[DESCRIPTION] BOSTON EDISON COMPANY 1994 FORM 10-K
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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 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
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
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
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(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
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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 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. [ ]
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
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of February 28, 1995 computed by reference to the last reported
sale price of the common stock, $1 par value, of the registrant of the New
York Stock Exchange composite tape on that date: $1,117,923,951.
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 FEBRUARY 28, 1995
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Common Stock, $1 par value 45,629,549 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part Document
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III Portions of definitive proxy statement dated March 27, 1995 for Annual
Meeting of Stockholders to be held May 12, 1995.
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Boston Edison Company
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Form 10-K Annual Report
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December 31, 1994
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Part I Page
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Item 1. Business 2
Item 2. Properties and Power Supply 8
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 11
Part II
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Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 15
Item 6. Selected Financial Data 16
Item 7. Management's Discussion and Analysis 17
Item 8. Financial Statements and Supplementary Financial
Information 27
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 47
Part III
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Item 10. Directors and Executive Officers of the Registrant 48
Item 11. Executive Compensation 48
Item 12. Security Ownership of Certain Beneficial Owners and
Management 49
Item 13. Certain Relationships and Related Transactions 49
Part IV
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Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 50
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Part I
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Item 1. Business
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(a) General Development of Business
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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 demand side management (DSM) programs.
In 1993 the Company established an unregulated subsidiary, Boston Energy
Technology Group (BETG), following approval from the Massachusetts Department
of Public Utilities (DPU). The Company has authority to invest up to $45
million in this wholly-owned subsidiary. BETG engages in demand side
management activities and businesses involving electric transportation and the
related infrastructure through its two wholly-owned subsidiaries. In 1994
BETG acquired a substantial majority interest in two additional businesses.
REZ-TEK International Corporation produces systems that treat cooling water
used in commercial and industrial air conditioning systems in an energy
efficient and environmentally sound manner, and Coneco Corporation provides
engineering and project management services to energy and water conservation
project developers and contractors. The Company does not currently have a
substantial investment in BETG and does not expect the subsidiary to
significantly impact the results of operations in the next several years.
(b) Financial Information about Industry Segments
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The Company operates primarily as a regulated electric public utility,
therefore industry segment information is not applicable.
(c) Narrative Description of Business
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Principal Products and Services
The Company supplies electricity at retail to an area of 590 square miles
encompassing 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 1994 the Company served an average of 656,000 customers. The
Company also supplies electricity at wholesale for resale to other utilities
and municipal electric departments. Revenues by class for the last three
years consisted of the following:
1994 1993 1992
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Retail electric revenues:
Commercial 50% 49% 48%
Residential 28% 28% 27%
Industrial 9% 10% 10%
Other 2% 1% 2%
Wholesale and contract revenues 11% 12% 13%
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Sources and Availability of Fuel
The Company owns two stations whose generating units are fueled by oil,
natural gas or both, one nuclear power station and ten combustion turbine
generators. See the Company-Owned Facilities section of Item 2. 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)
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1994 1993 1992 1991 1990 1994 1993 1992 1991 1990
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Oil 27.8 31.3 33.7 42.8 33.6 2.35 2.38 2.40 2.60 2.76
Gas 31.6 24.3 25.7 24.9 33.3 2.28 2.67 2.55 2.08 2.35
Nuclear 40.6 44.4 40.6 32.3 33.1 0.50 0.51 0.52 0.56 0.59
==============================================================================
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.
Most 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 pipeline capacity is unavailable. Deliveries of natural gas
to the Company's generating units from suppliers may also be dependent on the
availability of pipeline capacity to the New England region and competitive
forces prevailing in the pipeline industry. Beginning in April 1995 the
Company will be required to operate New Boston Station using exclusively
natural gas as fuel, except in certain emergency circumstances, as part of a
1991 consent order with the Massachusetts Department of Environmental
Protection (DEP). The Company has made arrangements for a firm supply of
natural gas to run the station at a minimum level and is developing a least-
cost plan for operation beyond this minimum level involving principally the
utilization of interruptible gas supplies or short-term capacity purchases.
In order to obtain nuclear fuel for use at Pilgrim Station 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 1998, 2000, 1998 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 DPU. 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.
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Seasonal Nature of Business
The Company's kWh sales and revenues are typically higher in the winter and
summer than in spring and fall as sales tend to vary with weather conditions.
In addition, the Company bills higher base rates to commercial and industrial
customers during the billing months of June through September as mandated by
the DPU. Accordingly, a significant portion of annual earnings occurs in the
Company's third quarter. See Selected Consolidated Quarterly Financial Data
(Unaudited) in Item 8.
Working Capital Practices
The Company has no special practices with respect to working capital that
would be considered unusual for the electric utility industry or significant
for the understanding of the Company's business.
Customer Dependence
No material portion of the Company's business is dependent upon one or a few
customers.
Government Contracts
No material portion of the Company's business is subject to renegotiation or
termination of government contracts or subcontracts.
Competitive Conditions
The Company is operating in an increasingly competitive environment. The
electric utility business is in a period of transition from a traditional
rate-regulated environment based on cost recovery to an environment with both
competition and modified regulation. The effects of competition to date have
been most evident in the wholesale electric market. In response to increased
competition from other electric utilities and non-utility generators to sell
electricity for resale, the Company has secured long-term power supply
agreements with its five wholesale customers. These agreements set the
Company's rates through the year 2002 and beyond.
Direct competition with other electric utilities and other energy suppliers
for retail electricity sales is still subject to substantial limitations, but
there is potential for these limitations to be reduced in the future. The
Company and other Massachusetts electric utilities are currently protected in
several ways by the DPU and municipal statutes against other utilities
offering service to retail customers in their service areas. Another electric
utility may not extend its service area to include municipalities other than
those named in its agreement of association or charter without DPU
authorization granted after notice and public hearing. Also, another company
may not obtain an initial location for its lines in a municipality served by
the Company without the approval of municipal authorities, subject to the
right of appeal to the DPU. Additionally, a municipality may not engage in
the electric utility business without complying with statutes requiring
specific city or town approval and the purchase of Company property within
municipality limits.
However, the Company is currently experiencing some forms of competition in
the retail electric market. Current legislation allows industrial and large
commercial customers to own and operate their own electric generating units.
Retail customers may also substitute natural gas or oil for electricity as
fuel for heating and cooling purposes. Large facilities may factor the cost
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of electricity into their decisions to relocate into or out of a given service
territory. In addition, the DPU is currently investigating the benefits of
restructuring the electric utility industry in Massachusetts and encouraging
utilities to devise and propose incentive ratemaking plans. The Company is
responding to the current and anticipated retail competitive challenges in
several ways. These include actively participating in the formulation of
regulatory policy concerning potential stranded investments, planning to not
seek additional base rate increases for at least five years, continuing
aggressive control of costs and increasing operating efficiencies.
Research Activities
The Company actively participates in several industry-sponsored research
activities. These expenditures, included in other operations and maintenance
expense on the consolidated income statement in Item 8, were not material in
1994.
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 can require modification of
existing facilities or curtailment or termination of operations at these
facilities, 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. The Company believes that its operating facilities
are in substantial compliance with currently applicable statutory and
regulatory environmental requirements.
The Company's capital expenditures for environmental purposes during the five
years 1990 through 1994 totalled approximately $137 million. Environmental-
related capital expenditures for the years 1995 through 1999 are currently
expected to total approximately $47 million, including $11 million in both
1995 and 1996. These amounts exclude costs associated with asbestos removal
which totalled approximately $8 million during the five years 1990 through
1994 and are currently expected to total approximately $3 million for the
years 1995 through 1999. The Company's capital expenditures for environmental
purposes through 1994 included approximately $80 million related to certain
improvements in the emission control systems at New Boston Station as
discussed in the Environmental section of Other Matters in Item 7.
Substantial additional expenditures could be required as changes in
environmental requirements occur.
The Company is required to clean up 48 properties that it owns or operates in
which hazardous materials were released in the past. In addition, the Company
has exposure to potential joint and several liability for the cleanup of ten
multi-party hazardous waste sites where it is alleged to have generated,
transported or disposed of hazardous waste at the sites. Complex litigation
or negotiations among the parties and with regulatory authorities is in
process concerning the scope and cost of cleanup and the sharing of costs
among the potentially responsible parties for several of these sites. The
Company's potential hazardous waste liabilities are described further in the
Environmental section of Item 7.
Spent nuclear fuel and low-level radioactive waste (LLW) result from the
operations of Pilgrim Station. Uncertainties currently exist regarding the
ultimate disposal of both the spent nuclear fuel and LLW. See Note D to the
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consolidated financial statements in Item 8 for further discussion regarding
spent nuclear fuel and LLW.
As a facility which treats and stores hazardous wastes, Pilgrim Station is
required to be licensed by the United States Environmental Protection Agency
(EPA). Pilgrim has received interim status approval for the treatment and
storage of certain wastes that are both hazardous and radioactive.
The Company is subject to regulation by the EPA and the DEP relative to
emissions from its fossil-fired generating units under federal and
Massachusetts clean air laws, including the 1990 Clean Air Act Amendments.
These regulations require the installation of various emissions controls and,
in certain cases, the use of low sulfur content fuels. The Company's current
status regarding compliance with DEP regulations and the 1990 Clean Air Act
Amendments is discussed in the Environmental section of Item 7.
The Company is also subject to regulation by the EPA and the DEP with respect
to discharges of effluent from its generating stations into receiving waters.
The federal Clean Water Act and the Massachusetts Clean Waters Act require the
Company to receive permits that limit discharges in accordance with applicable
water quality standards and are subject to renewal every five years. The
Company has received the required discharge permits for each of its electric
generating stations.
There are public concerns regarding electromagnetic fields (EMF) associated
with electric transmission and distribution facilities and appliances and
wiring in buildings and homes. These concerns include the possibility of
adverse health effects as well as perceived effects on property values. Refer
to the Environmental section of Item 7 for a discussion of the EMF issue.
Number of Employees
The Company had 4,026 full-time and 25 part-time utility employees as of the
end of 1994, 2,560 of which are represented by two locals of the Utility
Workers Union of America, AFL-CIO. In 1994 the Company and the locals signed
new six-year labor contracts. BETG had 46 full-time employees at the end of
1994.
(d) Financial Information about Foreign and Domestic Operations and Export
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Sales
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See Principal Products and Services for information regarding the geographical
area served by the Company and revenues by class for the last three years.
(e) Additional Information
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Regulation
The Company and its wholly-owned subsidiary, Harbor Electric Energy Company
(HEEC), operate primarily under the authority of the DPU, whose jurisdiction
includes supervision over retail rates for electricity, financing, investing
and accounting. In addition, the Federal Energy Regulatory Commission 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 such 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.
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The Company is required to submit to the DPU annual performance standards
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
DPU. The DPU 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 has not yet received orders from the DPU for the performance years
ended October 1993 and October 1994. 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 was issued in
1972 and 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 domestic nuclear plants,
including Pilgrim Station. NRC inspections and investigations can result in
the issuance of notices of violation. These notices can also be accompanied
by orders directing that certain actions be taken or by the imposition of
monetary civil penalties. In addition, the Company could undertake certain
actions regarding Pilgrim Station at the request or suggestion of its insurers
or the Institute of Nuclear Power Operations (INPO), a voluntary association
of nuclear utilities dedicated to the promotion of safety and reliability in
the operation of nuclear power plants.
Nuclear power continues to be a subject of political controversy and public
debate manifested from time to time in the form of requests for various kinds
of federal, state and local legislative or regulatory action, direct voter
initiatives or referenda or litigation. The Company cannot predict the
extent, cost or timing of any modifications to Pilgrim Station which could be
necessary in the future as a result of additional regulatory or other
requirements nor can it determine the effect of such future requirements on
the continued operation of Pilgrim Station. The Company continues to evaluate
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 expenditures, allowance for
funds used during construction (AFUDC), long-term debt maturities and sinking
fund requirements for the years 1995 through 1999 are as follows:
(in thousands) 1995 1996 1997 1998 1999
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Plant
expenditures $200,000 $172,000 $172,000 $159,000 $156,000
Nuclear fuel
expenditures 11,000 18,000 13,000 24,000 13,000
AFUDC (1) 6,000 5,000 4,000 5,000 4,000
Long-term debt 100,600 101,600 101,600 101,600 1,600
Preferred stock
sinking fund 2,000 2,000 2,000 2,000 2,000
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<FN>
(1) Excludes estimated AFUDC on nuclear fuel of approximately $1,000 per
year. The estimated AFUDC rate varies from 5.0% to 6.5%.
The Company conducts a continuing review of its capital expenditure and
financing programs. These programs and the estimates shown above are
therefore subject to revision due to changes in regulatory requirements,
environmental standards, availability and cost of capital, interest rates and
other assumptions. In addition, depending upon the outcome of certain DEP air
quality modeling studies currently in progress, the Company could be required
to make additional expenditures by 1999 in order to comply with the provisions
of the 1990 Clean Air Act Amendments. The extent of any additional
expenditures is uncertain at this time.
Plant expenditures in 1994 were approximately $199 million consisting
primarily of additions to the Company's distribution system and fossil and
nuclear generation facilities. Significant projects included spending of
approximately $13 million for the replacement of electric system property,
$10.5 million for a new energy control center, $10 million for a new
substation and $9 million for the replacement of the main turbine low pressure
rotors at Pilgrim Station.
The Company spent approximately $58 million on its DSM programs in 1994, of
which $37 million was capitalized and is being collected from customers over
six years. DSM expenditures for 1995 are currently estimated to be
approximately $43 million. Beginning in 1995 all costs will be collected
primarily in the year incurred in accordance with an order from the DPU.
In 1994 the DPU approved the Company's financing plan to issue up to $500
million of securities through 1996 and to use the proceeds to refinance short
and long-term securities and for capital expenditures. See Note H to the
consolidated financial statements in Item 8 for specific information relating
to the Company's financing activities.
Item 2. Properties and Power Supply
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Company-Owned Facilities
The Company's total electric generation capacity as of December 31, 1994
consisted of the following:
Maximum
Capacity Year
Unit Location (MW) Type Installed
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Pilgrim Nuclear Plymouth, Mass. 669 Nuclear 1972
Power Station
New Boston Station South Boston, Mass. 760 Fossil 1965-1967
Units 1 and 2
Mystic Station Everett, Mass.
Units 4-5-6 399 Fossil 1957-1961
Unit 7 592 Fossil 1975
Combustion turbine Various 302 Fossil 1966-1971
generators (ten)
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All of the Company's steam fossil fuel-fired generating units are located at
tide water and have access to fuel oil storage and/or natural gas or oil
pipelines from nearby suppliers.
The Company is also a 5.888% joint owner in 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 non-utilities 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 certain service centers and are generally located on
Company-owned land. The Company's high-tension transmission lines are
generally located on land either owned by the Company 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, 1994 the Company's transmission system consisted of 362
miles of overhead circuits operating at 115, 230 and 345 kV and 156 miles of
underground circuits operating at 115 and 345 kV. The substations supported
by these lines are 44 transmission or combined transmission and distribution
substations with transformer capacity of 10,112 megavolt amperes (MVA), 70
distribution substations with transformer capacity of 1,213 MVA and 18 primary
network units with 88 MVA capacity. In addition, high tension service was
delivered to 231 customers' substations. The overhead and underground
distribution systems cover 4,652 and 892 miles of streets, respectively.
HEEC, the Company's regulated subsidiary, has a distribution system that
consists principally of a 4.1 mile 115kV submarine distribution line and a
substation which is located on Deer Island in Boston, Massachusetts.
The Massachusetts Energy Facilities Siting Board (EFSB) must approve Company
plans for the construction of certain new generation or transmission
facilities based upon findings that such facilities are consistent with state
public health, environmental protection and resource use and development
policies. The Company currently has no proceedings before the EFSB.
Long-Term Power Contracts
Refer to Note L to the consolidated financial statements in Item 8 for further
information regarding the following contracts. The Company also has short-
term agreements with several other utilities for varying periods for purchases
of system and unit power, for sales of Company system and unit power and for
transmission services.
Utility Purchase Contracts:
--------------------------
The Company has a long-term contract with a subsidiary of Commonwealth Energy
System in which it receives 25% of the output of an oil-fired electric
generating plant. The Company is obligated to pay 25% of the unit's fixed and
operating costs plus an annual return on investment.
The Company has two long-term purchased power contracts with the Massachusetts
Bay Transportation Authority (MBTA) for the availability of two of the MBTA's
jet turbines. The MBTA retains the right to utilize the jets for its own
emergency use and for testing purposes while the Company retains New England
Power Pool credit for their capacity and output.
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The Company owns 9.5% of the common stock of Connecticut Yankee Atomic Power
Company, which operates a nuclear generating unit. The Company is entitled to
receive 9.5% of the unit's output and is obligated to pay Connecticut Yankee
9.5% of its fixed and operating costs plus an annual return on investment.
Non-Utility Generator Purchase Contracts:
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The Company currently purchases 535 MW of capacity and associated energy from
non-utility generators. These purchases are from Ocean State Power, Northeast
Energy Associates, L'Energia and MassPower. In addition, the Company
purchases power from two small hydro facilities.
In March 1995 the Company received a decision from the Massachusetts Supreme
Judicial Court (SJC) regarding the Company's appeal of a 1994 DPU order that
reaffirmed a 1993 order requiring it to purchase power from an independent
power producer (see Resource regulation in Item 7). The SJC decision reversed
the DPU order and remanded the case to the department for further
consideration of evidence.
Sales Contracts:
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The Company has agreements with Commonwealth Electric Company, a subsidiary of
Commonwealth Energy System, and with Montaup Electric Company, a subsidiary of
Eastern Utilities Associates, under which Commonwealth and Montaup 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. Commonwealth and Montaup have also agreed to indemnify the
Company to the extent of 11% each of all losses, liability or damage not
covered by insurance resulting from the operation, condemnation, shutdown or
retirement of the unit. In addition, 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 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.
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The table below sets forth certain information as of the date of the Company's
1994-1995 winter and 1994 summer peak loads:
February 6, 1995 July 21, 1994
(winter 1994-95) (summer 1994)
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NEPEX utilities installed capacity:
Seasonal maximum rating 25,645 MW 24,602 MW
Seasonal normal rating 25,299 MW 24,379 MW
NEPEX peak load (estimate) 19,205 MW 20,519 MW
Company territory peak load 2,473 MW 2,798 MW
==============================================================================
The Company's net capacity was 3,561 MW at its winter peak and 3,484 MW at its
summer peak. Its corresponding NEPOOL capacity obligations were estimated to
be 3,379 MW and 3,306 MW, respectively.
NEPOOL participants have two agreements with Hydro-Quebec of Canada for hydro-
electric power. The first agreement, Phase I, provides up to three million
MWH of hydro-electric power to NEPOOL annually through 1997. The second
agreement, Phase II, is a firm contract that provides seven million MWH of
hydro-electric power annually through 2001. The price of the Phase II energy
is based on the average cost of fossil fuel in New England for the previous
year. The contract price is 80% of that average through 1996 and will be 95%
of that average in 1997-2001. The Company receives capacity credit through
NEPOOL for approximately 11% of the generation equivalent of the total Hydro-
Quebec interconnection.
The Company has an approximately 11% equity ownership interest in the two
companies which own and operate the Phase II facilities. All equity
participants are required to guarantee, in addition to their own share, the
total obligations of those participants who do not meet certain credit
criteria. Amounts so guaranteed by the Company were approximately $21 million
at December 31, 1994.
Item 3. Legal Proceedings
--------------------------
In 1991 the Company was named in a lawsuit brought in the United States
District Court for the District of Massachusetts alleging discriminatory
employment practices under the Age Discrimination in Employment Act of 1967
concerning 46 employees affected by the Company's 1988 reduction in force.
Legal counsel continues to vigorously defend this case. Based on the
information presently available the Company does not expect that this
litigation or certain other legal matters in which it is currently involved
will have a material impact on financial condition. However, an unfavorable
decision ordered against the Company could have a material impact on the
results of a reporting period.
See also Environmental Matters in Item 1 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 1994.
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Executive Officers of the Registrant
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The names, ages, positions and business experience during the last five years
of all the executive officers of Boston Edison Company and its subsidiaries as
of March 1, 1995 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 officer
was elected. 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, 47 Chairman of the Board and Chief
Chairman of the Board and Executive Officer (since 1994),
Chief Executive Officer formerly President and Chief
Operating Officer (1993-1994),
Executive Vice President (1990-
1993) and Senior Vice President
(1987-1990). Director (since
1991). Chairman of the Board
and Chief Executive Officer and
Director, Harbor Electric Energy
Company and Boston Energy
Technology Group; Chairman of the
Board and Chief Executive Officer,
TravElectric Services Corp. and
Ener-G-Vision, Inc.; Chairman of
the Board, REZ-TEK International
Corp. and Coneco Corp.
George W. Davis, 61 President and Chief Operating
President and Chief Officer (since 1994), formerly
Operating Officer Executive Vice President (1992-
1994), responsible for all
power supply and delivery
operations, Senior Vice President
- Nuclear (1990-1992) and Vice
President - Nuclear Administration
(1989-1990). Director (since
1991). President and Director,
Harbor Electric Energy Company and
Boston Energy Technology Group;
Director, TravElectric Services
Corp. and Ener-G-Vision, Inc.
12
14
Business Experience
Name, Age and Position During Past Five Years
---------------------- ----------------------
E. Thomas Boulette, 52 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.
Cameron H. Daley, 49 Senior Vice President - Power
Senior Vice President - Power Supply Supply (since 1989).
L. Carl Gustin, 51 Senior Vice President - Marketing
Senior Vice President - Marketing & & Corporate Relations (since
Corporate Relations 1989).
John J. Higgins, Jr., 62 Senior Vice President - Human
Senior Vice President - Human Resources Resources (since 1990) and Vice
President - Human Resources (1988-
1990).
Ronald A. Ledgett, 56 Senior Vice President - Power
Senior Vice President - Power Delivery Delivery (since 1991) and
Director, Special Projects
(1989-1991).
Charles E. Peters, Jr., 43 Senior Vice President - Finance
Senior Vice President - Finance (since 1991), formerly Chief
Financial Officer and Senior Vice
President of Genrad, Inc. (1985-
1991). Senior Vice President,
Treasurer and Director, Harbor
Electric Energy Company and
Boston Energy Technology
Group; Director, TravElectric
Services Corp., Ener-G-Vision,
Inc., REZ-TEK International Corp.
and Coneco Corp.
Marc S. Alpert, 50 Vice President and Treasurer
Vice President and Treasurer (since 1988). Assistant
Treasurer, Harbor Electric Energy
Company and Boston Energy
Technology Group.
13
15
Business Experience
Name, Age and Position During Past Five Years
---------------------- ----------------------
Robert J. Weafer, Jr., 48 Vice President, Controller and
Vice President, Controller and Chief Chief Accounting Officer (since
Accounting Officer 1991). Controller (1988-1991) and
Chief Accounting Officer (1983-
1991).
Theodora S. Convisser, 47 Clerk of the Corporation (since
Clerk of the Corporation 1986). Clerk of Harbor Electric
Energy Company, Boston Energy
Technology Group, TravElectric
Services Corp., Ener-G-Vision,
Inc., REZ-TEK International
Corp. and Coneco Corp.
Douglas S. Horan, 45 Vice President and General Counsel
Vice President and (since 1994), formerly Deputy
General Counsel General Counsel (1991-1994) and
Associate General Counsel (1986-
1991). General Counsel of Harbor
Electric Energy Company.
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16
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 are the reported high and low sales prices of the Company's common
stock on the New York Stock Exchange as reported daily in the Wall Street
Journal for each of the quarters in 1994 and 1993:
1994 1993
------------------------------------------------------------------------------
High Low High Low
------------------------------------------------------------------------------
First quarter $29 7/8 $26 $30 1/2 $26 3/8
Second quarter 29 1/8 25 1/4 30 7/8 27 7/8
Third quarter 27 5/8 22 3/4 32 5/8 29 3/4
Fourth quarter 24 1/4 21 1/2 32 1/4 27 7/8
==============================================================================
(b) Holders
-----------
As of December 31, 1994, the Company had 39,904 holders of record of its
common stock (actual count of record holders).
(c) Dividends
-------------
Following are the dividends declared per share of common stock for each of the
quarters in 1994 and 1993:
1994 1993
----------------------------------------------------------------------
First quarter $0.440 $0.425
Second quarter 0.440 0.425
Third quarter 0.440 0.425
Fourth quarter 0.455 0.440
======================================================================
(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, 1994:
Ratio of earnings to fixed charges 2.45
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.07
15
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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).
1994 1993 1992 1991 1990
---------------------------------------------------------------------------
Operating
revenues $1,548,554 $1,482,253 $1,411,753 $1,354,501 $1,314,440
Net income 125,022 118,218 107,298 94,670 79,616(a)
Earnings per
common share 2.41 2.28 2.10 1.96 1.60(a)
Total assets 3,616,610 3,477,288 3,294,234 3,119,285 3,012,589
Long-term
debt 1,136,617 1,272,497 1,091,073 1,136,765 1,074,025
Redeemable
preferred/
preference
stock 219,000 221,000 221,000 221,333 221,333
Cash dividends
declared per
common share 1.775 1.715 1.655 1.595 1.535
============================================================================
<FN>
(a) Before cumulative effect of change in accounting principle ($15,824 or
$0.41 per common share).
16
18
Item 7. Management's Discussion and Analysis
--------------------------------------------
REGULATORY PROCEEDINGS
Retail settlement agreements
In 1992 our state regulators, the Massachusetts Department of Public
Utilities, approved a three-year settlement agreement effective November 1992.
This agreement provided us with retail rate increases, allowed for the
recovery of demand side management (DSM) conservation program costs, specified
certain accounting adjustments and clarified the timing and recognition of
certain expenses. The agreement also set a limit on our rate of return on
common equity of 11.75% for 1993 through 1995, excluding any penalties or
rewards from performance incentives.
The retail rate increases consisted of a new annual performance adjustment
charge effective November 1992 and two annual base rate increases of $29
million effective November 1993 and November 1994. The performance adjustment
charge varies annually based upon the performance of our Pilgrim Nuclear Power
Station. This charge is further described in our discussion of financial
condition.
In addition to the retail rate increases, our results of operations were
affected by the recovery of DSM program costs, accounting adjustments and the
timing and recognition of certain expenses as further described in the
following Results of Operations section.
Our state regulators previously approved a three-year settlement agreement
effective November 1989. That agreement also provided us with retail rate
increases and specified certain accounting adjustments. The 1989 agreement
primarily affected our results of operations through 1992.
We do not currently plan to make a base rate filing upon the expiration of the
1992 settlement agreement, therefore we anticipate that base rates will remain
in effect at their current levels.
RESULTS OF OPERATIONS
1994 versus 1993
Earnings per common share were $2.41 in 1994 and $2.28 in 1993. The increase
in earnings was primarily the result of the expiration of a long-term
purchased power contract in October 1993, a retail base rate increase
effective November 1993, a 2.0% increase in retail kWh sales and an award
relating to an eminent domain case. These positive changes were partially
offset by higher operations and maintenance, depreciation and amortization and
income tax expenses.
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19
Operating revenues
Operating revenues increased 4.5% over 1993 as follows:
(in thousands)
------------------------------------------------------
Retail electric revenues $62,945
Demand side management revenues 5,056
Wholesale and other revenues (2,919)
Short-term sales revenues 1,219
------------------------------------------------------
Increase in operating revenues $66,301
======================================================
Retail electric revenues increased $63 million. The November 1993 and 1994
base rate increases resulted in $28.6 million of the increased revenues and
approximately $6 million was due to the 2% increase in retail sales. Fuel and
purchased power revenues increased $28.5 million primarily due to the recovery
of certain new purchased power expenses. In accordance with the 1992
settlement agreement specific revenues related to the purchased power contract
that expired in October 1993 were not affected.
The decrease in wholesale and other revenues is primarily due to an estimated
provision for refunds to wholesale customers due to contract issues.
Operating expenses
Total fuel and purchased power expenses decreased $27 million. Fuel expense
decreased partly due to lower fossil fuel prices and a 12% decrease in nuclear
output. Purchased power expense reflects lower costs associated with the
long-term contract that expired in October 1993, partially offset by the costs
of new contracts. The timing effect of fuel and purchased power cost
collection also contributed to the decrease in fuel and purchased power
expenses. Fuel and purchased power expenses are substantially all recoverable
through fuel and purchased power revenues.
Other operations and maintenance expense increased 8.7% primarily due to
higher employee benefit expenses. Pension expense increased $20 million due
to a higher contribution made to the pension plan for the year. In accordance
with the 1992 settlement agreement, we record pension expense in the amount of
the contribution to the plan.
Depreciation and amortization expense increased primarily due to a higher
depreciable plant balance. In 1994 we fully expensed the remaining deferred
costs of the cancelled Pilgrim 2 nuclear unit. In accordance with the 1992
settlement agreement we did not expense any of these costs in 1993.
Amortization of deferred nuclear outage costs consists of amounts related to
the 1993 and 1991 refueling outages at Pilgrim Station. In 1993 we deferred
approximately $14 million of refueling outage costs. We began to amortize
these costs in June 1993 over five years as approved in the 1992 settlement
agreement.
The $2 million decrease in demand side management programs expense was due to
the timing of recovery of program costs. DSM expense includes some program
costs recovered over twelve months and other program costs recovered over six
years. The 1994 expense consists of $22 million of costs primarily related to
1994 expenditures and $13 million of costs capitalized in 1992 through 1994.
Municipal property and other taxes increased primarily as a result of higher
Boston property taxes due to a tax rate increase and capital additions.
18
20
Our effective annual income tax rate for 1994 was 31.4% vs. 23.4% for 1993.
Both rates were reduced by adjustments to deferred income taxes of $10 million
in 1994 and $20 million in 1993 made in accordance with the 1992 settlement
agreement. No further deferred income tax adjustments may be made and we
expect our effective tax rate to be close to the statutory rate in 1995.
Other income
In November 1994 a court ruling became effective providing us with an
additional $5.7 million gain on a 1989 eminent domain taking of our property.
Interest charges
Interest charges in total did not change significantly. Interest charges on
long-term debt decreased due to the first mortgage bond and debenture
redemptions in 1994 and the significant first mortgage bond refinancing in
1993 at lower interest rates. This decrease was partially offset by higher
amortization of redemption premiums. Other interest charges increased due to
higher short-term interest rates partially offset by a lower average short-
term debt level. Allowance for borrowed funds used during construction
(AFUDC), which represents the financing costs of construction, increased as a
result of a higher AFUDC rate related to higher short-term interest rates.
1993 versus 1992
Earnings per common share were $2.28 in 1993 and $2.10 in 1992. The increase
in earnings was primarily the result of a retail rate increase effective
November 1992, the expiration of a long-term purchased power contract in
October 1993, no amortization of deferred cancelled nuclear unit costs and
lower interest expense. These positive changes were partially offset by
higher operations and maintenance, income tax and property tax expenses.
Operating revenues
Operating revenues increased 5.0% over 1992 as follows:
(in thousands)
------------------------------------------------------
Retail electric revenues $70,837
Demand side management revenues 33,601
Wholesale and other revenues (2,794)
Short-term sales revenues (31,144)
------------------------------------------------------
Increase in operating revenues $70,500
======================================================
Retail electric revenues increased $71 million. The November 1992 and 1993
rate increases resulted in $40.6 million of additional revenues in 1993. Fuel
and purchased power revenues increased $29.5 million over 1992 primarily due
to the timing effect of fuel and purchased power cost collection and lower
revenues received from short-term power sales as discussed below.
We began recovery of certain demand side management program costs, lost base
revenues and incentives in August 1992. Our 1993 revenues provided $45.9
million related to 1991, 1992 and 1993 DSM programs. Our 1992 revenues of
$12.3 million related primarily to 1991 programs.
The decrease in wholesale and other revenues reflects an estimated provision
for refunds to customers of $8.6 million in 1993 as a result of orders from
our state regulators on our generating unit performance program.
19
21
Lower short-term power sales revenues were a result of changes in our
generation availability and the needs of short-term power purchasers.
Revenues from short-term sales serve to reduce fuel and purchased power
billings to retail customers and therefore have no effect on earnings.
Operating expenses
Total fuel and purchased power expenses decreased $12 million. Fuel expense
decreased primarily due to a 21.5% decrease in fossil generation and an 8.5%
decrease in nuclear generation, resulting from planned plant overhauls and a
nuclear refueling outage. Purchased power expense reflects both higher
interchange purchases, caused by the lower generation, and lower costs
associated with the long-term contract that expired in October 1993. The
decreases in expense were partially offset by the timing effect of fuel and
purchased power cost collection.
Other operations and maintenance expense increased 7.1% primarily due to
increases in employee benefits and nuclear production expenses.
Postretirement benefits expense increased by $7 million primarily as a result
of the adoption of a new accounting standard and pension expense increased by
$5 million; both are provided for in our 1992 settlement agreement and further
explained in Note E to the consolidated financial statements. A refueling
outage at Pilgrim Station in 1993 resulted in higher nuclear production
expenses.
Depreciation and amortization expense increased in 1993 primarily due to a
higher annual decommissioning charge for Pilgrim Station effective November
1992 provided by the 1992 settlement agreement. The charge is based on a 1991
estimate of decommissioning costs as further discussed in Note D to the
consolidated financial statements. In addition, the effect of lower
depreciation rates implemented in accordance with the settlement agreement was
offset by the effect of a higher depreciable plant balance.
In accordance with our 1992 settlement agreement we did not expense any of the
$19 million of remaining deferred costs associated with the cancelled Pilgrim
2 nuclear unit in 1993.
Amortization of deferred nuclear outage costs consists of amounts related to
the 1993 and 1991 refueling outages at Pilgrim Station as discussed in the
results of operations for 1994 versus 1993.
The increase in demand side management programs expense is consistent with the
increase in DSM revenues. DSM expense includes some costs recovered over
twelve months and other costs recovered over six years. We began to recover
previously deferred DSM expenses in August 1992. In 1993 we expensed and
collected from customers approximately $30 million of deferred 1991, 1992 and
1993 program costs. Over six years we are expensing and collecting from our
customers $11 million of costs capitalized in 1992 and $37 million of costs
capitalized in 1993. The 1993 expense related to these capitalized costs was
$7 million.
Municipal property and other taxes increased in 1993 due to the absence of tax
abatements. In 1992 property taxes were reduced by $10.4 million of tax
abatements in accordance with our 1989 settlement agreement.
Our effective annual income tax rate for 1993 was 23.4% vs. 8.7% for 1992.
Both rates were significantly reduced by adjustments to deferred income taxes
of $20 million in 1993 and $23 million in 1992 made in accordance with the
1992 and 1989 settlement agreements. The 1992 rate was also reduced due to
20
22
tax benefits of approximately $7 million resulting from mandated payments made
in accordance with the 1989 agreement. Our adoption of a new accounting
standard for income taxes in 1993 did not significantly affect earnings.
Interest charges and preferred and preference dividends
Total interest charges decreased $4 million in 1993. Interest on long-term
debt decreased primarily due to the refinancing of substantially all our first
mortgage bonds in 1993 at lower interest rates, partially offset by higher
amortization of redemption premiums. Other interest charges decreased due to
a lower short-term debt level and lower short-term interest rates. AFUDC
decreased as a result of a lower AFUDC rate related to lower short-term
interest rates.
Preferred and preference dividends decreased 5.1% due to the replacement of a
preferred and a preference stock issue with less costly issues of preferred
stock.
FINANCIAL CONDITION
Our 1992 settlement agreement is providing us with increased revenues from
retail customers over the three-year period ending October 1995.
Additionally, a significant long-term purchased power contract expired in
October 1993 with no change in related revenues. The settlement agreement
also limits the annual rate of return on equity during the three-year period
to 11.75%, excluding any penalties or rewards from performance incentives.
Our ability to achieve or exceed the 11.75% rate of return on equity is
primarily dependent upon our ability to control costs and to earn performance
incentives from generation performance mechanisms. The most significant
impact that incentives can have on our financial results is based on Pilgrim
Station's annual capacity factor. An annual capacity factor between 60% and
68% would provide us with approximately $47 million of revenues in the
performance year ended October 1995. For each percentage point increase in
capacity factor above 68%, annual revenues will increase by approximately
$690,000. For each percentage point decrease in capacity factor below 60% (to
a minimum of 35%), annual revenues will decrease by approximately $790,000.
Pilgrim's capacity factor for the performance year ending October 1995 is
currently expected to be approximately 69%, a decrease from the 72% capacity
factor achieved in the performance year ended October 1994, primarily due to
the refueling outage scheduled for 1995. We earned approximately $47 million
in revenues related to Pilgrim's capacity factor in the performance year ended
October 31, 1994.
Pilgrim Station automatically shut down in August 1994 as a result of a non-
nuclear problem with its electrical generator. The plant returned to service
three months later following the completion of necessary repairs as well as
maintenance work originally scheduled for an October 1994 mid-cycle outage.
The power needs usually met by the station were met by our other generating
plants or purchased from other suppliers as necessary. We do not believe that
the generator damage resulted from actions within our control, however, our
recovery of the incremental purchased power costs during the outage through
fuel and purchased power revenues is subject to review by our state regulators
under our generating unit performance program.
As discussed in Regulatory Proceedings, we do not plan to make a base rate
filing with our state regulators upon the expiration of the 1992 settlement
agreement, therefore we anticipate that our base rates will remain in effect
at their current levels.
21
23
LIQUIDITY
We meet our capital expenditure cash requirements primarily with internally
generated funds. These funds provided for 98%, 76% and 88% of our plant and
nuclear fuel expenditures in 1994, 1993 and 1992, respectively. Our current
estimate of plant expenditures for 1995 is $200 million. These expenditures
will be used primarily to maintain and improve existing transmission,
distribution and generation facilities. We do not expect plant expenditures
to vary significantly from the 1995 amount in the four years thereafter. We
have long-term debt and preferred stock payment requirements of $102.6 million
in 1995, $103.6 million per year in 1996 through 1998 and $3.6 million in
1999.
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 currently have authority from our federal regulators
to issue up to $350 million of short-term debt. We 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, 1994 we had $215 million of short-term
debt outstanding, none of which was incurred under the revolving credit
agreement. In 1994 our state regulators approved our financing plan to issue
up to $500 million of securities through 1996. The proceeds will be used to
refinance short and long-term securities and for capital expenditures. Refer
to Note H to the consolidated financial statements for specific information
relating to our recent financing activities.
OUTLOOK FOR THE FUTURE
Electricity sales
A significant portion of our electricity sales are made to commercial
customers rather than industrial customers. As a result our sales have been
only moderately impacted by the unfavorable economic factors affecting the
manufacturing industry in Massachusetts, including defense cutbacks and
continued downsizing in the computer industry. Increased sales to commercial
customers more than offset the decrease in sales to industrial customers as
economic factors provided growth in the commercial sector in 1994. Total
retail sales increased 2% in 1994.
Implementation of DSM programs, which are designed to assist customers in
reducing electricity use, will result in lower growth in electricity sales.
We receive approval from our state regulators for annual DSM spending levels
and recovery amounts. Through 1994 we collected from customers certain DSM
program costs primarily in the year incurred and other DSM program costs over
a six-year period. We are also provided with incentives and recovery of lost
revenues based on the actual reduction in customer electricity usage from
these programs and a return on the costs that we recover over six years.
Beginning in 1995 all costs are expected to be collected primarily in the year
incurred. We will continue to recover the DSM costs capitalized during 1992
through 1994 along with a return on investment on the unrecovered balance.
Competition
The electric utility business is in a period of transition from a traditional
rate-regulated environment based on cost recovery to an environment with both
competition and modified regulation. The effects of competition to date have
been most evident in the wholesale electric market. In response to increased
22
24
competition from other electric utilities and non-utility generators to sell
electricity for resale, we have secured long-term power supply agreements with
our five wholesale customers. These agreements set our rates through the year
2002 and beyond.
We are also beginning to face some forms of competition in the retail electric
market. This is happening as industrial and large commercial customers pursue
their options to generate their own electric power, as customers look to
obtain lower electricity prices and to substitute natural gas or oil for
electricity for heating or cooling purposes and as large facilities factor the
cost of electricity into their decisions to relocate into or out of a given
service territory. In the future, the potential exists for electric utilities
and other energy suppliers to sell electricity to retail customers of other
electric utilities without regard for existing service territories. In
addition, our state regulators are currently investigating two issues related
to the onset of competition, incentive regulation and industry restructuring.
We are responding to the current and anticipated retail competitive challenges
in several ways. We do not plan on seeking any additional base rate increases
until at least the year 2000 and are working to accomplish this by controlling
costs and increasing operating efficiencies without sacrificing quality of
service or profitability. During 1994 we reduced our workforce by 8.4%, we
negotiated six-year contracts with our two union locals which resulted in
cost-saving changes and limits wage growth and we implemented various other
cost control strategies. We also developed customer alliances and provided
economic development rates to some customers. In addition, we filed with our
state regulators for approval of lower rates for a small number of large
manufacturing customers on a limited basis. These actions all signify our
commitment to be a competitively priced, reliable provider of energy. We are
also actively participating in regulatory and legislative discussions and
proceedings concerning the future structure of the electric utility industry.
We do not expect the economic development rates or the proposed lower
manufacturing customer rates to have a significant impact on our financial
condition or results of operations.
As a regulated company, we are subject to certain accounting rules that are
not applicable to other businesses and industries. These accounting rules
allow regulated companies, as appropriate, to record certain costs as
regulatory assets instead of expenses when they are incurred. These
regulatory assets are expected to be recovered from customers through future
rates. The effects of competition or changes in regulation could ultimately
cause us to no longer be able to follow these accounting rules, in which case
our regulatory assets would have to be fully expensed at that time.
Resource regulation
Our state regulators require utilities to purchase power from qualifying non-
utility generators at prices set through a bidding process. In 1993 our state
regulators ordered us to purchase 132 megawatts of power from an independent
power producer, Altresco Lynn, LP, starting as early as 1995. We oppose this
order since we do not believe we need any new power for several years. We
asked the Massachusetts Supreme Judicial Court (SJC) to reverse the order and
in 1994 the SJC remanded the case to our state regulators for further
consideration. Our regulators then issued an order requiring us to negotiate
a contract with Altresco Lynn. We filed an appeal of this order with the SJC
in October 1994 and are currently awaiting a decision. In addition, we
supported an appeal filed by other parties of a state regulatory body's
conditional approval of construction of Altresco Lynn's generating station
project. In January 1995 the SJC reversed the regulator's approval on the
23
25
basis that there was no showing of need for the project in Massachusetts prior
to 2000.
We are also subject to our state regulators' integrated resource management
(IRM) process in which electric utilities forecast their future energy needs
and propose how they will meet those needs by balancing conservation programs
with all other supplies of energy. We submitted an IRM filing in 1994 and
received a favorable ruling in January 1995. Our regulators found that we do
not have a need for additional resources through 2001 and we are not required
to issue a competitive request for proposal for new generating capacity at
this time. We are required to update our IRM filing in January 1996.
Non-utility business
In 1993 we created an unregulated subsidiary, Boston Energy Technology Group
(BETG), following approval from our state regulators. We have authority to
invest up to $45 million in this wholly-owned subsidiary. BETG engages in
demand side management activities and businesses involving electric
transportation and the related infrastructure through two wholly-owned
subsidiaries. In 1994 BETG acquired a substantial majority interest in two
additional businesses. REZ-TEK International Corp. produces systems that
treat cooling water used in commercial and industrial air conditioning systems
in an energy efficient and environmentally sound manner, and Coneco
Corporation provides engineering and project management services to energy and
water conservation project developers and contractors. These acquisitions
were not material.
We do not currently have a substantial investment in BETG and do not
anticipate it significantly impacting our results of operations in the next
several years.
OTHER MATTERS
Environmental
We are subject to numerous federal, state and local standards with respect to
waste disposal, air and water quality and other environmental considerations.
These standards can require that we modify our existing facilities or incur
increased operating costs.
We own or operate 48 properties where hazardous materials were released in the
past. We are required to clean up these properties in accordance with a
timetable developed by the Massachusetts Department of Environmental
Protection (DEP) 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 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 we currently expect to have only a small percentage of the
potential liability. Through December 31, 1994, 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 expect any such additional costs to have a material
impact on our financial condition. However, additional provisions for cleanup
costs could have a material impact on our results of a reporting period.
24
26
Uncertainties continue to exist with respect to the disposal of both low-level
radioactive waste (LLW) and spent nuclear fuel resulting from the operation of
Pilgrim Station. In July 1994 our access to off-site LLW disposal facilities
ended. Until access is attained to other disposal facilities we are managing
LLW through on-site storage. 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. Refer to Note D to the consolidated financial statements for
further discussion regarding LLW and spent nuclear fuel disposal.
Under a 1991 consent order with the DEP and other interested parties we made
certain improvements in the emission control systems at New Boston Station.
These improvements included the replacement of four existing chimney stacks
with two taller stacks in order to improve the air quality in the vicinity of
the station, and the installation of low nitrogen oxides burners. The capital
costs of these modifications along with other associated improvements, which
were substantially completed in 1994, were approximately $80 million.
New Boston Station has the ability to burn natural gas, oil or both.
Beginning in April 1995, as part of the DEP consent order, we will be required
to operate the station fueled exclusively by natural gas, except in certain
emergency circumstances. We have made arrangements for a firm supply of
natural gas to run the station at a minimum level. We are developing a least-
cost plan for operation beyond this minimum level involving principally the
utilization of interruptible gas supplies or short-term capacity purchases.
The 1990 Clean Air Act Amendments will require a significant reduction in
nationwide emissions of sulfur dioxide from fossil fuel-fired generating
units. The reduction will be accomplished by restricting sulfur dioxide
emissions through a market-based system of allowances. We currently have
allowances that are in excess of our needs and which may be marketable. Any
gain from the sale of these may be subject to future regulatory treatment.
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 the low nitrogen oxides burners at New Boston, will allow the
units to meet the provisions of the 1995 standards. Depending upon the
outcome of certain DEP air quality modeling studies currently in progress,
additional emission reductions may also be required by 1999. The extent of
any additional reductions and the cost of any further modifications is
uncertain at this time.
In recent years there have been increasing public concerns 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. We support further 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.
25
27
Litigation
In 1991 we were named in a lawsuit alleging discriminatory employment
practices under the Age Discrimination in Employment Act of 1967 concerning 46
employees affected by our 1988 reduction in force. Legal counsel continues to
vigorously defend this case. Based on the information presently available we
do not expect that this litigation or certain other legal matters in which we
are currently involved will have a material impact on our financial condition.
However, an unfavorable decision ordered against us could have a material
impact on our results of a reporting period.
Executive Office Changes
In July 1994 our former President, Thomas May, became Chairman and Chief
Executive Officer, former Executive Vice President George Davis became
President and Chief Operating Officer and former Chairman and Chief Executive
Officer Bernard Reznicek retired. In January 1995 George Davis announced his
anticipated retirement effective September 1995.
26
28
Item 8. Financial Statements and Supplementary Financial Information
--------------------------------------------------------------------
Consolidated Statements of Income
years ended December 31,
(in thousands, except earnings per share) 1994 1993 1992
---------------------------------------------------------------------------
Operating revenues $1,548,554 $1,482,253 $1,411,753
---------------------------------------------------------------------------
Operating expenses:
Fuel 156,951 170,799 200,774
Purchased power 356,874 370,049 352,030
Other operations and maintenance 441,423 406,271 379,350
Depreciation and amortization 149,122 137,722 129,045
Amortization of deferred cost of
cancelled nuclear unit 19,791 0 24,381
Amortization of deferred nuclear
outage costs 7,721 6,546 4,901
Demand side management programs 35,438 37,504 8,221
Taxes - property and other 100,132 93,102 80,426
Income taxes 54,279 34,941 11,725
---------------------------------------------------------------------------
Total operating expenses 1,321,731 1,256,934 1,190,853
---------------------------------------------------------------------------
Operating income 226,823 225,319 220,900
Other income (expense), net 5,658 589 (2,074)
---------------------------------------------------------------------------
Operating and other income 232,481 225,908 218,826
---------------------------------------------------------------------------
Interest charges:
Long-term debt 102,570 104,375 106,850
Other 12,367 9,778 12,525
Allowance for borrowed funds used
during construction (7,478) (6,463) (7,847)
---------------------------------------------------------------------------
Total interest charges 107,459 107,690 111,528
---------------------------------------------------------------------------
Net income 125,022 118,218 107,298
Preferred and preference dividends provided 15,765 15,705 16,550
---------------------------------------------------------------------------
Balance available for common stock $ 109,257 $ 102,513 $ 90,748
===========================================================================
Common shares outstanding (weighted average) 45,338 44,959 43,144
Earnings per share of common stock $ 2.41 $ 2.28 $ 2.10
===========================================================================
Consolidated Statements of Retained Earnings
years ended December 31,
(in thousands) 1994 1993 1992
---------------------------------------------------------------------------
Balance at beginning of year $ 218,292 $ 192,948 $ 174,477
Net income 125,022 118,218 107,298
---------------------------------------------------------------------------
Subtotal 343,314 311,166 281,775
---------------------------------------------------------------------------
Cash dividends declared:
Preferred stock 15,765 15,705 14,923
Preference stock 0 0 1,953
Common stock 80,545 77,169 71,951
---------------------------------------------------------------------------
Subtotal 96,310 92,874 88,827
---------------------------------------------------------------------------
Balance at end of year $ 247,004 $ 218,292 $ 192,948
===========================================================================
The accompanying notes are an integral part of the consolidated financial
statements
27
29
Consolidated Balance Sheets
December 31,
(in thousands) 1994 1993
-----------------------------------------------------------------------------
Assets
Utility plant, at original cost:
In service $4,074,810 $3,904,776
Less: accumulated depreciation 1,344,452 $2,730,358 1,258,359 $2,646,417
------------------------------------------------------------------------------
Nuclear fuel 291,836 273,867
Less: accumulated amortization 236,239 55,597 220,477 53,390
------------------------------------------------------------------------------
Construction work in progress 144,048 144,835
------------------------------------------------------------------------------
2,930,003 2,844,642
Investments in electric companies,
at equity 24,678 24,292
Nuclear decommissioning trust 82,831 66,060
Current assets:
Cash and cash equivalents 6,822 8,768
Accounts receivable 189,382 171,098
Accrued unbilled revenues 32,240 29,823
Fuel, materials and supplies,
at average cost 71,560 79,381
Prepaid expenses and other 26,705 326,709 9,738 298,808
------------------------------------------------------------------------------
Deferred debits:
Regulatory assets 197,455 210,144
Intangible asset-pension 22,849 0
Other 32,085 252,389 33,342 243,486
------------------------------------------------------------------------------
Total assets $3,616,610 $3,477,288
==============================================================================
Capitalization and Liabilities
Common stock equity $ 915,747 $ 876,479
Cumulative preferred stock:
Non-mandatory redeemable series 123,000 123,000
Mandatory redeemable series 94,000 96,000
Long-term debt 1,136,617 1,272,497
Current liabilities:
Long-term debt/preferred
stock due within one year $102,250 $ 2,000
Notes payable 214,786 204,151
Accounts payable 139,119 117,614
Interest accrued 24,464 25,467
Dividends payable 23,533 22,696
Pension benefits 31,908 22,005
Other 76,615 612,675 32,477 426,410
------------------------------------------------------------------------------
Deferred credits:
Power contracts 40,277 36,275
Accumulated deferred income taxes 515,454 484,785
Accumulated deferred investment
tax credits 67,048 71,140
Nuclear decommissioning reserve 92,404 73,744
Other 19,388 734,571 16,958 682,902
------------------------------------------------------------------------------
Commitments and contingencies - -
------------------------------------------------------------------------------
Total capitalization and liabilities $3,616,610 $3,477,288
==============================================================================
The accompanying notes are an integral part of the consolidated financial
statements
28
30
Consolidated Statements of Cash Flows
years ended December 31,
(in thousands) 1994 1993 1992
-----------------------------------------------------------------------------
Cash flows from operating activities:
Net income $125,022 $118,218 $107,298
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation 142,932 130,074 123,243
Amortization of nuclear fuel 18,810 21,816 25,473
Amortization of deferred cost of cancelled
nuclear unit, net 19,067 0 22,340
Amortization of deferred nuclear outage
costs 7,721 6,546 4,901
Other amortization 13,967 9,433 2,132
Deferred income taxes (4,184) 10,303 17,165
Investment tax credits (4,092) (4,073) (4,273)
Allowance for borrowed funds used during
construction (7,478) (6,463) (7,847)
Net changes in:
Accounts receivable and accrued
unbilled revenues (20,701) 13,206 (18,188)
Fuel, materials and supplies 3,093 9,722 (2,330)
Accounts payable 21,505 (18,465) 35,759
Rate and contract settlements 0 (175) (31,363)
Other current assets and liabilities 36,908 25,209 3,575
Other, net 15,561 (19,548) (15,844)
-----------------------------------------------------------------------------
Net cash provided by operating activities 368,131 295,803 262,041
-----------------------------------------------------------------------------
Investing activities:
Plant expenditures (excluding AFUDC) (198,760) (246,763) (213,827)
Nuclear fuel expenditures (21,934) (6,491) (17,198)
Capitalized demand side management
expenditures (37,007) (37,156) (11,469)
Sale of plant assets, net 15,972 0 0
Nuclear decommissioning trust investments (16,771) (15,189) (7,210)
Electric company investments (386) 1,106 1,836
-----------------------------------------------------------------------------
Net cash used by investing activities (258,886) (304,493) (247,868)
-----------------------------------------------------------------------------
Financing activities:
Issuances:
Common stock 10,634 10,855 70,412
Preferred stock 0 40,000 40,000
Long-term debt 15,000 815,000 60,000
Redemptions:
Preferred and preference stock (2,000) (40,000) (40,333)
Long-term debt retirements (50,000) (648,625) (123,600)
Net change in short-term debt 10,635 (71,349) 65,200
Dividends paid (95,460) (92,370) (86,184)
-----------------------------------------------------------------------------
Net cash provided (used) by financing activities (111,191) 13,511 (14,505)
-----------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents (1,946) 4,821 (332)
Cash and cash equivalents at the
beginning of the year 8,768 3,947 4,279
-----------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $ 6,822 $ 8,768 $ 3,947
=============================================================================
Cash paid during the year for:
Interest, net of amounts capitalized $108,462 $103,720 $113,076
Income taxes $ 46,074 $ 30,305 $ 10,095
The accompanying notes are an integral part of the consolidated financial
statements.
29
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A. 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 and Boston Energy
Technology Group. All significant intercompany transactions have been
eliminated.
We follow accounting policies prescribed by our federal and state regulators.
We are also subject to the accounting and reporting requirements of the
Securities and Exchange Commission. The financial statements comply with
generally accepted accounting principles. Certain prior period amounts on the
financial statements were reclassified to conform with current presentation.
2. Revenues
We record 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 some purchased power costs to be billed to customers using a
forecasted rate. The difference between actual and estimated costs is
recorded as an adjustment to fuel and purchased power expenses and is included
in accounts receivable until subsequent rates are adjusted. State regulators
have 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. Depreciation and Nuclear Fuel Amortization
Our physical property was depreciated on a straight-line basis in 1994, 1993
and 1992 at composite rates of 3.11%, 3.09% and 3.36% per year, respectively,
based on estimated useful lives of the various classes of property. The cost
of decommissioning Pilgrim Station, our nuclear unit, is excluded from the
depreciation rates. When property units are retired, their cost, net of
salvage value, is charged to accumulated depreciation.
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 the 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.
5. Amortization of Deferred Nuclear Outage Costs
We expense deferred nuclear outage costs over five years as approved in the
1992 settlement agreement. The deferred cost balances in 1994 and 1993
consist of amounts related to the 1993 and 1991 refueling outages at Pilgrim
Station.
30
32
6. Amortization of Discounts, Premiums and Redemption Premiums on Debt
We expense discounts, premiums, redemption premiums and related costs
associated with issuances or redemptions of long-term debt or the refinancing
of existing debt over the life of the debt or the replacement debt subject to
regulatory approval.
7. Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance plant expenditures. In
accordance with regulatory accounting, AFUDC is included as a cost of utility
plant and a reduction of 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 1994, 1993 and 1992
were 4.45%, 3.62% and 4.48%, respectively, and represented only the cost of
short-term debt.
8. Cash and Cash Equivalents
Cash and cash equivalents are comprised of highly liquid securities with
maturities of three months or less. Outstanding checks are included in cash
and accounts payable until they are presented for payment.
9. Allowance for Doubtful Accounts
Our accounts receivable are substantially all 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.
10. Regulatory Assets
Regulatory assets represent costs incurred which will be collected from
customers through future charges in accordance with agreements with our state
regulators. These costs are to be expensed when the corresponding revenues
are received in order to appropriately match revenues and expenses. A portion
of these costs is currently being recovered from customers. No return on
investment was earned on the regulatory assets.
Regulatory assets consisted of the following:
December 31,
1994 1993
------------------------------------------------------------------
Redemption premiums $52,859 $59,116
Income taxes, net 44,745 26,916
Power contracts 40,277 36,275
Pension and postretirement costs 22,761 24,416
Nuclear outage costs 17,804 25,524
Cancelled nuclear unit 0 19,067
Other 19,009 18,830
------------------------------------------------------------------
$197,455 $210,144
==================================================================
NOTE B. RETAIL SETTLEMENT AGREEMENTS
In 1992 and 1989 our state regulators, the Massachusetts Department of Public
Utilities, approved three-year settlement agreements relating to our rate case
proceedings. These agreements provided for retail rate increases, accounting
adjustments and demand side management program expenditures; clarified the
31
33
timing and recognition of certain expenses and set limits on our rate of
return on common equity. Refer to Management's Discussion and Analysis for
further information related to these settlement agreements.
The settlement agreements did not affect our contract or wholesale power rates
charged to other utilities, which are regulated by our federal regulators, the
Federal Energy Regulatory Commission.
NOTE C. INCOME TAXES
In 1993 we prospectively adopted Statement of Financial Accounting Standards
No. 109, Accounting for Income Taxes (SFAS 109). This required us to change
our methodology of accounting for income taxes from the deferred method to an
asset and liability approach. The deferred method was based on the tax
effects of timing differences between income for financial reporting purposes
and taxable income. The asset and liability approach 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
$44.7 million and $26.9 million and corresponding net increases in accumulated
deferred income taxes as of December 31, 1994 and December 31, 1993,
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) 1994 1993
------------------------------------------------------------------------------
Deferred tax liabilities:
Plant-related $511,572 $496,731
Other 105,786 95,161
------------------------------------------------------------------------------
617,358 591,892
------------------------------------------------------------------------------
Deferred tax assets:
Plant-related 13,216 9,999
Investment tax credits 43,273 45,914
Alternative minimum tax 1,332 18,672
Other 44,083 32,522
------------------------------------------------------------------------------
101,904 107,107
------------------------------------------------------------------------------
Net accumulated deferred income taxes $515,454 $484,785
==============================================================================
No valuation allowances for deferred tax assets are deemed necessary.
Components of income tax expense were as follows:
years ended December 31,
(in thousands) 1994 1993 1992
------------------------------------------------------------------------------
Current income tax expense $62,839 $28,711 $ (385)
Deferred tax expense (4,468) 10,303 16,383
Investment tax credits (4,092) (4,073) (4,273)
------------------------------------------------------------------------------
Income taxes charged to operations 54,279 34,941 11,725
------------------------------------------------------------------------------
Taxes on other income:
Current 2,550 1,205 (2,348)
Deferred 284 0 782
------------------------------------------------------------------------------
2,834 1,205 (1,566)
-----------------------------------------------------------------------------
Total income tax expense $57,113 $36,146 $10,159
=============================================================================
32
34
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:
1994 1993 1992
-----------------------------------------------------------------------------
Statutory tax rate 35.0% 35.0% 34.0%
State income tax, net of federal income tax benefit 4.3 4.2 3.9
Investment tax credits (2.3) (2.6) (3.6)
Municipal property tax adjustment - (0.6) (1.6)
Adjustment of deferred taxes on cancelled
nuclear unit - - 2.7
Reversal of deferred taxes-settlement agreement (5.5) (13.0) (19.6)
Federal tax benefit of mandated
payments from settlement agreements - - (6.2)
Other (0.1) 0.4 (0.9)
-----------------------------------------------------------------------------
Effective tax rate 31.4% 23.4% 8.7%
=============================================================================
NOTE D. 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 are expensing an estimate of the
decommissioning costs over Pilgrim's expected service life. The 1994 expense
of approximately $15 million is included in depreciation expense on the
consolidated income statement. The estimate used to determine our annual
expense is based on a 1991 study which 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, which involves many uncertainties, was incorporated in our
1992 retail settlement agreement. We receive recovery of the annual expense
from charges to our retail customers and from other utility companies and
municipalities who 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 so that they may only be used for
decommissioning and related expenses. The net earnings on the trust funds,
which are also restricted, increase the nuclear decommissioning fund balance
and nuclear decommissioning reserve, thus reducing the amount to be collected
from customers.
The 1991 decommissioning study was partially updated for internal planning
purposes to evaluate the potential impact of long-term spent fuel storage
options resulting from delays in United States Department of Energy (DOE)
spent fuel removal on the estimated decommissioning cost. (See part 2 below
for a discussion of spent fuel removal). The partial update indicates an
estimated decommissioning cost of approximately $400 million in 1991 dollars
based upon a revised 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.
In 1994 the Financial Accounting Standards Board began to review the
accounting for decommissioning. If current industry accounting practices are
changed our annual decommissioning expense could increase and trust fund
earnings could be reported as investment income. In addition, the total
estimated liability for decommissioning costs may be recorded on the balance
sheet, most likely fully offset by an addition to utility plant costs. We do
33
35
not expect that these potential changes would have a material effect on our
results of operations.
2. Spent Nuclear Fuel
In 1994 we received a license amendment from the Nuclear Regulatory Commission
to modify our fuel storage facility at Pilgrim Station to provide sufficient
room for spent nuclear fuel generated through the end of Pilgrim's operating
license in 2012. We have modified the facility to provide spent fuel storage
capacity through approximately 2003, however any further modifications are
subject to review by our state regulators. In addition we are actively
exploring the feasibility of other spent fuel storage facilities and
technologies.
It is the ultimate responsibility of the DOE to permanently dispose of spent
nuclear fuel as required by the Nuclear Waste Policy Act of 1982. 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 is currently
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 may be unable to construct such a repository in a
timely manner. In June 1994 we and other interested parties filed petitions
in the U.S. Court of Appeals for the D.C. Circuit seeking declaratory rulings
that the DOE is obligated to begin taking spent nuclear fuel for disposal in
1998. The DOE has sought to dismiss those petitions and a court ruling is
awaited. It is unknown at this time whether and on what schedule the DOE will
eventually construct a spent fuel repository and what the effect on us will be
of any delays in such construction.
3. Low-Level Radioactive Waste
Our access to low-level radioactive waste (LLW) disposal facilities located in
Barnwell, South Carolina ended in July 1994. Until access is attained to
other disposal facilities we are managing LLW generated at Pilgrim Station
through on-site storage. 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.
However, it appears unlikely that either option will be available in the near
future. 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.
4. Other Nuclear Units
We are an investor in and customer of two other domestic nuclear units. Both
of these units receive, through the rates charged to their customers, an
amount to cover the estimated costs to dispose of their spent nuclear fuel and
to decommission the units at the end of their useful lives.
34
36
NOTE E. PENSIONS, OTHER POSTRETIREMENT AND POSTEMPLOYMENT 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 compensation during the last years of
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. Plan assets are primarily equities,
bonds, insurance contracts and real estate funds.
Net pension cost consisted of the following components:
years ended December 31,
(in thousands) 1994 1993 1992
-----------------------------------------------------------------------------
Current service cost - benefits earned $15,057 $ 11,734 $ 10,683
Interest cost on projected benefit
obligation 33,961 33,181 32,287
Actual net loss/(return) on plan assets 214 (44,470) (23,281)
Net amortization and deferral (32,169) 8,528 (13,549)
-----------------------------------------------------------------------------
Net pension cost (a) $17,063 $ 8,973 $ 6,140
=============================================================================
<FN>
(a) In accordance with an agreement with our state regulators we deferred
the difference in net pension costs and the annual funding amounts. Net
deferred costs amounted to $6 million and $14 million at December 31,
1994 and 1993, respectively. Net pension costs recorded as expense were
$25 million in 1994, $5 million in 1993 and $0 in 1992.
We used the following assumptions for calculating pension cost:
1994 1993 1992
-----------------------------------------------------------------------------
Discount rate 7.00% 8.25% 8.25%
Expected long-term rate of return on assets 10.00% 10.00% 10.00%
Compensation increase rate 4.50% 4.50% 4.50%
-----------------------------------------------------------------------------
The pension plan's funded status was as follows:
December 31,
(in thousands) 1994 1993
-----------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including
vested benefits of $305,632 and $384,150 $321,072 $400,895
=============================================================================
Plan assets at fair value $289,164 $394,233
Projected obligation for service rendered
to date (387,910) (509,661)
-----------------------------------------------------------------------------
Projected benefit obligation in excess of
plan assets (98,746) (115,428)
Unrecognized prior service cost 13,328 8,139
Unrecognized net loss 67,361 75,352
Unrecognized net obligation 8,998 9,932
Minimum liability adjustment (b) (22,849) 0
-----------------------------------------------------------------------------
Net pension liability $(31,908) $(22,005)
=============================================================================
<FN>
(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
35
37
recorded an additional minimum liability and corresponding intangible
asset of $23 million on our consolidated balance sheet at December 31,
1994.
We used the following assumptions for calculating the plan's year-end funded
status:
1994 1993
------------------------------------------------------------------------------
Discount rate 8.25% 7.00%
Compensation increase rate 3.90% 4.50%
------------------------------------------------------------------------------
We also provide defined contribution 401(k) plans for substantially all our
employees. We match a percentage of employees' voluntary contributions to the
plans, which amounted to $8 million in 1994, $7 million in 1993 and $5 million
in 1992.
2. Other Postretirement Benefits
In addition to pension benefits, we also currently provide health care and
other benefits to our retired employees who meet certain age and years of
service eligibility requirements. In 1993 we adopted Statement of Financial
Accounting Standards No. 106, Employers' Accounting for Postretirement
Benefits Other Than Pensions (SFAS 106). This requires us to record a
liability during the working years of employees for the expected costs of
providing their postretirement benefits other than pensions (PBOPs). Prior to
1993 our policy was to record the cost of PBOPs when paid. Our transition
obligation upon adopting this standard was approximately $183 million, which
we elected to recognize over 20 years as permitted by SFAS 106.
Our 1992 settlement agreement provides us with a phase-in of a portion of the
higher PBOP costs incurred under SFAS 106 and allows us to defer the
additional costs in excess of the phase-in amounts to the extent that we fund
an external trust. Our funding policy is to contribute 100% of postretirement
benefit costs to external trusts. Accordingly, we recorded expenses of $17
million in 1994 and $15 million in 1993, reflecting the amount of current cost
recovery from customers, and deferred the net costs in excess of amounts
expensed for future recovery. Net deferred costs amounted to $16 million and
$10 million at December 31, 1994 and 1993, respectively.
Net postretirement benefits cost consisted of the following components:
years ended December 31,
(in thousands) 1994 1993
-----------------------------------------------------------------------------
Current service cost - benefits earned $ 4,978 $ 4,351
Interest cost on accumulated benefit obligation 13,632 14,286
Actual return on plan assets (187) 0
Amortization of transition obligation 9,151 9,151
Net amortization and deferral (2,581) 0
-----------------------------------------------------------------------------
Net postretirement benefits cost $24,993 $27,788
-----------------------------------------------------------------------------
36
38
We used the following assumptions for calculating postretirement benefits
cost:
1994 1993
-----------------------------------------------------------------------------
Discount rate 7.0% 8.0%
Expected long-term rate of return on assets 9.0% 9.0%
Health care cost trend rate 9.0% 12.5%
------------------------------------------------------------------------------
The health care cost trend rate is assumed to decrease by one percent each
year beginning in 1995 to 5% in 1998 and 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 service and interest cost components by 20% and would increase the
accumulated benefit obligation at December 31, 1994 by 18%.
The postretirement benefits program's funded status was as follows:
December 31,
(in thousands) 1994 1993
-----------------------------------------------------------------------------
Trust assets at fair value $ 33,300 $ 18,016
Accumulated obligation for service
rendered to date from:
Retirees $(93,960) $(75,216)
Active employees eligible to retire (31,159) (64,880)
Active employees not eligible to retire (51,545)(176,664) (73,285) (213,381)
-----------------------------------------------------------------------------
Accumulated benefit obligation in excess
of trust assets (143,364) (195,365)
Unrecognized prior service cost (19,502) 0
Unrecognized net (gain)/loss (1,849) 21,497
Unrecognized transition obligation 164,715 173,868
-----------------------------------------------------------------------------
Net postretirement benefits liability $ 0 $ 0
=============================================================================
The weighted average discount rates we used to measure the accumulated benefit
obligation were 8.25% in 1994 and 7.0% in 1993. The trust assets consist of
equities, bonds and money market funds.
3. Postemployment Benefits
In 1994 we adopted Statement of Financial Accounting Standards No. 112,
Employers' Accounting for Postemployment Benefits (SFAS 112). This required
us to record a liability for the estimated costs of providing postemployment
benefits. Postemployment benefits provided to former or inactive employees,
their beneficiaries and covered dependents consist primarily of disability-
related benefits, including workers' compensation. We previously recognized
the costs of these benefits primarily as claims were paid. The adoption of
SFAS 112 did not have a material effect on our results of operations.
Note F. Eminent Domain Taking
In November 1994 a Norfolk Superior Court ruling against the Massachusetts
Metropolitan District Commission (MDC) became effective, providing us with an
additional $5.7 million gain on an eminent domain land taking case. We had
filed suit against the MDC in 1992 related to the eminent domain taking of
certain of our property in 1989.
Note G. Cancelled Nuclear Unit
In May 1982 we began to expense the cost of our cancelled Pilgrim 2 nuclear
unit over approximately eleven and one-half years in accordance with an order
37
39
received from state regulators. We did not expense any of these costs in
1993. The remaining balance of $19 million was fully expensed in 1994 as
allowed by our state regulators in our 1992 settlement agreement.
Note H. Capital Stock and Indebtedness
Capital Stock
December 31,
(dollars in thousands, except per share amounts) 1994 1993 1992
------------------------------------------------------------------------------
Common stock equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 45,535,477,
45,129,227 and 44,763,055 shares issued and
outstanding: $ 45,535 $ 45,129 $ 44,763
Premium on common stock 622,803 612,653 602,196
Retained earnings 247,004 218,292 192,948
Surplus invested in plant 405 405 405
------------------------------------------------------------------------------
Total common stock equity $915,747 $876,479 $840,312
==============================================================================
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares
authorized; issued and outstanding:
Non-mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
------------------------------------------------------------------------------
4.25% 180,000 $103.625 $ 18,000 $ 18,000 $ 18,000
4.78% 250,000 $102.800 25,000 25,000 25,000
7.75% 400,000 - 40,000 40,000 0
8.25% 400,000 - 40,000 40,000 40,000
8.88% 0 - 0 0 40,000
------------------------------------------------------------------------------
Total non-mandatory redeemable series $123,000 $123,000 $123,000
==============================================================================
Mandatory redeemable series:
Current Shares
Series Outstanding
------------------------------------------------------------------------------
7.27% 460,000 $ 46,000 $ 48,000 $ 48,000
8.00% 500,000 50,000 50,000 50,000
------------------------------------------------------------------------------
Total mandatory redeemable series 96,000 98,000 98,000
Less: due within one year 2,000 2,000 0
------------------------------------------------------------------------------
Total mandatory redeemable series, net $ 94,000 $ 96,000 $ 98,000
==============================================================================
Dividends Declared per Share
Common stock $ 1.775 $ 1.715 $ 1.655
Preferred stock:
4.25% series $ 4.250 $ 4.253 $ 4.250
4.78% series 4.780 4.785 4.780
7.27% series 7.270 7.270 7.270
7.75% series 7.750 5.707 0
8.00% series 8.000 8.000 8.000
8.25% series 8.250 8.250 5.278
8.88% series 0 2.220 8.880
Preference stock:
$1.46 series $ 0 $ 0 $ 0.365
38
40
Indebtedness
December 31,
(dollars in thousands) 1994 1993
------------------------------------------------------------------------------
Long-term debt:
First mortgage bonds:
Series S, variable rate, due 2002 $ 0 $ 25,000
Series U, 10.250%, due 2014 0 15,000
------------------------------------------------------------------------------
Total first mortgage bonds 0 40,000
------------------------------------------------------------------------------
Sewage facility revenue bonds 36,300 36,300
Less: due within one year 600 0
Less: funds held by trustee 4,083 3,803
------------------------------------------------------------------------------
Net long-term sewage facility revenue bonds 31,617 32,497
------------------------------------------------------------------------------
Debentures:
8.875%, due 1995 100,000 100,000
5.125%, due 1996 100,000 100,000
5.700%, due 1997 100,000 100,000
5.950%, due 1998 100,000 100,000
6.800%, due 2000 65,000 65,000
6.050%, due 2000 100,000 100,000
6.800%, due 2003 150,000 150,000
9.875%, due 2020 100,000 100,000
9.375%, due 2021 115,000 125,000
8.250%, due 2022 60,000 60,000
7.800%, due 2023 200,000 200,000
------------------------------------------------------------------------------
Total debentures 1,190,000 1,200,000
Less: due within one year 100,000 0
------------------------------------------------------------------------------
Net long-term debentures 1,090,000 1,200,000
------------------------------------------------------------------------------
Massachusetts Industrial Finance Agency bonds:
5.750%, due 2014 15,000 0
------------------------------------------------------------------------------
Total long-term debt $1,136,617 $1,272,497
==============================================================================
Short-term debt:
Notes payable:
Bank loans $ 80,786 $ 106,501
Commercial paper 134,000 97,650
------------------------------------------------------------------------------
Total notes payable $ 214,786 $ 204,151
==============================================================================
1. Common Stock
Since December 31, 1991, we issued the following shares of common stock:
Number Total Premium on
(in thousands) of Shares Par Value Common Stock
------------------------------------------------------------------------------
Balance December 31, 1991 42,047 $42,047 $536,567
Dividend reinvestment plan 416 416 9,658
New issue (a) 2,300 2,300 55,971
------------------------------------------------------------------------------
Balance December 31, 1992 44,763 44,763 602,196
Dividend reinvestment plan 366 366 10,457
------------------------------------------------------------------------------
Balance December 31, 1993 45,129 45,129 612,653
Dividend reinvestment plan (b) 406 406 10,150
------------------------------------------------------------------------------
Balance December 31, 1994 45,535 $45,535 $622,803
==============================================================================
39
41
<FN>
(a) We used the net proceeds of the 1992 common stock issuance to reduce
short-term debt.
(b) At December 31, 1994, the remaining authorized common shares reserved
for future issuance under the Dividend Reinvestment and Common Stock
Purchase Plan were 2,408,920 shares.
2. Cumulative Non-Mandatory Redeemable Preferred Stock
In May 1993 we issued 400,000 shares of 7.75% cumulative non-mandatory
redeemable preferred stock at par. The stock is redeemable at $100 per share
plus accrued dividends beginning in May 1998. These shares were sold in the
form of 1.6 million depositary shares, each representing a one-fourth interest
in a share of the preferred stock. We used the proceeds of this issue to
fully retire the 8.88% series cumulative non-mandatory redeemable preferred
stock.
3. Cumulative Mandatory Redeemable Preferred Stock
The 460,000 shares of our 7.27% sinking fund series cumulative preferred stock
are currently redeemable at our option at $103.88. 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 non-cumulative option each May to redeem
additional shares, not to exceed 20,000, through the sinking fund at $100 per
share plus accrued dividends.
We are not able to redeem any part of our 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.
4. Long-Term Debt
The aggregate principal amounts of our debentures and sewage facility revenue
bonds (including sinking fund requirements) due are $100.6 million in 1995,
$101.6 million per year in 1996 through 1998 and $1.6 million in 1999.
In February 1993 we issued $65 million of 6.80% debentures due in 2000. We
used the proceeds of this issue to reduce short-term debt. These debentures
are not redeemable prior to maturity.
In March 1993 we issued $650 million of debentures and used the proceeds to
retire ten series of first mortgage bonds and reduce short-term debt. The
debentures were issued in five separate series with interest rates ranging
from 5.125% to 7.8% and maturing between 1996 and 2023. The 5 1/8% debentures
due 1996, 5.70% due 1997, 5.95% due 1998 and 6.80% due 2003 are not redeemable
prior to maturity. The 7.80% debentures due 2023 are first redeemable in
March 2003 at a redemption price of 103.73%. The redemption price decreases
annually each March to par value in March 2013. There is no sinking fund
requirement for any series of these debentures.
In August 1993 we issued $100 million of 6.05% debentures due in 2000. We
used the proceeds from this sale to reduce short-term debt. These debentures
are not redeemable prior to maturity and have no sinking fund requirements.
In March 1994 the Massachusetts Industrial Finance Agency, on our behalf,
issued $15 million of 5.75% tax-exempt unsecured bonds due in 2014. The bonds
are redeemable beginning in February 2004 at a redemption price of 102%. The
40
42
redemption price decreases to 101% in February 2005 and to par in February
2006. The proceeds from this issuance together with sufficient other funds
were used to fully redeem the Series U first mortgage bonds.
We redeemed at par the $25 million variable rate Series S first mortgage bonds
in 1994. These bonds paid interest at 9.2% for the period January 15, 1993
through January 14, 1994. The rate was adjusted to 8.2% beginning January 15,
1994 based upon the ten-year constant maturity Treasury rate as published by
the Federal Reserve Board.
As a result of the redemption of all outstanding first mortgage bonds, the
Indenture of Trust and First Mortgage that had mortgaged substantially all our
property since 1940 was terminated in November 1994.
Sewage facility revenue bonds were issued by Harbor Electric Energy Company
(HEEC), a wholly-owned subsidiary. The bonds are tax-exempt, subject to
annual mandatory sinking fund redemption requirements and mature in the years
1995-2015. 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 certain costs on a timely basis or
be unable to meet certain net worth requirements, we would be required to make
additional capital contributions or loans to the subsidiary up to a maximum of
$7 million.
5. 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
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:
(in thousands of dollars) 1994 1993 1992
-----------------------------------------------------------------------------
Maximum short-term borrowings $268,100 $320,000 $314,998
Weighted average amount outstanding $214,640 $220,149 $233,286
Weighted average interest rates, excluding
commitment fees 4.5% 3.4% 4.1%
------------------------------------------------------------------------------
NOTE I. FAIR VALUE OF SECURITIES
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 $82.8 million approximates fair value based on quoted market
prices of securities held.
Cash and cash equivalents
The carrying amount of $6.8 million approximates fair value due to the
short-term nature of these securities.
41
43
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, 1994 are
as follows:
Carrying Fair
(in thousands) Amount Value
------------------------------------------------------------------------------
Mandatory redeemable cumulative preferred stock $ 96,000 $ 93,780
Sewage facility revenue bonds 36,300 37,037
Unsecured debt 1,205,000 1,111,317
------------------------------------------------------------------------------
NOTE J. NEW ACCOUNTING PRONOUNCEMENT
Statement of Financial Accounting Standards No. 115, Accounting for Certain
Investments in Debt and Equity Securities, became effective in 1994. This
statement did not have a material effect on our consolidated financial
statements.
NOTE K. COMMITMENTS AND CONTINGENCIES
1. Capital Commitments
At December 31, 1994, we had estimated contractual obligations for plant and
equipment of approximately $50 million.
2. Lease Commitments
We have leases for certain facilities and equipment. Our estimated minimum
rental commitments under both noncancellable leases and transmission
agreements for the years after 1994 are as follows:
(in thousands)
------------------------------------------------------
1995 $ 26,540
1996 24,305
1997 21,396
1998 19,438
1999 17,794
Years thereafter 127,646
------------------------------------------------------
Total $237,119
======================================================
We will capitalize a portion of these lease rentals as part of plant
expenditures in the future. Our total expense for both lease rentals and
transmission agreements was $27 million in 1994 and $30 million in 1993 and
1992, net of capitalized expenses of $4 million in 1994 and $5 million in 1993
and 1992.
3. 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, which is included in our consolidated financial
statements. 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 and are compensated accordingly. At December
31, 1994, our portion of these guarantees was approximately $21 million.
42
44
4. Yankee Atomic Electric Company
We have a 9.5% stock investment of approximately $2.5 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. We relied on Yankee
Atomic for less than one percent of our system capacity under a long-term
purchased power contract.
In 1993 Yankee Atomic received approval from federal regulators to continue to
collect its investment and decommissioning costs through July 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 $39 million
as of December 31, 1994. 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.
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 $8.3 billion is provided by a retrospective
assessment of up to $75.5 million per incident levied on each of the 110 units
licensed to operate in the United States, with a maximum assessment of $10
million per reactor per accident in any year. The additional nuclear
liability insurance amount may change as existing units give up their
licenses. In addition to the nuclear liability retrospective assessments, if
the sum of all public liability claims and legal costs arising from any
nuclear accident exceeds the maximum amount of financial protection, each
licensee can be assessed an additional five percent of the maximum
retrospective assessment.
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 at Pilgrim Station 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 approximately $14.8
million under both the replacement power and excess property damage,
decontamination and decommissioning policies. All companies insured with NEIL
are subject to retroactive assessments if losses are in excess of the total
funds available to NEIL. While assessments may also be made for losses in
certain prior policy years, we are not aware of any losses in those years
which we believe are likely to result in an assessment.
6. Litigation
In 1991 we were named in a lawsuit alleging discriminatory employment
practices under the Age Discrimination in Employment Act of 1967 concerning 46
employees affected by our 1988 reduction in force. Legal counsel continues to
vigorously defend this case. Based on the information presently available we
do not expect that this litigation or certain other legal matters in which we
are currently involved will have a material impact on our financial condition.
However, an unfavorable decision ordered against us could have a material
impact on our results of a reporting period.
43
45
7. Hazardous Waste
We own or operate 48 properties where hazardous materials were released in the
past. 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 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 we currently expect to have only a small percentage of the
potential liability. Through December 31, 1994, 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 expect any such additional costs to have a material
impact on our financial condition. However, additional provisions for cleanup
costs could have a material impact on our results of a reporting period.
44
46
Note L. 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 in our consolidated income statements. Information
relating to these contracts as of December 31, 1994 is as follows:
proportionate share (in thousands)
----------------------------------
Units of 1994 1994 Interest Debt
Contract Capacity Minimum Portion of Outstanding
Expiration Purchased(a) Debt Minimum Through Cont.
Generating Unit Date % MW Service Debt Service Exp. Date
------------------------------------------------------------------------------
Canal Unit 1 2001 25.0 140 $ 796 $ 321 $ 1,928
Mass. Bay Trans-
portation
Authority 2005 100.0 34 (b) (b) (b)
Connecticut Yankee
Atomic 2007 9.5 55 2,607 1,695 14,678
Ocean State Power -
Unit 1 2010 23.5 67.5 5,072 3,653 21,563
Ocean State Power -
Unit 2 2011 23.5 67.5 4,266 3,223 18,316
Northeast Energy
Associates (c) (c) 219 (c) (c) (c)
L'Energia 2013 73.0 64 (d) (d) (d)
MassPower (e) 2013 44.3 117 12,642 8,088 86,538
------------------------------------------------------------------------------
Total 764 $25,383 $16,980 $143,023
==============================================================================
<FN>
(a) The Northeast Energy Associates contract represents 6.4% of our total
system generation capability. The remaining units listed above represent
15.9% in total.
(b) We are required to pay the greater of $22.00 per kilowatt-year or 90% of
the New England Power Pool capability responsibility adjustment charge up
to $63.00 per kilowatt-year times the qualified capacity (currently rated
at 34MW) plus incremental operating, maintenance and fuel costs. The
total charges for this contract in 1994 were approximately $2 million.
(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. The
total charges for these contracts in 1994 were approximately $119
million.
(d) We pay for this energy based on a price per kWh actually received. The
total charges under this contract for 1994 were approximately $31
million.
45
47
(e) The MassPower contract started in January 1994. Payments are based on a
stipulated price per MW rating of the unit subject to the unit
maintaining a twelve month average availability of at least 90%.
Payments are adjusted proportionately if the twelve month average is
below 90%. If the twelve month average is less than 10% no payment is
required. Total charges for this contract in 1994 were approximately $47
million.
Our total fixed and variable costs for these contracts in 1994, 1993 and 1992
were approximately $286 million, $225 million and $217 million, respectively.
Our minimum fixed payments under these contracts for the years after 1994 are
as follows:
(in thousands)
------------------------------------------------------
1995 $ 105,574
1996 108,187
1997 105,622
1998 109,837
1999 108,196
Years thereafter 1,318,008
------------------------------------------------------
Total $1,855,424
======================================================
Total present value $ 928,594
======================================================
2. Long-Term Power Sales
In addition to our power sales to five wholesale customers, 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
==============================================================================
<FN>
(a) Subject to certain adjustments.
Under these contracts, the utilities pay their proportional 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.
46
48
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
------------------------------------------------------------------------------
1994
First quarter $377,449 $45,795 $19,812 $15,850 $0.35
Second quarter 368,655 50,395 23,982 20,031 0.44
Third quarter 449,094 96,599 70,182 66,256 1.46
Fourth quarter 353,356 34,034 11,046 7,120 0.16
1993
First quarter $354,752 $41,722 $15,452 $11,377 $0.25
Second quarter 346,074 49,282 22,829 19,125 0.43
Third quarter 436,024 96,319 70,015 66,053 1.47
Fourth quarter 345,403 37,996 9,922 5,958 0.13
Item 9. Changes in and Disagreements with Accountants on Accounting and
-------------------------------------------------------------------------
Financial Disclosure
--------------------
Not applicable.
47
49
Part III
--------
Item 10. Directors and Executive Officers of the Registrant
------------------------------------------------------------
(a) Identification of Directors
---------------------------------
See "Election of Directors - Information about Nominees and Incumbent
Directors" on pages 1 through 4 of the definitive proxy statement dated March
27, 1995, 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.
Information regarding delinquent filers pursuant to Item 405 of Regulation S-K
is included under "Stock Ownership by Directors and Executive Officers" on
pages 4 through 5 of the definitive proxy statement dated March 27, 1995,
incorporated herein by reference.
(c) Identification of Certain Significant Employees
----------------------------------------------------
Not applicable.
(d) Family Relationships
-------------------------
Not applicable.
(e) Business Experience
------------------------
For information relating to the business experience during the past five years
and other directorships (of companies subject to certain SEC requirements)
held by each person nominated to be a director, see "Election of Directors -
Information about Nominees and Incumbent Directors" on pages 1 through 4 of
the definitive proxy statement dated March 27, 1995, 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 "Director and Executive Compensation" on pages 5 through 11 of the
definitive proxy statement dated March 27, 1995, incorporated herein by
reference.
48
50
Item 12. Security Ownership of Certain Beneficial Owners and Management
------------------------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners
----------------------------------------------------
To the knowledge of management, no person owns beneficially more than five
percent of the outstanding voting securities of the Company.
(b) Security Ownership of Management
-------------------------------------
See "Stock Ownership by Directors and Executive Officers" on pages 4 through 5
of the definitive proxy statement dated March 27, 1995, incorporated herein by
reference.
(c) Changes in Control
-----------------------
Not applicable.
Item 13. Certain Relationships and Related Transactions
--------------------------------------------------------
Not applicable.
49
51
Part IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
-------------------------------------------------------------------------
(a) Exhibits and Consolidated Financial Statement Schedules Page
----------------------------------------------------------- ----
Consolidated Statements of Income for the three years ended
December 31, 1994, 1993 and 1992 27
Consolidated Statements of Retained Earnings for the three
years ended December 31, 1994, 1993 and 1992 27
Consolidated Balance Sheets as of December 31, 1994 and 1993 28
Consolidated Statements of Cash Flows for the three years
ended December 31, 1994, 1993 and 1992 29
Notes to Consolidated Financial Statements 30
Selected Consolidated Quarterly Financial Data (Unaudited) 47
Report of Independent Accountants 61
Financial statement schedules have been omitted as they are either not
required or not applicable.
50
52
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 Votes of the Pricing Committee of the 4.1 1-2301
Board of Directors of Boston Edison Form 10-Q
Company taken December 11, 1990 re for the
8 7/8% debentures due December 15, 1995 quarter ended
March 31, 1991
4.1.3 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
51
53
Exhibit SEC Docket
------- ----------
4.1.4 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
4.1.5 Revolving Credit Agreement dated 4.1.24 1-2301
February 12, 1993 Form 10-K
for the
year ended
December 31,
1992
4.1.6 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
4.1.7 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
4.1.8 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
4.1.9 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
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.
52
54
Exhibit SEC Docket
------- ----------
Exhibit 10 Material Contracts
---------- ------------------
Incorporated herein by reference:
10.1 Key Executive Benefit Plan 10.13 1-2301
(1982 Form of Agreement) Form 10-K
for the
year ended
December 31,
1992
10.1.1 Amendment to Key Executive Benefit 10.4.1 1-2301
Plan dated February 1, 1986 Form 10-K
for the
year ended
December 31,
1985
10.1.2 Key Executive Benefit Plan 10.1 1-2301
Standard Form of Agreement, May Form 10-Q
1986 for the
quarter ended
June 30, 1986
10.1.3 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
53
55
Exhibit SEC Docket
------- ----------
10.4 Boston Edison Company Deferred 10.11 1-2301
Fee Plan dated January 1, 1990 Form 10-K
for the
year ended
December 31,
1992
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
10.6 Directors Retirement Benefit 10.8.1 1-2301
(1993 Plan) Form 10-K
for the
year ended
December 31,
1993
Filed herewith:
10.5.1 Amendment No. 1 to Deferred
Compensation Trust dated
March 31, 1994
10.7 Description of Supplemental Fee
Arrangement for Certain Directors
10.8 Performance Share Plan, Amendment
and Restatement dated
October 24, 1994
10.9 Boston Edison Company Deferred
Compensation Plan, Amendment and
Restatement dated January 31, 1995
10.10 Employment Agreement applicable to
Ronald A. Ledgett dated April 30, 1987
54
56
Exhibit SEC Docket
------- ----------
10.11 Description of Compensation
Arrangement with Bernard W.
Reznicek dated June 23, 1994
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, 1994
12.2 Computation of Ratio of Earnings
to Fixed Charges and Preferred Stock
Dividend Requirements for the Year
Ended December 31, 1994
Exhibit 18 Letter re Change in Accounting Principle
---------- ----------------------------------------
Incorporated herein by reference:
18.1 Letter of Independent Certified 18.1 1-2301
Public Accountants Form 10-Q
for the
quarter ended
March 31, 1990
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
21.3 Ener-G-Vision, Inc. (incorporated
in Massachusetts), a wholly-owned
subsidiary of Boston Energy
Technology Group, Inc.
21.4 TravElectric Services Corporation
(incorporated in Massachusetts),
a wholly-owned subsidiary of Boston
Energy Technology Group, Inc.
55
57
Exhibit SEC Docket
------- ----------
21.5 REZ-TEK International Corporation
(incorporated in Massachusetts),
a majority-owned subsidiary of
Boston Energy Technology Group, Inc.
21.6 Coneco Corporation (incorporated
in Massachusetts), a majority-owned
subsidiary of Boston Energy
Technology Group, Inc.
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
September 14, 1990 (File No.
33-36824), February 3, 1993 (File
No. 33-57840) 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) and
March 17, 1993 (33-59662 and
33-59682).
Exhibit 27 Financial Data Schedule
---------- -----------------------
Filed herewith:
27.1 Schedule UT
Exhibit 99 Additional Exhibits
---------- -------------------
Incorporated herein by reference:
99.1 DPU Settlement Agreement with 28.1 1-2301
Boston Edison Company dated Form 8-K
October 3, 1989 dated
October 3, 1989
56
58
Exhibit SEC Docket
------- ----------
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
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 Amendment to
December 31, 1993, 1992 and 1991 Form 10-K for
the year ended
December 31,
1993 and Form 8
Amendments to
Form 10-K for
the years ended
December 31,
1992 and 1991,
dated June 30,
1994, June 29,
1993 and
June 26, 1992,
respectively
99.6 DPU Settlement Agreement with 28.2 1-2301
Boston Edison Company, dated Form 10-Q
October 23, 1992 for the
quarter ended
September 30,
1992
57
59
(b) Reports on Form 8-K
------------------------
There were no Form 8-K's filed during the fourth quarter of 1994.
58
60
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/ Charles E. Peters, Jr.
--------------------------
Charles E. Peters, Jr.
Senior Vice President - Finance
(Principal Financial Officer)
Date: March 23, 1995
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 23rd day of March 1995.
/s/ Thomas J. May Chairman of the Board and Chief
--------------------------- Executive Officer
Thomas J. May
/s/ George W. Davis President and Chief Operating
--------------------------- Officer and Director
George W. Davis
/s/ Robert J. Weafer, Jr. Vice President, Controller and
--------------------------- Chief Accounting Officer
Robert J. Weafer, Jr.
/s/ William F. Connell Director
---------------------------
William F. Connell
/s/ Gary L. Countryman Director
---------------------------
Gary L. Countryman
--------------------------- Director
Thomas G. Dignan, Jr.
--------------------------- Director
Charles K. Gifford
/s/ Nelson S. Gifford Director
---------------------------
Nelson S. Gifford
59
61
/s/ Kenneth I. Guscott Director
---------------------------
Kenneth I. Guscott
/s/ Matina S. Horner Director
---------------------------
Matina S. Horner
/s/ Sherry H. Penney Director
---------------------------
Sherry H. Penney
/s/ Bernard W. Reznicek Director
---------------------------
Bernard W. Reznicek
/s/ Herbert Roth, Jr. Director
---------------------------
Herbert Roth, Jr.
--------------------------- Director
Stephen J. Sweeney
--------------------------- Director
Paul E. Tsongas
60
62
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, 1994 and 1993, and the consolidated results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
January 26, 1995
61