusetts Department of Public Utilities (MDPU). The
holding company structure is a well-established form of organization for
companies conducting multiple lines of business, particularly entities
engaging in both regulated and unregulated activities. All investor-owned
Massachusetts electric utilities, other than Boston Edison, are currently
organized in a holding company structure.
Refer also to Note C to these Consolidated Financial Statements for potential
changes in the nature of our operations as a result of the electric utility
industry restructuring.
32
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 MDPU. 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 are subject to 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. 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 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. The MDPU has
the right to reduce our subsequent fuel and purchased power rates if they find
that we have been unreasonable or imprudent in the operation of our generating
units or in purchasing fuel.
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 adjustment discussed below, the overall composite
depreciation rates were 3.26%, 3.28% and 3.31% in 1996, 1995 and 1994,
respectively.
33
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) are unlikely to provide competitively priced power beyond the year 2000.
Therefore, during the second quarter of 1996, we revised the estimated
remaining economic lives of these units to five years retroactive to the
beginning of the year. The effect of this change in estimate is an annual
increase to depreciation expense of $22 million.
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
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 future periods. 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 debt 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 over the
average life of the replacement preferred stock series.
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
1996, 1995 and 1994 were 5.87%, 6.35% and 4.45%, 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.
34
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. No return on investment is being earned on the regulatory assets.
Regulatory assets consisted of the following:
December 31,
1996 1995
- --------------------------------------------------------------------
Power contracts $ 88,963 $ 21,396
Redemption premiums 31,052 36,832
Income taxes, net 47,483 46,121
Postretirement benefits costs 15,009 15,009
Decontamination and decommissioning 13,190 13,968
Nuclear outage costs 3,432 13,471
Other 2,897 3,298
- --------------------------------------------------------------------
$202,026 $150,095
====================================================================
12. Earnings Per Share of Common Stock
Earnings per share 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.
Note C. Electric Utility Industry
In December 1996, we reached a settlement agreement with the Massachusetts
Attorney General and the Massachusetts Division of Energy Resources that, if
approved by the MDPU, allows all retail electric customers in our service area
to choose their electricity supplier (referred to as retail access) beginning
as early as January 1, 1998. As part of the settlement, we have agreed to
divest our fossil generating plants no later than six months after the
commencement of retail access. Accordingly, other than Pilgrim Nuclear Power
Station, we will no longer own any electricity generating facilities. The
rates of our retained electric delivery business will continue to be regulated
by the MDPU and will include a non-bypassable access charge for the collection
of our stranded costs. These costs include the above-market commitments under
existing purchased power contracts, our net generation plant investment,
nuclear decommissioning commitments and regulatory assets related to our
generation business. Implementation of the settlement will be subject to
enactment of enabling legislation by the Massachusetts legislature and rulings
by the FERC.
In the traditional revenue requirements model, our electric revenues have been
based on the cost of providing electric service. As such, we are subject to
certain accounting standards that are not applicable to other businesses and
industries in general. We believe that we currently meet the criteria of
these standards. SFAS 71 requires us to defer recognition of certain costs
when incurred when we expect to receive future rate recovery of these costs.
The Securities and Exchange Commission has recently begun to focus on how the
changes in the electric utility industry have affected utilities' ability to
continue to apply regulatory accounting. The final rules issued by the MDPU
or the enactment of legislation in Massachusetts could, in the near term,
cause us to no longer meet the criteria for application of SFAS 71 for some of
our operations. Should this occur, we would be required to take an immediate
35
noncash charge to income for all of our affected regulatory assets and the
above-market portion of purchased power contracts. In addition, a write-down
of utility plant assets would be required 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, if competitive or
regulatory change results in a probability that future cash flows will not be
sufficient to recover our investment in those assets. Based on our settlement
agreement we expect to recover all strandable costs through a non-bypassable
access charge to be paid by our delivery business customers. Under our
settlement agreement, our delivery business will remain subject to rate
regulation and, therefore, will continue to meet the criteria of these
accounting standards. As noted earlier, under our settlement agreement we
expect to continue to operate Pilgrim Station with the ability to collect
stranded costs related to the unit. Although not anticipated based on our
settlement agreement, the nonrecovery of strandable costs could have a
material impact on our results of operations and financial condition.
However, if laws are enacted or regulatory decisions are made that do not
offer Massachusetts electric utilities an opportunity to recover previously
reviewed, prudently incurred commitments to provide service to our customers,
we believe we have strong legal arguments to challenge such laws or decisions.
We will actively pursue the full recovery of stranded costs and are prepared
to take the action necessary to protect the interests of our shareholders.
Our 1992 settlement agreement provided us with two annual retail base rate
increases of $29 million effective in November 1993 and November 1994 and an
eight-year annual performance adjustment charge. We did not make a base rate
filing upon the expiration of the settlement agreement in 1995, therefore base
rates have remained in effect at their 1995 levels.
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 $47.5 million and $46.1 million and
corresponding net increases in accumulated deferred income taxes as of
December 31, 1996, and December 31, 1995, 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) 1996 1995
- ------------------------------------------------------------------------------
Deferred tax liabilities:
Plant-related $532,390 $521,280
Other 95,642 95,148
- ------------------------------------------------------------------------------
628,032 616,428
- ------------------------------------------------------------------------------
Deferred tax assets:
Plant-related 8,406 12,590
Investment tax credits 38,005 40,632
Other 82,903 65,924
- ------------------------------------------------------------------------------
129,314 119,146
- ------------------------------------------------------------------------------
Net accumulated deferred income taxes $498,718 $497,282
==============================================================================
36
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) 1996 1995 1994
- -----------------------------------------------------------------------------
Current income tax expense $92,760 $93,469 $63,358
Deferred income tax expense 14 (21,115) (4,468)
Investment tax credits (4,071) (4,078) (4,092)
- -----------------------------------------------------------------------------
Income taxes charged to operations 88,703 68,276 54,798
- -----------------------------------------------------------------------------
Taxes on other income:
Current (721) (1,729) 2,550
Deferred 0 0 284
- -----------------------------------------------------------------------------
(721) (1,729) 2,834
- -----------------------------------------------------------------------------
Total income tax expense $87,982 $66,547 $57,632
=============================================================================
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:
1996 1995 1994
- -----------------------------------------------------------------------------
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 4.3 4.3 4.3
Investment tax credits (1.8) (2.3) (2.3)
Reversal of deferred taxes - settlement agreement - - (5.5)
Other 0.7 0.1 (0.1)
- -----------------------------------------------------------------------------
Effective tax rate 38.2% 37.1% 31.4%
=============================================================================
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. We record an estimate of decommissioning costs in
depreciation expense on the consolidated statements of income over Pilgrim's
expected service life. Decommissioning expense was $12 million, $14 million
and $15 million in 1996, 1995 and 1994, respectively. 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
Energy (DOE) spent fuel removal program. Refer to part 2 below for a
discussion of spent fuel removal. The partial update indicates an estimated
decommissioning cost of $400 million in 1991 dollars based upon a revised
37
spent fuel removal schedule and utilization of dry spent fuel storage
technology. No further update is currently available; however, we will
continue to monitor DOE spent fuel removal schedules and developments in spent
fuel storage technology along with their impact on the decommissioning
estimate. We anticipate that we will be permitted to recover our actual
ultimate decommissioning costs from our retail and contract customers.
In February 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. Depending on the results of the FASB's redeliberation of
certain issues regarding these proposed rules, it plans to issue either a
final statement or revised proposed rules in the second quarter of 1997.
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 Nuclear Regulatory Commission 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 MDPU. We are actively exploring the feasibility of other spent fuel
storage facilities and technologies, including proposed participation in a
limited liability company (LLC) which would undertake construction of a
private spent fuel storage facility in the state of Utah or other locations.
Our participation in this LLC requires approval by the MDPU and is currently
the subject of a petition seeking such approval.
In July 1996, the U.S. Court of Appeals for the District of Columbia Circuit
ruled that the DOE is obligated to begin taking spent nuclear fuel for
disposal in 1998. The decision was in response to petitions filed by us and
other interested parties in 1994 seeking declaratory rulings concerning this
obligation. In December 1996, the DOE notified us and other nuclear plant
owners that it would be unable to begin acceptance of spent nuclear fuel for
disposal in 1998. Along with other interested parties, we again filed a
petition with the U.S. Court of Appeals for the District of Columbia Circuit
seeking declaratory rulings concerning enforcement and remedies for DOE's
failure to accept spent fuel for disposal in a timely manner. 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. The DOE has been conducting scientific studies evaluating a
potential spent nuclear fuel repository site at Yucca Mountain, Nevada. The
potential site, however, has encountered substantial public and political
opposition and the DOE has publicly stated that it will be unable to begin
acceptance of spent nuclear fuel for disposal by the date specified in the
Nuclear Waste Policy Act. We cannot predict at this time whether or on what
38
schedule the DOE will eventually construct a spent fuel repository or what the
effect will be of any delays in such construction.
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 the state's 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. 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 net of 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. The enhanced retirement programs were offered to all
employees at least 55 years old, with different years of service requirements
for management and union employees. The programs provided for supplemental
salary payments and waivers of the early retirement pension reduction and the
medical and life insurance benefits years of service requirement. The special
severance program, which applied to management and support personnel, was
provided for all employees whose positions were eliminated in the
reorganization. Severance benefits provided included salary payments, medical
insurance and outplacement services. As of December 31, 1996, there was no
material obligation remaining for these programs.
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 a supplemental retirement plan for certain management employees.
Benefits under this plan are based on final compensation upon retirement. The
plan is not funded. The plan's cost and benefit obligation amounts are
included in the following pension information for 1995 and 1996. Amounts
related to the plan prior to 1995 were not material to our total pension
costs.
39
Net pension cost consisted of the following components:
years ended December 31,
(in thousands) 1996 1995 1994
- -----------------------------------------------------------------------------
Current service cost - benefits earned $13,452 $11,339 $15,057
Interest cost on projected benefit
obligation 32,325 31,789 33,961
Actual net (return)/loss on plan assets (40,335) (72,192) 214
Net amortization and deferral 17,064 49,557 (32,169)
- -----------------------------------------------------------------------------
Net pension cost $22,506 $20,493 $17,063
=============================================================================
In accordance with our 1992 settlement agreement we deferred the difference
between the net pension cost of the retirement plan and its annual funding
amount through 1995. Net pension costs recognized in 1995 and 1994 were $28.2
million and $25.0 million, respectively.
We used the following assumptions for calculating pension cost:
1996 1995 1994
- -----------------------------------------------------------------------------
Discount rate 7.25% 8.25% 7.00%
Expected long-term rate of return on assets 10.00% 10.00% 10.00%
Compensation increase rate 3.90% 3.90% 4.50%
- -----------------------------------------------------------------------------
The plans' funded status were as follows:
December 31,
(in thousands) 1996 1995
- -----------------------------------------------------------------------------
Supplemental Supplemental
Retirement Retirement Retirement Retirement
Plan Plan Plan Plan
- -----------------------------------------------------------------------------
Actuarial present value of
accumulated benefit
obligation:
Vested $316,101 $ 7,576 $377,272 $ 8,748
Non-vested 10,867 943 13,902 1,409
- -----------------------------------------------------------------------------
Total (a) $326,968 $ 8,519 $391,174 $ 10,157
=============================================================================
Plan assets at fair value $331,299 $ 0 $358,572 $ 0
Projected obligation for
service rendered to date (400,561) (9,199) (476,666) (11,036)
- -----------------------------------------------------------------------------
Projected benefit
obligation in excess of
plan assets (69,262) (9,199) (118,094) (11,036)
Unrecognized prior service
cost 11,238 9,436 12,283 10,223
Unrecognized net loss/(gain) 78,853 (1,141) 82,935 252
Unrecognized net obligation 7,130 0 8,064 0
Additional minimum
liability (b) 0 (7,615) (17,790) (9,596)
- -----------------------------------------------------------------------------
Net pension prepayment/
(liability) $ 27,959 $ (8,519) $(32,602) $(10,157)
=============================================================================
(a) The accumulated benefit obligation at December 31, 1995, includes
$13.5 million related to the enhanced retirement programs offered in
1995 as discussed in Note F to these Consolidated Financial Statements.
(b) 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
40
recorded additional minimum liabilities and corresponding intangible
assets of $7.6 million and $27.4 million on our consolidated balance
sheets at December 31, 1996 and 1995, respectively.
We used the following assumptions for calculating the plans' year-end funded
status:
1996 1995
- -----------------------------------------------------------------------------
Discount rate 7.75% 7.25%
Compensation increase rate 3.90% 3.90%
- -----------------------------------------------------------------------------
We also provide defined contribution 401(k) plans for substantially all our
employees. We match a percentage of employees' voluntary contributions to the
plans. We made matching contributions of $8 million in 1996, $9 million in
1995 and $8 million in 1994.
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
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions (SFAS 106). Our 1992 settlement agreement provided us with a
phase-in to full expense of the PBOP costs incurred under SFAS 106. The 1992
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 recorded $23 million and $17 million of PBOP costs in 1995 and
1994, respectively in accordance with the 1992 settlement agreement. In 1996
we recorded the full PBOP costs incurred under SFAS 106 of $26 million. The
net deferred PBOP costs of $15 million resulting from the delayed phase-in are
included in regulatory assets as these costs are expected to be recovered from
customers in future periods.
Net postretirement benefits cost consisted of the following components:
years ended December 31,
(in thousands) 1996 1995 1994
- -----------------------------------------------------------------------------
Current service cost - benefits earned $ 4,616 $ 3,408 $ 4,978
Interest cost on accumulated benefit
obligation 16,815 13,521 13,632
Actual return on plan assets (9,584) (7,151) (187)
Amortization of transition obligation 9,151 9,151 9,151
Net amortization and deferral 5,209 3,017 (2,581)
- -----------------------------------------------------------------------------
Net postretirement benefits cost $26,207 $21,946 $24,993
=============================================================================
We used the following assumptions for calculating postretirement benefits
cost:
1996 1995 1994
- -----------------------------------------------------------------------------
Discount rate 7.25% 8.25% 7.00%
Expected long-term rate of return on assets 9.00% 9.00% 9.00%
Health care cost trend rate 7.00% 7.00% 9.00%
- -----------------------------------------------------------------------------
The health care cost trend rate is assumed to decrease by one percent in 1997
and 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 one percent
increase in the assumed health care cost trend rate would increase the total
41
service and interest cost components by 7.6% and would increase the
accumulated benefit obligation at December 31, 1996, by 6.7%.
The PBOP program's funded status was as follows:
December 31,
(in thousands) 1996 1995
- -----------------------------------------------------------------------------
Trust assets at fair value $ 72,702 $ 51,064
Accumulated obligation for service
rendered to date from:
Retirees $(156,694) $(110,877)
Active employees eligible to retire (12,644) (31,980)
Active employees not eligible to
retire (61,567) (230,905) (53,514) (196,371)
- -----------------------------------------------------------------------------
Accumulated benefit obligation in
excess of trust assets (158,203) (145,307)
Unrecognized prior service cost (16,274) (17,889)
Unrecognized net loss 26,663 5,612
Unrecognized transition obligation 146,413 155,564
- -----------------------------------------------------------------------------
Net postretirement benefits liability $ (1,401) $ (2,020)
=============================================================================
The weighted average discount rates used to measure the accumulated benefit
obligation were 7.75% in 1996 and 7.25% in 1995. The trust assets consist of
equities, bonds and money market funds.
42
Note H. Capital Stock
December 31,
(dollars in thousands, except per share amounts) 1996 1995
- -----------------------------------------------------------------------------
Common stock equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 48,509,537
and 48,003,178 shares issued and
outstanding: $ 48,510 $ 48,003
Premium on common stock 695,723 683,686
Retained earnings 291,786 257,344
Surplus invested in plant 405 405
- -----------------------------------------------------------------------------
Total common stock equity $1,036,424 $989,438
=============================================================================
Dividends declared per share of common stock were $1.88, $1.835 and $1.775 in
1996, 1995 and 1994, respectively.
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% 400,000 - 40,000 40,000
- -----------------------------------------------------------------------------
123,000 123,000
Less: redemption and issuance costs (3,046) (3,323)
- -----------------------------------------------------------------------------
Total nonmandatory redeemable series $ 119,954 $119,677
=============================================================================
Mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
- -----------------------------------------------------------------------------
7.27% 400,000 $102.910 $ 40,000 $ 44,000
8.00% 500,000 - 50,000 50,000
- -----------------------------------------------------------------------------
90,000 94,000
Less: redemption and issuance costs (6,535) (7,163)
due within one year (2,000) (2,000)
- -----------------------------------------------------------------------------
Total mandatory redeemable series $ 81,465 $ 84,837
=============================================================================
1. Common Stock
Common stock issuances in 1994 through 1996 were as follows:
Number Total Premium on
(in thousands) of Shares Par Value Common Stock
- -----------------------------------------------------------------------------
Balance at December 31, 1993 45,129 $45,129 $612,653
Dividend reinvestment plan 406 406 10,150
- -----------------------------------------------------------------------------
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
=============================================================================
43
2. Cumulative Mandatory Redeemable Preferred Stock
The 400,000 shares of 7.27% sinking fund series cumulative preferred stock are
currently redeemable at our option at $102.910. 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. In 1996, 1995 and 1994, we redeemed, at par
value, 40,000 shares, 20,000 shares and 20,000 shares, respectively. The
redemptions in 1996 include 20,000 shares of optional redemptions.
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 I. Indebtedness
December 31,
(in thousands) 1996 1995
- -----------------------------------------------------------------------------
Long-term debt:
Debentures:
5.125%, due March 1996 $ 0 $ 100,000
5.700%, due March 1997 100,000 100,000
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 1,115,000 1,215,000
Less: due within one year (100,000) (100,000)
- -----------------------------------------------------------------------------
Net long-term debentures 1,015,000 1,115,000
- -----------------------------------------------------------------------------
Sewage facility revenue bonds 34,100 35,700
Less: due within one year (667) (667)
Less: funds held by trustee (4,789) (4,810)
- -----------------------------------------------------------------------------
Net long-term sewage facility revenue bonds 28,644 30,223
- -----------------------------------------------------------------------------
Massachusetts Industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000
- -----------------------------------------------------------------------------
Total long-term debt $1,058,644 $1,160,223
=============================================================================
Short-term debt:
Notes payable:
Bank loans $ 129,631 $ 75,941
Commercial paper 71,823 50,500
- -----------------------------------------------------------------------------
Total notes payable $ 201,454 $ 126,441
=============================================================================
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 May 1995 and 1996, we redeemed $0.6 million and $1.6
million, respectively, 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.
The aggregate principal amounts of our long-term debt (including HEEC sinking
fund requirements) due through 2001 are $101.6 million per year in 1997 and
1998, $1.6 million in 1999, $166.6 million in 2000 and $1.6 million in 2001.
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 short-term borrowings, comprised of bank loans and
commercial paper, is as follows:
(dollars in thousands) 1996 1995 1994
- -----------------------------------------------------------------------------
Maximum short-term borrowings $272,500 $327,769 $268,100
Weighted average amount outstanding $208,914 $165,720 $214,640
Weighted average interest rates excluding
commitment fees 5.65% 6.21% 4.47%
- -----------------------------------------------------------------------------
Note J. 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 $132.1 million approximates fair value based on quoted market
prices of securities held.
45
Cash and cash equivalents:
The carrying amount of $5.7 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, 1996, are
as follows:
Carrying Fair
(in thousands) Amount Value
- ------------------------------------------------------------------------------
Mandatory redeemable cumulative preferred stock $ 83,465 $ 93,900
Sewage facility revenue bonds $ 34,100 $ 35,082
Unsecured debt $1,130,000 $1,131,363
- ------------------------------------------------------------------------------
Note K. New Accounting Pronouncement
In October 1996, the Accounting Standards Executive Committee of the American
Institute of Certified Public Accountants issued Statement of Position 96-1,
Environmental Remediation Liabilities, effective in 1997. This statement
contains authoritative guidance on specific accounting issues that are present
in the recognition, measurement, display and disclosure of environmental
remediation liabilities. We do not believe this statement will have a
material effect on our financial position or results of operations.
Note L. Commitments and Contingencies
1. Contractual Commitments
At December 31, 1996, we had estimated contractual obligations for plant and
equipment of approximately $8 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 1996 are as follows:
(in thousands)
- ------------------------------------------------------
1997 $ 22,842
1998 20,042
1999 17,568
2000 16,684
2001 12,067
Years thereafter 98,945
- ------------------------------------------------------
Total $188,148
======================================================
The total of future minimum rental income to be received under noncancellable
subleases related to the above leases is $455,117.
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 $26.3 million in 1996, $24.5 million in 1995 and
$28.6 million in 1994, net of capitalized expenses of $2.9 million in 1996,
$2.7 million in 1995 and $2.4 million in 1994.
We also have various outstanding commitments for take or pay and throughput
agreements, primarily to supply our New Boston generating station with natural
46
gas. The fixed and determinable portions of the obligations are $19.5 million
in 1997, 1998 and 1999 and $14.6 million in 2000. We are also committed to
purchase natural gas at market prices. The total expense under these
agreements was $49.5 million in 1996, $13.9 million in 1995, and $6.5 million
in 1994.
2. Hydro-Quebec
We have an approximately 11% equity ownership interest 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, 1996,
our portion of these guarantees was approximately $18 million.
3. Yankee Atomic
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 permanently discontinue power operation of the Yankee Atomic
nuclear generating station 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 $16.5 million as of December 31,
1996. This estimate is recorded on our consolidated balance sheet as a power
contract liability and an offsetting regulatory asset as we continue to
collect these costs from our customers in accordance with our 1992 settlement
agreement.
4. Connecticut Yankee
On December 4, 1996, the board of directors of Connecticut Yankee Atomic Power
Company (CYAPC), which owns and operates the Connecticut Yankee nuclear
electric generating unit (Connecticut Yankee), unanimously voted to retire the
Haddam Neck, Connecticut 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. We have a 9.5% equity investment in CYAPC of
approximately $10 million.
The current estimate of the sum of future payments for the closing,
decommissioning and recovery of the remaining investment in Connecticut Yankee
is approximately $763 million. Our share of these remaining estimated costs
is $72.5 million.
On December 24, 1996, CYAPC filed its cost estimate along with certain
amendments to its power contracts with the FERC. The power contract
amendments are designed to clarify the obligations of CYAPC's power
purchasers, including Boston Edison, following the decision to cease power
production. Based upon regulatory precedent, CYAPC believes it will continue
to collect from its power purchasers its decommissioning costs, the owners'
unrecovered investments in CYAPC and other costs associated with the permanent
closure of the unit over the remaining period of the unit's operating license.
We expect that we will continue to be allowed to recover our share of such
costs from our customers and, therefore, have recorded our share of these
costs on our consolidated balance sheet as a regulatory asset with a
corresponding power contract liability.
47
5. Nuclear Insurance
The federal Price-Anderson Act currently provides approximately $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 approximately $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.
6. Hazardous Waste
We own or operate approximately 40 properties where oil or hazardous materials
were previously spilled or released. We are required to clean up these
properties in accordance with a timetable developed by the Massachusetts
Department of Environmental Protection and are continuing to evaluate the
costs associated with their 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 approximately ten 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. At the majority of
these 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, 1996, 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.
48
7. Litigation
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 February 1997, we settled the lawsuit
brought by Subaru Distributors Corporation. The settlement did not have a
material impact on our financial position or results of operations. The
Subaru of New England, Inc. lawsuit is still pending.
In 1991 we were named in a lawsuit alleging discriminatory employment
practices under the Age Discrimination in Employment Act of 1967 concerning
employees affected by our 1988 reduction in force. In December 1996, we
reached a settlement of this lawsuit under which there is no finding or
admission of discriminatory employment practices. We anticipate full recovery
from our insurance carrier for this settlement.
In the normal course of our business we are also 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.
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 the 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, 1996, 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 $ 1,415 $ 5,373 $ 24,399
Mass. Bay Trans-
portation
Authority - 1 2005 100.0 34 - - 1,999
Connecticut Yankee
Atomic 2007 9.5 - 2,427 12,519 (b)
Ocean State Power -
Unit 1 2010 23.5 68 4,487 20,447 23,689
Ocean State Power -
Unit 2 2011 23.5 67 3,538 16,529 24,091
Northeast Energy
Associates (c) (c) 219 - - 124,730
L'Energia (d) 2013 73.0 63 - - 30,920
MassPower 2013 44.3 117 11,738 76,524 50,322
Mass. Bay Trans-
portation
Authority - 2 2019 100.0 34 - - 371
- ------------------------------------------------------------------------------
Total 743 $23,605 $131,392 $280,521
==============================================================================
(a) The Northeast Energy Associates contract represents 6% of our total
system generation capability. The remaining units listed above represent
14.5% in total.
(b) Connecticut Yankee permanently ceased operation in 1996. Refer to Note
L.4. to these Consolidated Financial Statements for more details.
(c) We purchase approximately 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.
(d) We pay for this energy based on a price per kWh actually received.
50
Our total fixed and variable costs for these contracts in 1996, 1995 and 1994
were approximately $281 million (excluding Connecticut Yankee Atomic), $283
million and $286 million, respectively. Our minimum fixed payments under
these contracts for the years after 1996 are as follows:
(in thousands)
- ------------------------------------------------------
1997 $ 85,429
1998 87,540
1999 88,401
2000 88,927
2001 91,089
Years thereafter 1,047,479
- ------------------------------------------------------
Total $1,488,865
======================================================
Total present value $ 797,683
======================================================
2. Long-Term Power Sales
In addition to wholesale power sales, we sell a percentage of Pilgrim
Station's output to other utilities under long-term contracts. Information
relating to these contracts is as follows:
Contract
Expiration Units of Capacity Sold
----------------------
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 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 capital.
51
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
Balance
Available Earnings
Operating Operating Net for Common Per Average
Revenues Income Income Stock Common Share(a)
- --------------------------------------------------------------------------
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
1995
- ----
First quarter $379,678 $ 47,610 $20,202 $16,300 $0.36
Second quarter 380,828 55,683 26,137 22,247 0.48
Third quarter 498,554 102,695(b) 72,368 (b) 68,478 (b) 1.46 (b)
Fourth quarter 369,443 21,412(b) (6,397)(b) (10,286)(b) (0.21)(b)
(a) Based on the weighted average number of common shares outstanding during
each quarter.
(b) As discussed in Note F to the Consolidated Financial Statements, we
incurred a $34 million nonrecurring pre-tax charge related to our
corporate restructuring over the third and fourth quarters of 1995.
Amounts excluding the restructuring charge were as follows:
Balance
Available Earnings
Operating Net for Common Per Average
Income Income Stock Common Share
- --------------------------------------------------------------------------
1995
- ----
Third quarter $107,779 $77,452 $73,562 $1.57
Fourth quarter 36,991 9,182 5,293 0.11
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 7 through 9 of the definitive proxy statement dated
March 26, 1997, 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 7 through 9 of
the definitive proxy statement dated March 26, 1997, 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 27 through 33 of the definitive proxy
statement dated March 26, 1997, 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 9 through
10 of the definitive proxy statement dated March 26, 1997, 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, 1996, 1995 and 1994 28
Consolidated Statements of Retained Earnings for the
years ended December 31, 1996, 1995 and 1994 28
Consolidated Balance Sheets as of December 31, 1996 and 1995 29
Consolidated Statements of Cash Flows for the years
ended December 31, 1996, 1995 and 1994 30
Notes to Consolidated Financial Statements 31
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 December 20, 1996, was filed during the fourth quarter of
1996 announcing that the Company reached a settlement agreement with the
Massachusetts Attorney General and the Massachusetts Division of Energy
Resources.
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
5 1/8% debentures due March 15, 1996, year ended
5.70% debentures due March 15, 1997, December 31,
5.95% debentures due March 15, 1998, 1992
6.80% debentures due March 15, 2003,
7.80% debentures due March 15, 2023
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
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 10.1 1-2301
Standard Form of Agreement, May Form 10-Q
1986 for the
quarter ended
June 30, 1986
10.1.1 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
10.3 1991 Director Stock Plan 10.1 1-2301
Form 10-Q
for the
quarter ended
March 31, 1991
10.4 Boston Edison Company Deferred 10.11 1-2301
Fee Plan dated January 14, 1993 Form 10-K
for the
year ended
December 31,
1992
58
Exhibit SEC Docket
------- ----------
10.5 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
10.5.1 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
10.6 Directors Retirement Benefit 10.8.1 1-2301
(1993 Plan) Form 10-K
for the
year ended
December 31,
1993
10.7 Performance Share Plan, Amendment 10.8 1-2301
and Restatement dated October 24, 1994 Form 10-K
for the
year ended
December 31,
1994
10.8 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
10.9 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
10.10 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
------- ----------
10.11 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
10.12 Form of Change in Control Agreement 10.3 1-2301
applicable to Ronald A. Ledgett, Form 10-Q
E. Thomas Boulette, L. Carl Gustin, for the
John J. Higgins, Douglas S. Horan quarter ended
and certain other officers dated June 30, 1996
July 8, 1996
Filed herewith:
10.13 Retention Agreement applicable to
Douglas S. Horan dated May 15, 1996
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, 1996
12.2 Computation of Ratio of Earnings
to Fixed Charges and Preferred Stock
Dividend Requirements for the Year
Ended December 31, 1996
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 MDPU Settlement Agreement with 28.1 1-2301
Boston Edison Company dated Form 8-K
October 3, 1989 dated
October 3, 1989
99.2 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
62
Exhibit SEC Docket
------- ----------
99.3 Pilgrim Outage Case Settlement between 28.2 1-2301
Boston Edison Company and Reading Form 8-K
Municipal Light Department regarding dated
Contract Demand Rate, dated December December 21,
21, 1989 1989
99.4 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
99.5 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, 1995, 1994 and 1993 Form 10-K for
the years ended
December 31,
1995, 1994 and
1993 dated
June 27,1996,
June 29, 1995
and June 30,
1994,
respectively
99.6 MDPU Settlement Agreement with 28.2 1-2301
Boston Edison Company, dated Form 10-Q
October 23, 1992 for the
quarter ended
September 30,
1992
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 27, 1997
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 27th day of March 1997.
/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/ William F. Connell Director
- ----------------------------------
William F. Connell
/s/ Gary L. Countryman Director
- ----------------------------------
Gary L. Countryman
/s/ Thomas G. Dignan, Jr. Director
- ----------------------------------
Thomas G. Dignan, Jr.
/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.
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, 1996 and 1995, and the consolidated results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
January 23, 1997