<PAGE>
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, 1995
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)
<TABLE>
<S> <C>
Massachusetts 04-1278810
- ------------------------------------------- ------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
- ------------------------------------------- ------------------------
(Address of principal executive offices) (Zip Code)
</TABLE>
Registrant's telephone number, including area code: 617-424-2000
------------
<TABLE>
Securities registered pursuant to Section 12(b) of the Act:
<CAPTION>
Name of each exchange
Title of each class on which registered
------------------- ---------------------
<S> <C>
Common stock, par value $1 per share New York Stock Exchange
Boston Stock Exchange
Cumulative preferred stock:
7.75% Series, par value $100 per share New York Stock Exchange
(represented by depositary shares-each
represents one-fourth interest in par value)
8.25% Series, par value $100 per share New York Stock Exchange
(represented by depositary shares-each
represents one-fourth interest in par value)
</TABLE>
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark 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 29, 1996 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: $1,328,730,345.
Indicate the number of shares outstanding of each of the registrant's classes
of common stock, as of the latest practicable date.
<TABLE>
<CAPTION>
Class Outstanding at February 29, 1996
-------------------------- --------------------------------
<S> <C>
Common Stock, $1 par value 48,098,836 shares
</TABLE>
<TABLE>
DOCUMENTS INCORPORATED BY REFERENCE
<CAPTION>
Part Document
---- --------
<S> <C>
III Portions of definitive proxy statement dated March 28, 1996 for Annual
Meeting of Stockholders to be held May 8, 1996.
</TABLE>
<PAGE> 1
Boston Edison Company
- --------------------------------------------------------------------------
Form 10-K Annual Report
- --------------------------------------------------------------------------
December 31, 1995
- --------------------------------------------------------------------------
<TABLE>
<CAPTION>
Part I Page
- --------------------------------------------------------------------------
<S> <C>
Item 1. Business 2
Item 2. Properties and Power Supply 9
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 12
Part II
- --------------------------------------------------------------------------
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 16
Item 6. Selected Financial Data 17
Item 7. Management's Discussion and Analysis 18
Item 8. Financial Statements and Supplementary Financial
Information 30
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 52
Part III
- --------------------------------------------------------------------------
Item 10. Directors and Executive Officers of the Registrant 53
Item 11. Executive Compensation 53
Item 12. Security Ownership of Certain Beneficial Owners and
Management 54
Item 13. Certain Relationships and Related Transactions 54
Part IV
- --------------------------------------------------------------------------
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 55
</TABLE>
<PAGE> 2
Part I
------
Item 1. Business
- -----------------
(a) General Development of Business
- -----------------------------------
Boston Edison Company (the Company) is an investor-owned regulated public
utility incorporated in 1886 under Massachusetts law. The Company operates in
the energy and energy services business, which includes the generation,
purchase, transmission, distribution and sale of electric energy and the
development and implementation of electric demand side management programs.
The Company has an unregulated subsidiary, Boston Energy Technology Group
(BETG), in which it has authority from the Massachusetts Department of Public
Utilities (DPU) to invest up to $45 million. This wholly owned subsidiary
engages primarily in energy conservation services and the production of water
treatment systems. In 1996 BETG entered into a joint venture to build a
series of ice-based cooling systems. BETG's investment in this joint venture,
Northwind Boston, is not material. 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
- -------------------------------------------------
The Company operates primarily as a regulated electric public utility,
therefore industry segment information is not applicable.
(c) Narrative Description of Business
- -------------------------------------
Principal Products and Services
The Company supplies electricity at retail to an area of 590 square miles,
including the City of Boston and 39 surrounding cities and towns. The
population of the area served with electricity at retail is approximately 1.5
million. In 1995 the Company served an average of 654,000 customers. The
Company also supplies electricity at wholesale for resale to other utilities
and municipal electric departments. Electric operating revenues by class for
the last three years consisted of the following:
<TABLE>
<CAPTION>
1995 1994 1993
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Retail electric revenues:
Commercial 50% 50% 49%
Residential 28% 28% 28%
Industrial 9% 9% 10%
Other 2% 2% 1%
Wholesale and contract revenues 11% 11% 12%
===========================================================================
</TABLE>
<PAGE> 3
Sources and Availability of Fuel
<TABLE>
The Company owns two stations whose generating units have the ability to burn
oil, natural gas or both, one nuclear power station and ten combustion turbine
generators. Refer also to 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:
<CAPTION>
Percentage of Company Average Cost of Fuel
Generation by Source (%) ($ per Million BTU)
-------------------------------- --------------------------------
1995 1994 1993 1992 1991 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil 17.5 27.8 31.3 33.7 42.8 2.66 2.35 2.38 2.40 2.60
Gas 39.9 31.6 24.3 25.7 24.9 2.20 2.28 2.67 2.55 2.08
Nuclear 42.6 40.6 44.4 40.6 32.3 0.43 0.50 0.51 0.52 0.56
==============================================================================
</TABLE>
The majority of the Company's residual oil purchases consists of imported oil
acquired primarily from international suppliers. The Company has contracts
with major oil companies that can supply most of its estimated requirements,
assuming no major disruptions in oil producing regions. Within contract
provisions, the Company has the ability to purchase significant amounts of oil
in the spot market when it is economical to do so.
A portion of the Company's natural gas is supplied on an interruptible basis
by contract. These contracts permit interruptions in deliveries by the
supplier when natural gas pipeline capacity is unavailable. The Company is
currently required to fuel New Boston Station exclusively by natural gas,
except in certain emergency circumstances, as part of a 1991 consent order
with the Massachusetts Department of Environmental Protection (DEP). The
Company has arrangements for a firm supply of natural gas to run the station
at a minimum level and is developing a least-cost plan for operating beyond
this minimum level which principally utilizes interruptible gas supplies or
short-term capacity purchases.
In order to obtain 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.
<PAGE> 4
Seasonal Nature of Business
The Company's kWh sales and revenues are typically higher in the winter and
summer than in the spring and fall as sales tend to vary with weather
conditions. In addition, the Company bills higher base rates to commercial
and industrial customers during the billing months of June through September
as mandated by the DPU. Accordingly, greater than half of the Company's
annual earnings typically occurs in the third quarter. Refer also to the
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.
Competitive pressures on the electric utility industry have increased due to a
variety of factors, including legislative and regulatory proceedings at both
federal and state levels and changes in customer expectations. The trend is
toward promotion of increased competition through modified regulation of the
industry.
To date the effects of competition have been most prominent in the wholesale
electric market. In response to increased competition from other electric
utilities and nonutility generators to sell electricity for resale, the
Company secured long-term power supply agreements with its six wholesale
customers that set rates through 2002 and beyond.
As discussed in the Competition section of Item 7, the Federal Energy
Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking (NOPR) in
March 1995 addressing open transmission access and recovery of previously
incurred costs. The provisions in the NOPR provide a framework for
significant changes in the electric utility industry.
Direct competition with other electric utilities and other energy suppliers
for retail electricity sales is still subject to certain limitations. 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
<PAGE> 5
specific city or town approval and the purchase of Company property within
municipality limits.
Despite the limitations on direct competition, the Company has been
experiencing some forms of increased competition in the retail electric
market. Competition currently exists with alternative fuel suppliers as
customers are able to substitute natural gas, steam or oil for electricity for
heating or cooling purposes. In addition, current legislation allows
industrial and large commercial customers to own and operate their own
electric generating units. Large facilities may also factor the cost of
electricity into their decisions to relocate to new service territories.
Electric utilities are thus under increasing pressure to discount rates.
In August 1995 the DPU issued an order on restructuring of the electric
utility industry. The order provides for Massachusetts-based electric
utilities to restructure their operations to encourage more competition for
customers. Refer to the Competition section of Item 7 for a discussion of the
DPU order and the Company's involvement in the restructuring proceedings.
In addition to its involvement in the DPU's restructuring proceedings, the
Company is actively responding to the current and anticipated changes in the
industry in several ways. In 1995 the Company reorganized into separate
business units and reduced its workforce in order to strengthen its
competitiveness as discussed in Note F to the Consolidated Financial
Statements. It also continued to develop customer alliances and provided
economic development rates to some customers. In addition, the Company
currently has a special lower rate available for a small number of large
manufacturing customers on a limited basis and recently implemented a one-year
pilot program that uses a competitive market index to set electric rates for a
limited number of customers. These actions all signify the Company's
commitment to be a competitively priced, reliable provider of energy.
Research Activities
The Company actively participates in several industry sponsored research
activities. Related expenditures, included in other operations and
maintenance expense on the consolidated income statement in Item 8, were not
material in 1995.
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 environmental-related capital expenditures for the years 1996
through 2000 are currently expected to total $17 million, including $4.5
million in 1996 and $3.5 million in 1997. Additional expenditures could be
required as changes in environmental requirements occur.
The Company is required by the DEP to clean up approximately 40 properties
that it owns or operates in which hazardous materials were previously spilled
<PAGE> 6
or released. In addition, the Company has exposure to potential joint and
several liability for the cleanup of approximately ten multi-party hazardous
waste sites in Massachusetts and other states where it is alleged to have
generated, transported or disposed of hazardous waste at the sites.
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 continue to exist regarding the
ultimate disposal of both the spent nuclear fuel and LLW. Refer to Note E to
the Consolidated Financial Statements in Item 8 for further discussion
regarding spent nuclear fuel and LLW disposal.
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 fuel-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. The Company has the
required discharge permits for each of its electric generating stations.
Public concern continues 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 3,518 full-time and 26 part-time utility employees as of
January 1, 1996, 2,342 of which are represented by two locals of the Utility
Workers Union of America, AFL-CIO. The locals' labor contracts are effective
through 2000. BETG had 46 full-time employees.
(d) Financial Information about Foreign and Domestic Operations and Export
- --------------------------------------------------------------------------
Sales
- -----
Refer to Principal Products and Services of this item for information
regarding the geographical area served by the Company and revenues by class
for the last three years.
<PAGE> 7
(e) Additional Information
- --------------------------
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 FERC has jurisdiction over various phases of
the Company's business including rates for power sold at wholesale for resale,
facilities used for the transmission or sale of that power, certain issuances
of short-term debt and regulation of the system of accounts. The Company's
subsidiary BETG and its subsidiaries are not subject to such regulation.
The Company is required to submit 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 1994 and October 1995. 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, 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.
The Company also owns 9.5% of the common stock of Connecticut Yankee Atomic
Power Company, which owns a nuclear generating unit. Northeast Utilities, the
majority owner of Connecticut Yankee, operates the unit. In March 1996 the
<PAGE> 8
NRC ordered Northeast Utilities to submit a plan within 30 days verifying
operational compliance with licensing documentation at the Connecticut Yankee
unit and another unit owned and operated by Northeast Utilities, or risk
having the plants shut down. This order follows noncompliances discovered at
two of Northeast Utilities' other nuclear units. The Company is unable to
determine at this time what the results of the NRC order will be on the
operations of the Connecticut Yankee unit, or what the impact would be on the
Company if the unit were to be shut down.
Capital Expenditures and Financings
<TABLE>
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 1996 through 2000 are as follows:
<CAPTION>
(in thousands) 1996 1997 1998 1999 2000
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Plant
expenditures $160,000 $140,000 $130,000 $120,000 $110,000
Nuclear fuel
expenditures 48,000 0 27,000 13,000 29,000
AFUDC (1) 2,000 2,000 2,000 2,000 2,000
Long-term debt 101,600 101,600 101,600 1,600 166,600
Preferred stock
sinking fund 2,000 2,000 2,000 2,000 2,000
=============================================================================
<FN>
(1) Excludes AFUDC on nuclear fuel.
</TABLE>
The Company conducts a continuing review of its capital expenditure and
financing programs. These programs and, therefore, the estimates shown above
are subject to revision due to changes in regulatory requirements,
environmental standards, availability and cost of capital, interest rates and
other assumptions.
Plant expenditures in 1995 were $181 million and consisted primarily of
additions to the Company's transmission and distribution systems and nuclear
generation facility. Significant projects included spending of $20 million
for the replacement of the main turbine rotors at Pilgrim Station and $17
million for the replacement of electric system property.
In 1994 the DPU approved the Company's financing plan to issue up to $500
million of securities through 1996 using the proceeds to refinance short and
long-term securities and for capital expenditures. Refer to Notes J and K to
the Consolidated Financial Statements in Item 8 for specific information
relating to the Company's financing activities.
<PAGE> 9
Item 2. Properties and Power Supply
- ------------------------------------
Company-Owned Facilities
<TABLE>
The Company's total electric generation capacity consisted of the following:
<CAPTION>
Year
Unit Location Capacity(a) Type Installed
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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 14 Fossil 1969
generator
Combustion turbine Various 284 Fossil 1966-1971
generators (nine)
=============================================================================
<FN>
(a) In MW based on winter capability audit results.
</TABLE>
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 also owns approximately 6% of W.F. Wyman Unit 4. The 619 MW oil-
fired unit located in Yarmouth, Maine, began operations in 1978 and is
operated by Central Maine Power Company.
Additional electric generation capacity is available to the Company through
its contractual arrangements with other utilities and 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 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, 1995, 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 46 transmission or combined transmission and distribution
substations with transformer capacity of 10,612 megavolt amperes (MVA), 69
distribution substations with transformer capacity of 1,143 MVA and 18 primary
network units with 88 MVA capacity. In addition, high tension service was
delivered to 237 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.
<PAGE> 10
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 one proceeding before the EFSB, which
concerns proposed transmission and station facilities in Hopkinton and
Milford, Massachusetts.
Long-Term Power Contracts
Refer to Note O 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 unit. 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.
The Company has a contract to purchase 9.5% of Connecticut Yankee's nuclear
generating 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:
- ----------------------------------------
The Company currently purchases 533 MW of capacity and associated energy from
non-utility generators. These purchases are from Ocean State Power, Northeast
Energy Associates, L'Energia and MassPower. The Company also purchases power
from two small hydro-electric facilities.
Sales Contracts:
- ---------------
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.
<PAGE> 11
New England Power Pool
The Company is a member of the New England Power Pool (NEPOOL), a voluntary
association of electric utilities and other electricity suppliers in New
England responsible for the coordination, monitoring and directing of the
operations of the major generating and transmission facilities in the region.
To obtain maximum benefits of power pooling, the electric facilities of all
member companies are operated by NEPOOL as if they were a single power system.
This is accomplished through the use of a central dispatching system that uses
the lowest cost generation and transmission equipment available at any given
time. This operation is the responsibility of NEPOOL's central dispatch
center, the New England Power Exchange (NEPEX). As a result of its
participation in NEPOOL, the Company's operating revenues and costs are
affected to some extent by the operations of the other members. The
dispatching of Company-owned generating facilities by NEPEX may be affected by
minimally increasing energy requirements and any additions to New England
generation capacity.
<TABLE>
The table below sets forth certain information as of the date of the Company's
1995-1996 winter and 1995 summer peak loads:
December 11, 1995 August 16, 1995
(winter 1995-96) (summer 1995)
- ------------------------------------------------------------------------
<S> <C> <C>
NEPEX utilities installed capacity:
Seasonal maximum rating 27,187 MW 25,637 MW
Seasonal normal rating 26,839 MW 25,353 MW
NEPEX peak load 19,167 MW 20,486 MW
Company territory peak load 2,458 MW 2,785 MW
========================================================================
</TABLE>
The Company's net capacity was 3,667 MW at its winter peak and 3,445 MW at its
summer peak. Its corresponding NEPOOL capacity obligations were estimated to
be 3,341 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 transmission 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. At December 31, 1995, the Company's portion of these guarantees was
approximately $19 million.
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 (US District Court) 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. The
<PAGE> 12
Company has also been named as a party in a lawsuit filed in both the US
District Court and the Massachusetts Norfolk Superior Court by Subaru of New
England, Inc. and Subaru Distributors Corporation in 1992. The plaintiffs are
claiming certain automobiles stored on lots in South Boston suffered pitting
damage caused by emissions from New Boston Station. The Company believes that
it has a strong defense in this case. It is also involved in certain other
legal matters. The Company is unable to fully determine a range of reasonably
possible litigation costs in excess of amounts previously accrued, although
based on the information currently available, it does not expect that any such
additional costs will have a material impact on its financial condition.
However, additional litigation costs that may result from a change in
estimates could have a material impact on the results of a reporting period in
the near term.
Also refer to the Environmental section in Item 7 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 1995.
<PAGE> 13
Executive Officers of the Registrant
- ------------------------------------
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, 1996 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.
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
Thomas J. May, 48 Chairman of the Board, President
Chairman of the Board, President and Chief Executive Officer (since
and Chief Executive Officer 1995), Chairman of the Board and
Chief Executive Officer (1994-
1995), President and Chief
Operating Officer (1993-1994) and
Executive Vice President (1990-
1993); Director (since 1991)
Chairman of the Board and Chief
Executive Officer and Director,
Harbor Electric Energy Company,
Boston Energy Technology Group,
TravElectric Services Corp. and
Ener-G-Vision, Inc.; Chairman of
the Board and Director, REZ-TEK
International Corp. and Coneco
Corp.
E. Thomas Boulette, 53 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
L. Carl Gustin, 52 Senior Vice President - Corporate
Senior Vice President - Corporate Relations (since 1995), Senior
Relations Vice President - Marketing &
Corporate Relations (1989-1995)
John J. Higgins, Jr., 63 Senior Vice President - Human
Senior Vice President - Human Resources (since 1990)
Resources
</TABLE>
<PAGE> 14
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
Douglas S. Horan, 46 Senior Vice President and General
Senior Vice President and Counsel (since 1995), Vice
General Counsel President and General Counsel
(1994-1995), Deputy General
Counsel (1991-1994) and Associate
General Counsel (1986-1991)
Director and General Counsel,
Harbor Electric Energy Company;
Director, Boston Energy Technology
Group
James J. Judge, 40 Senior Vice President and
Senior Vice President and Treasurer (since 1995), Assistant
Treasurer Treasurer (1989-1995) and
Director - Corporate Planning
(1993-1995)
Senior Vice President, Treasurer
and Director, Harbor Electric
Energy Company and Boston Energy
Technology Group; Director,
Ener-G-Vision, Inc., TravElectric
Services Corp. and REZ-TEK
International Corp.
Ronald A. Ledgett, 57 Senior Vice President - Fossil
Senior Vice President - Fossil (since 1995), Senior Vice
President - Power Delivery (1991-
1995) and Director, Special
Projects (1989-1991)
Alison Alden, 47 Vice President - Sales & Service
Vice President - Sales & Service (since 1993) and Director -
Organization Development (1990-
1993)
Director, Harbor Electric Energy
Company, Boston Energy Technology
Group and Coneco Corp.
Robert A. Ruscitto, 51 Vice President - Field Service and
Vice President - Field Service Electric Delivery (since 1995),
and Electric Delivery Vice President - Electric Customer
Service (1994-1995), General
Manager, Electric Customer Service
(1992-1994) and Manager,
Metropolitan Transmission &
Distribution Department
(1990-1992)
</TABLE>
<PAGE> 15
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
Robert J. Weafer, Jr., 49 Vice President - Finance,
Vice President - Finance, Controller and Chief Accounting
Controller and Chief Officer (since 1991), Controller
Accounting Officer (1988-1991) and Chief Accounting
Officer (1983-1991)
Theodora S. Convisser, 48 Clerk of the Corporation (since
Clerk of the Corporation 1986) and Assistant General
Counsel (since 1984)
Clerk, Harbor Electric Energy
Company, Boston Energy Technology
Group, TravElectric Services
Corp., Ener-G-Vision, Inc.,
REZ-TEK International Corp. and
Coneco Corp.
</TABLE>
<PAGE> 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.
<TABLE>
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 1995 and 1994:
<CAPTION>
1995 1994
- ------------------------------------------------------------------------------
High Low High Low
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First quarter $25 1/2 $23 1/8 $29 7/8 $26
Second quarter 27 23 3/8 29 1/8 25 1/4
Third quarter 27 1/2 24 1/2 27 5/8 22 3/4
Fourth quarter 29 1/2 26 3/4 24 1/4 21 1/2
==============================================================================
</TABLE>
(b) Holders
- -----------
As of December 31, 1995, the Company had 38,205 holders of record of its
common stock.
(c) Dividends
- -------------
<TABLE>
Following are the dividends declared per share of common stock for each of the
quarters in 1995 and 1994:
<CAPTION>
1995 1994
- ---------------------------------------------------------------------
<S> <C> <C>
First quarter $0.455 $0.440
Second quarter 0.455 0.440
Third quarter 0.455 0.440
Fourth quarter 0.470 0.455
=====================================================================
</TABLE>
(d) Other Information
- ---------------------
<TABLE>
Ratio of earnings to fixed charges and ratio of earnings to fixed charges and
preferred stock dividend requirements for the year ended December 31, 1995:
<S> <C>
Ratio of earnings to fixed charges 2.38
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.00
</TABLE>
<PAGE> 17
Item 6. Selected Financial Data
- --------------------------------
<TABLE>
The following table summarizes five years of selected consolidated financial
data of the Company (in thousands, except per share data).
<CAPTION>
1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating
revenues $1,628,503 $1,544,735 $1,482,159 $1,411,753 $1,354,501
Net income 112,310 125,022 118,218 107,298 94,670
Earnings per
common share 2.52(a) 2.41 2.28 2.10 1.96
Total assets 3,643,849 3,616,576 3,476,601 3,294,212 3,098,742
Long-term
debt 1,160,223 1,136,617 1,272,497 1,091,073 1,136,765
Redeemable
preferred/
preference
stock 217,000 219,000 221,000 221,000 221,333
Cash dividends
declared per
common share 1.835 1.775 1.715 1.655 1.595
===========================================================================
<FN>
(a) Excludes $0.44 per share restructuring charge.
Certain reclassifications were made to the data reported in prior years to
conform with the method of presentation used in 1995.
</TABLE>
<PAGE> 18
Item 7. Management's Discussion and Analysis
- ---------------------------------------------
Rate Regulation
The rates we charge our retail customers are regulated by our state
regulators, the Massachusetts Department of Public Utilities (DPU). In 1992
the DPU 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 two annual base rate increases of $29
million effective November 1993 and November 1994 and an annual performance
adjustment charge effective November 1992 through October 2000. The
performance adjustment charge varies annually based on the performance of
Pilgrim Nuclear Power Station. This charge is further described in the
Electric Sales and Revenues section.
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.
We did not make a base rate filing upon the expiration of the 1992 settlement
agreement, therefore base rates currently remain in effect at their 1995
levels.
In February 1996 we filed an industry restructuring plan with the DPU in
response to its August 1995 order on restructuring the electric utility
industry. This plan is expected to lead to negotiations with intervening
parties that will result in an unbundling of our currently integrated monopoly
business into a separate competitive electric production business and a
regulated electric distribution business. Refer to Outlook for the Future for
further information regarding the restructuring of the electric utility
industry in Massachusetts.
Results of Operations
1995 versus 1994
Earnings per common share were $2.08 in 1995 and $2.41 in 1994. Earnings in
1995 reflect a one-time charge of $34 million ($20.7 million net of tax, or
$0.44 per share) associated with our corporate restructuring. The charge
reflects the costs of early retirement and severance programs implemented as
part of our organizational streamlining and reorganization into business
units. Excluding the one-time charge, earnings per common share were $2.52 in
1995, an increase of 4.6% over 1994. This increase is due to the $29 million
annual retail base rate increase effective November 1994, the ending of
amortization of deferred cancelled nuclear costs in 1994, a 1.2% increase in
retail kWh sales and lower revenue reserve provisions. These positive impacts
were partially offset by higher income tax, property tax, nuclear outage
amortization and employee benefit expenses, and an award received on an
eminent domain case in 1994.
<PAGE> 19
Operating revenues
<TABLE>
Operating revenues increased 5.4% over 1994 as follows:
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $59,419
Demand side management revenues 8,783
Wholesale and other revenues 11,126
Short-term sales revenues 4,440
- ------------------------------------------------------
Increase in operating revenues $83,768
======================================================
</TABLE>
Retail electric revenues increased $59 million. Approximately $28 million of
the increased revenues was due to the November 1994 base rate increase and
approximately $11 million was due to the increase in retail kWh sales. Fuel
and purchased power revenues increased $11 million as a result of the timing
effect of fuel and purchased power cost recovery. However, these higher
revenues are offset by higher fuel and purchased power expenses and have no
net effect on earnings. Performance revenues, which vary annually based on
the operating performance of Pilgrim Station, increased $9 million primarily
due to a higher performance rate effective in 1995 and a 17% increase in
generation.
A new annual conservation charge for recovery of demand side management
program costs was implemented in February 1995. Under this charge all 1995
program costs were recovered in 1995. This resulted in higher DSM revenues
and expenses than in prior years when certain program costs were capitalized
for recovery over six years.
The net increase in wholesale and other revenues is primarily due to a $10
million decrease in revenue reserve provisions, which are primarily related to
wholesale customer contract issues.
The increase in short-term sales revenues is due to higher short-term sales
resulting from higher generating availability in 1995. Revenues from short-
term sales serve to reduce fuel and purchased power billings to retail
customers and therefore have no net effect on earnings.
Operating expenses
Total fuel and purchased power expenses increased $22 million primarily due to
the timing effect of fuel and purchased power cost collection. Excluding the
timing effect, fuel expense increased 5% due to an 8% increase in fossil
station generation while purchased power expense was unchanged. Fuel and
purchased power expenses are substantially all recoverable through fuel and
purchased power revenues.
Other operations and maintenance expense increased 0.9% over 1994. Employee
benefit expenses increased primarily due to higher postretirement benefit
expenses recorded in accordance with the 1992 settlement agreement. We also
incurred higher administrative costs in positioning the company for changes in
the industry, which were offset by lower operating costs in the electric
delivery business. Electric generation costs increased only 1% in 1995,
primarily due to a refueling and maintenance outage at Pilgrim Station.
The $34 million one-time restructuring charge was incurred over the third and
fourth quarters of 1995 as a result of our corporate reorganization announced
in July 1995. As part of the reorganization 330 employees elected to retire
under enhanced retirement programs and 149 employees whose positions were
eliminated became eligible for benefits under a special severance program.
<PAGE> 20
See Note F to the Consolidated Financial Statements for additional
information. We expect to achieve ongoing savings as a result of the
restructuring, with a payback period of approximately one year.
Depreciation and amortization expense increased due to a higher average
depreciable plant balance.
In 1994 we fully expensed the remaining deferred costs of the cancelled
Pilgrim 2 nuclear unit.
In the third quarter of 1995 we changed the amortization period of deferred
nuclear outage costs to two years from five years as discussed in Note B to
the Consolidated Financial Statements. The remaining $9 million of deferred
costs allocable to retail customers for refueling outages performed in 1991
and 1993 was written off. Approximately $15 million of deferred costs from
the 1995 refueling outage is being amortized over two years.
The increase in demand side management programs expense is related to the
increase in DSM revenues. Beginning with the annual conservation charge
implemented in February 1995, DSM costs are recovered and expensed primarily
in the year incurred. The 1995 expense includes $31 million of 1995 program
costs and $14 million of amortization of costs capitalized in 1992 through
1994.
Property and other taxes increased primarily due to higher Boston property
taxes resulting from capital additions.
Our effective annual income tax rate for 1995 was 37.1% vs. 31.4% for 1994.
The higher rate is the result of a $10 million adjustment to deferred income
taxes made in 1994 in accordance with the 1992 settlement agreement.
Other income
The net decrease in other income is primarily due to a $5.7 million gain
recognized in 1994 from a court ruling on a 1989 eminent domain taking of
certain of our property.
Interest charges
Interest charges on long-term debt increased due to a $125 million debentures
issuance in May 1995, partially offset by interest savings from first mortgage
bond and debenture redemptions in 1994. Other interest charges increased
slightly due to higher short-term interest rates partially offset by a lower
average short-term debt level. Allowance for borrowed funds used during
construction (AFUDC), which represents the financing costs of construction,
decreased due to a lower construction work in progress balance and shorter
construction periods, partially offset by a higher AFUDC rate related to the
higher short-term interest rates.
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 $29 million annual 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.
<PAGE> 21
Operating revenues
<TABLE>
Operating revenues increased 4.2% over 1993 as follows:
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
Retail electric revenues $62,945
Demand side management revenues 5,056
Wholesale and other revenues (6,644)
Short-term sales revenues 1,219
- ------------------------------------------------------
Increase in operating revenues $62,576
======================================================
</TABLE>
Retail electric revenues increased $63 million. The November 1993 and 1994
base rate increases resulted in $29 million of the increased revenues, and
approximately $6 million was due to the 2% increase in retail kWh sales. Fuel
and purchased power revenues increased $28 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.
Wholesale and other revenues decreased primarily due to an $8.5 million
increase in revenue reserve provisions in 1994 related to certain wholesale
customer 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.
Other operations and maintenance expense increased 7.4% 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 recorded 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 in 1994 and 1993 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.
<PAGE> 22
Municipal property and other taxes increased primarily as a result of higher
Boston property taxes due to a tax rate increase and capital additions.
Our effective annual income tax rate for 1994 was 31.4% vs. 23.4% for 1993.
Both rates were reduced from the statutory rate by adjustments to deferred
income taxes of $10 million in 1994 and $20 million in 1993 made in accordance
with the 1992 settlement agreement.
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 certain of our
property.
Interest charges
Total interest charges 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. AFUDC increased as a result of a higher AFUDC rate related
to the higher short-term interest rates.
Electric Sales and Revenues
Electric sales
Retail kWh sales increased 1.2% in 1995 primarily due to the positive effects
of a stronger economy on commercial customers. This sector represents
approximately 50% of our electric operating revenues.
Demand side management conservation programs are designed to assist customers
in reducing electricity use and, therefore, result in lower growth in
electricity sales. We receive approval from our state regulators for DSM
spending levels and recovery amounts through an annual conservation charge.
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. In
1995 a new annual conservation charge was implemented under which all 1995
program costs were recovered in 1995. 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 are
recovering over six years.
Electric revenues
As discussed in the Rate Regulation section, our 1992 settlement agreement
provided us with two annual retail base rate increases of $29 million
effective in 1993 and 1994 and an eight-year annual performance adjustment
charge. We did not make a base rate filing upon the expiration of the
settlement agreement in 1995, therefore base rates currently remain in effect
at their 1995 levels. Due to our continued commitment to controlling costs
and increasing operating efficiencies, maintaining these rate levels in our
current regulatory environment is not expected to significantly affect our
financial condition or results of operations.
The annual performance adjustment charge provides us with opportunities to
improve our financial results. The most significant potential impact of this
<PAGE> 23
performance incentive is based on Pilgrim Station's annual capacity factor.
An annual capacity factor between 60% and 68% would provide us with
approximately $51 million of revenues in the performance year ended October
1996. For each percentage point increase in capacity factor above 68%, annual
revenues will increase by approximately $750,000. For each percentage point
decrease in capacity factor below 60% (to a minimum of 35%), annual revenues
will decrease by approximately $840,000. Pilgrim's capacity factor for the
performance year ending October 1996 is currently expected to be approximately
91%, an increase from the 67% capacity factor achieved in the performance year
ended October 1995. There are no major outages scheduled for the current
performance year. Pilgrim was out of service in November 1994 and for a 73-
day refueling and maintenance outage in 1995. We earned approximately $49
million in revenues related to Pilgrim's capacity factor in the performance
year ended October 31, 1995.
Pilgrim Station was shut down for three months in 1994 due to a non-nuclear
problem with its electrical generator. Regularly scheduled maintenance work
was also performed during the shutdown. The power needs usually met by the
station were met by other generating plants or purchased from other suppliers
as necessary. We do not believe that the generator damage resulted from
actions within our control. Our recovery of the incremental purchased power
costs during the outage through fuel and purchased power revenues, however, is
subject to review by the DPU under a generating unit performance program.
Liquidity
We meet our capital expenditure cash requirements primarily with internally
generated funds. These funds provided for 95%, 98% and 77% of our plant and
nuclear fuel expenditures in 1995, 1994 and 1993, respectively. Our current
estimate of plant expenditures for 1996 is $160 million. These expenditures
will be used primarily to maintain and improve existing transmission and
distribution facilities. We expect plant expenditures to remain level or
decline slightly from the 1996 amount in the four years thereafter. In
addition to capital expenditures we have long-term debt and preferred stock
payment requirements of $103.6 million per year in 1996 through 1998, $3.6
million in 1999 and $168.6 million in 2000.
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,
the Federal Energy Regulatory Commission (FERC), 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, 1995, we had $126 million of short-term debt outstanding, none of
which was incurred under the revolving credit agreement. In 1994 the DPU
approved our financing plan to issue up to $500 million of securities through
1996 using the proceeds to refinance short and long-term securities and for
capital expenditures. Refer to Notes J and K to the Consolidated Financial
Statements for specific information relating to our recent financing
activities.
Outlook for the Future
Competition
Competitive pressures on the electric utility industry have increased due to a
variety of factors, including legislative and regulatory proceedings at both
federal and state levels and changes in customer expectations. The trend is
<PAGE> 24
toward promotion of increased competition through modified regulation of the
industry.
To date the effects of competition have been most prominent in the wholesale
electric market. In response to increased competition from other electric
utilities and nonutility generators to sell electricity for resale, we secured
long-term power supply agreements with our six wholesale customers that set
rates through 2002 and beyond. In 1995, our largest retail customer, the
Massachusetts Port Authority (Massport), issued a request for proposals for a
wholesale supplier of electricity. We successfully retained Massport as a
customer through a ten-year wholesale power supply agreement effective
November 1995. We are awaiting approval of this agreement from the FERC.
In March 1995 the FERC issued a Notice of Proposed Rulemaking (NOPR)
addressing open transmission access and recovery of previously incurred costs.
If approved, the NOPR would require all utilities with transmission systems to
file open access tariffs at the FERC, to provide service under those tariffs
to transmission customers comparable to service provided to their electric
energy customers and to take service under the tariffs for wholesale purchases
and sales. The NOPR also supports the full recovery of legitimate and
verifiable costs previously incurred under federal and state regulation. The
provisions in the NOPR provide a framework for significant changes in the
electric utility industry.
We have also been experiencing increased competition in the retail electric
market. Competition currently exists with alternative fuel suppliers as
customers are able to substitute natural gas, steam or oil for electricity for
heating or cooling purposes. In addition, industrial and large commercial
customers may pursue options to generate their own electric power or factor
the cost of electricity into their decisions to relocate to new service
territories. Electric utilities are thus under increasing pressure from these
customers to discount rates.
In August 1995 the DPU issued an order on restructuring of the electric
utility industry. The order provides for Massachusetts-based electric
utilities to restructure their operations to encourage more competition for
customers. It also includes the following principles for a restructured
electric industry:
- provide the broadest possible customer choice
- provide all customers with an opportunity to share in the benefits of
increased competition
- ensure full and fair competition in generation markets
- functionally separate generation, transmission and distribution services
- provide universal service
- support and further the goals of environmental regulation
- rely on incentive regulation where a fully competitive market cannot
exist, or does not yet exist
The DPU order also set the following principles to guide the transition from a
regulated to a competitive industry structure:
- honor existing commitments
- unbundle rates for generation, transmission and distribution
- reduce rates in the near term
- maintain demand side management programs
- ensure an orderly and quick transition that minimizes customer confusion
The order provides a reasonable opportunity for the recovery of net,
nonmitigatable potentially strandable costs (strandable costs), over a period
<PAGE> 25
of up to ten years. These costs include investments in plant that might not
be recoverable in a competitive market, liabilities for future decommissioning
of nuclear plants, the amounts by which certain purchase power contracts
exceed the competitive price for generation, and prudently incurred regulatory
assets. We are looking at possibilities for mitigating our potentially
strandable costs, including potential revisions to depreciation and
amortization periods.
The order establishes only general principles for the transition to a
competitive market and does not establish a particular model for the new
industry structure. Each of the Massachusetts-based electric utilities is
required to develop a plan for moving toward competition consistent with the
DPU's order and encouraged to negotiate with all interested parties while
doing so. We were one of three companies required to file a restructuring
plan in February 1996. Our plan is consistent with the general principles
outlined in the order, including unbundled rates for generation, transmission
and distribution. It provides for and is based upon full recovery of
strandable costs through a nonbypassable access charge. This charge is to be
paid by customers as a condition of receiving service over our distribution
system, which remains a monopoly function. We expect to enter into
negotiations with intervening parties that will result in new rates and
performance incentives to be implemented in the new industry structure.
In addition to our involvement in the DPU's restructuring proceedings, we are
actively responding to the current and anticipated changes in the industry in
several ways. In 1995 we reorganized the company into separate business units
in order to strengthen our competitiveness. These business units, Customer,
Generating-Fossil, Generating-Nuclear and Corporate Services, were designed to
sharpen management focus along our significant lines of operation while
maintaining company-wide strategic goals. As a result of enhanced retirement
programs and a special severance program offered during this corporate
restructuring, we reduced our workforce by 12%. We expect to achieve ongoing
savings as a result of the restructuring, with a payback period of
approximately one year. We also continued to develop customer alliances and
provided economic development rates to some customers. In addition, we
currently have a special lower rate available for a small number of large
manufacturing customers on a limited basis and we recently implemented a one-
year pilot program that uses a competitive market index to set electric rates
for a limited number of customers. These actions all signify our commitment
to be a competitively priced, reliable provider of energy. We do not expect
the economic development rates, the lower manufacturing customer rates or the
pilot program to have a significant impact on our financial condition or
results of operations.
In the rate-regulated environment based on cost recovery that we have
traditionally operated in, we are subject to certain accounting standards that
are not applicable to other businesses and industries. The standards allow us
to record certain costs as regulatory assets instead of as expenses when
incurred when we expect to receive future rate recovery of the costs. We
believe that we currently meet the criteria of these standards. In addition
to the specifically identified regulatory assets on our consolidated balance
sheets, there may be differences in the carrying value of our net utility
plant compared to what the amount would have been if we were not subject to
rate regulation. These potential differences would be due to differing plant
depreciable lives for regulatory and non-regulatory accounting standards. We
have not yet fully determined to what extent such differences may exist. The
effects of competition and modified regulation could, in the near term, cause
us to no longer meet the criteria for application of the regulatory accounting
standards for some of our operations. Should this occur we would have to take
a noncash write-off of our affected regulatory assets and adjust our affected
<PAGE> 26
plant balances if necessary by recording an addition to depreciation expense
at that time. However, the DPU order on industry restructuring provides a
reasonable opportunity for recovery of these previously incurred costs, which
are also provided for in our related plan. We expect to recover all
strandable costs through our distribution system, which we expect will remain
rate-regulated, and therefore will continue to meet the criteria of these
accounting standards. If it does not continue to be likely that we will
recover all our regulatory assets and generating plant costs as our
restructuring plan is ultimately finalized, we would have to write off such
portions that are no longer probable of recovery in accordance with Financial
Accounting Standards No. 121, Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of. See Note M to the
Consolidated Financial Statements for information on this new accounting
standard. The nonrecovery of specifically identified and other embedded
regulatory assets or plant costs could have a material impact on our results
of operations and financial condition.
Resource regulation
In this period of transition in the electric utility industry we remain
subject to current regulatory requirements. The DPU requires utilities to
purchase power from qualifying nonutility generators at prices set through a
bidding process. In a continuation of a dispute which originated in 1991, the
DPU is currently investigating whether we should again be ordered to negotiate
a contract to purchase power from an independent power producer, JMC Altresco,
Inc. We have consistently opposed this order since we do not believe we need
any new power for several years and the proposed contract would impose
excessive costs on our customers. In 1995 we filed a motion to dismiss the
matter, which is pending. We also filed testimony comparing the cost of
Altresco to projected market costs and hearings are currently ongoing. In a
separate but related matter, we appealed the Massachusetts Energy Facilities
Siting Board's (EFSB) approval of construction of Altresco's proposed
generating station based partly on the EFSB's failure to consider market
information and forecasts.
We also currently remain subject to the DPU's 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. As a result of our 1994 IRM filing, the
DPU found that we did not have a need for additional generating capacity
through 2001 and therefore were not required to issue a competitive request
for proposals for new generating capacity. Required updates to our IRM filing
have been postponed due to the current industry restructuring proceedings
ongoing at the DPU.
Nonutility business
We have an unregulated subsidiary, Boston Energy Technology Group (BETG), in
which we have authority from the DPU to invest up to $45 million. This wholly
owned subsidiary engages primarily in energy conservation services and the
production of water treatment systems. In 1996 BETG entered into a joint
venture to build a series of ice-based cooling systems as an alternative to
costly chemical systems. BETG's investment in this joint venture, Northwind
Boston, is 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.
<PAGE> 27
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 approximately 40 properties where oil or hazardous materials
were previously spilled or released. We are required to clean up these
properties in accordance with a timetable developed by the Massachusetts
Department of Environmental Protection (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 approximately ten multi-party hazardous waste sites in
Massachusetts and other states where we are alleged to have generated,
transported or disposed of hazardous waste at the sites. At the majority of
these sites we are one of many potentially responsible parties and we
currently expect to have only a small percentage of the potential liability.
Through December 31, 1995, 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 that may result
from a change in estimates could have a material impact on the results of a
reporting period in the near term.
Uncertainties continue to exist with respect to the disposal of both spent
nuclear fuel and low-level radioactive waste (LLW) resulting from the
operation of Pilgrim Station. The United States Department of Energy (DOE) is
responsible for the ultimate disposal of spent nuclear fuel; however, there
are uncertainties regarding the DOE's schedule of acceptance of spent fuel for
disposal. In 1995 we regained access to the LLW disposal facility located in
Barnwell, South Carolina. Refer to Note E to the Consolidated Financial
Statements for further discussion regarding spent nuclear fuel and LLW
disposal.
As part of a 1991 DEP consent order, we are currently required to fuel New
Boston Station exclusively by natural gas, except in certain emergency
circumstances. The station has the ability to burn natural gas, oil or both.
We have arrangements for a firm supply of natural gas to run the station at a
minimum level and are developing a least-cost plan for operating beyond this
minimum level which principally utilizes interruptible gas supplies or short-
term capacity purchases.
The 1990 Clean Air Act Amendments 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 allowances 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 low nitrogen oxides burners at New Boston, have
<PAGE> 28
allowed 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 or years
thereafter. The extent of any additional emission restrictions and the cost
of any further modifications is uncertain at this time.
Public concern continues regarding electromagnetic fields (EMF) associated
with electric transmission and distribution facilities and appliances and
wiring in buildings and homes. Such concerns have included the possibility of
adverse health effects caused by EMF as well as perceived effects on property
values. Some scientific reviews conducted to date have suggested associations
between EMF and potential health effects, while other studies have not
substantiated such associations. 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.
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. We have also been named as a party in a lawsuit
by Subaru of New England, Inc. and Subaru Distributors Corporation. The
plaintiffs are claiming certain automobiles stored on lots in South Boston
suffered pitting damage caused by emissions from New Boston Station. We
believe that we have a strong defense in this case. We are also involved in
certain other legal matters. We are unable to fully determine a range of
reasonably possible litigation costs in excess of amounts previously accrued,
although based on the information currently available, we do not expect that
any such additional costs will have a material impact on our financial
condition. However, additional litigation costs that may result from a change
in estimates could have a material impact on the results of a reporting period
in the near term.
New accounting pronouncement
Statement of Financial Accounting Standards No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,
is effective in 1996. This statement establishes accounting standards for
recognizing and measuring asset impairment losses. Refer to Note M to the
Consolidated Financial Statements for more information regarding this
statement and its potential effects.
Safe harbor cautionary statement
We occasionally make forward-looking statements such as forecasts and
projections of expected future performance or statements of our plans and
objectives. These forward-looking statements may be contained in filings with
the Securities and Exchange Commission, press releases and oral statements.
Actual results could potentially differ materially from these statements.
Therefore, no assurances can be given that the outcomes stated in such
forward-looking statements and estimates will be achieved.
<PAGE> 29
The above sections include certain forward-looking statements about the
effects of the industry restructuring process and our related plan, operating
results, Pilgrim Station's performance and environmental and legal issues.
The effects of the industry restructuring process currently underway at the
DPU and our related plan could differ from our expectations. This could occur
as regulatory decisions and negotiated settlements between utilities and
intervenors are finalized during the restructuring process. In addition, the
development of a competitive electric generation market and the impacts of
actual electric supply and demand in New England may affect the ultimate
results of the industry restructuring and our plan.
The impacts of our continued cost control procedures on our operating results
could differ from our expectations. The effects of changes in economic
conditions, tax rates, interest rates, technology and the prices and
availability of operating supplies could materially affect our projected
operating results.
Pilgrim Station's performance could differ from our expectations. The
station's capacity factor could be impacted by changes in regulations or by
unplanned outages resulting from certain operating conditions.
The impacts of various environmental and legal issues could differ from our
expectations. New regulations or changes to existing regulations could impose
additional operating requirements or liabilities. The effects of changes in
specific hazardous waste site conditions and cleanup technology could affect
our estimated cleanup liabilities. The impacts of changes in available
information and circumstances regarding legal issues could affect our
estimated litigation costs.
<PAGE> 30
<TABLE>
Item 8. Financial Statements and Supplementary Financial Information
- ---------------------------------------------------------------------
Consolidated Statements of Income
<CAPTION>
years ended December 31,
(in thousands, except earnings per share) 1995 1994 1993
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $1,628,503 $1,544,735 $1,482,159
- ---------------------------------------------------------------------------
Operating expenses:
Fuel 170,337 156,951 170,799
Purchased power 365,469 356,874 370,049
Other operations and maintenance 439,263 435,824 405,609
Restructuring costs 34,000 0 0
Depreciation and amortization 153,339 148,845 137,710
Amortization of deferred cost of
cancelled nuclear unit 0 19,791 0
Amortization of deferred nuclear
outage costs 18,933 7,721 6,546
Demand side management programs 45,125 35,438 37,504
Taxes - property and other 106,361 100,015 93,102
Income taxes 68,276 54,798 35,143
- ---------------------------------------------------------------------------
Total operating expenses 1,401,103 1,316,257 1,256,462
- ---------------------------------------------------------------------------
Operating income 227,400 228,478 225,697
Other income (expense), net (575) 3,979 211
- ---------------------------------------------------------------------------
Operating and other income 226,825 232,457 225,908
- ---------------------------------------------------------------------------
Interest charges:
Long-term debt 106,640 102,570 104,375
Other 12,642 12,343 9,778
Allowance for borrowed funds used
during construction (4,767) (7,478) (6,463)
- ---------------------------------------------------------------------------
Total interest charges 114,515 107,435 107,690
- ---------------------------------------------------------------------------
Net income 112,310 125,022 118,218
Preferred dividends provided 15,571 15,765 15,705
- ---------------------------------------------------------------------------
Balance available for common stock $ 96,739 $ 109,257 $ 102,513
===========================================================================
Weighted average common shares outstanding 46,592 45,338 44,959
Earnings per share of common stock $ 2.08 $ 2.41 $ 2.28
===========================================================================
</TABLE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
years ended December 31,
(in thousands) 1995 1994 1993
- ---------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $ 247,004 $ 218,292 $ 192,948
Net income 112,310 125,022 118,218
- ---------------------------------------------------------------------------
Subtotal 359,314 343,314 311,166
- ---------------------------------------------------------------------------
Cash dividends declared:
Preferred stock 15,571 15,765 15,705
Common stock 86,399 80,545 77,169
- ---------------------------------------------------------------------------
Subtotal 101,970 96,310 92,874
- ---------------------------------------------------------------------------
Balance at end of year $ 257,344 $ 247,004 $ 218,292
===========================================================================
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 31
<TABLE>
Consolidated Balance Sheets
<CAPTION>
December 31,
(in thousands) 1995 1994
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Assets
Utility plant in service, at
original cost $4,315,422 $4,074,810
Less: accumulated depreciation 1,439,996 $2,875,426 1,344,452 $2,730,358
- ------------------------------------------------------------------------------
Nuclear fuel 302,594 291,836
Less: accumulated amortization 251,951 50,643 236,239 55,597
- ------------------------------------------------------------------------------
Construction work in progress 29,573 144,048
- ------------------------------------------------------------------------------
Net utility plant 2,955,642 2,930,003
Investments in electric companies,
at equity 23,620 24,678
Nuclear decommissioning trust 102,894 82,831
Current assets:
Cash and cash equivalents 5,841 6,822
Accounts receivable 219,114 189,361
Accrued unbilled revenues 37,113 32,240
Fuel, materials and supplies,
at average cost 59,631 71,560
Prepaid expenses and other 23,607 345,306 26,693 326,676
- ------------------------------------------------------------------------------
Deferred debits:
Regulatory assets 156,774 198,148
Intangible asset - pension 27,386 22,849
Other 32,227 216,387 31,391 252,388
- ------------------------------------------------------------------------------
Total assets $3,643,849 $3,616,576
==============================================================================
Capitalization and Liabilities
Common stock equity $ 989,438 $ 915,747
Cumulative preferred stock:
Nonmandatory redeemable series 123,000 123,000
Mandatory redeemable series 92,000 94,000
Long-term debt 1,160,223 1,136,617
Current liabilities:
Long-term debt/preferred
stock due within one year $ 102,667 $ 102,250
Notes payable 126,441 214,786
Accounts payable 133,474 130,496
Accrued interest 25,113 24,464
Dividends payable 25,351 23,533
Pension benefits 32,602 31,908
Other 105,442 551,090 85,204 612,641
- ------------------------------------------------------------------------------
Deferred credits:
Power contracts 21,396 40,277
Accumulated deferred income taxes 497,282 515,454
Accumulated deferred investment
tax credits 62,970 67,048
Nuclear decommissioning reserve 113,288 92,404
Other 33,162 728,098 19,388 734,571
- ------------------------------------------------------------------------------
Commitments and contingencies - -
- ------------------------------------------------------------------------------
Total capitalization and liabilities $3,643,849 $3,616,576
==============================================================================
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 32
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
years ended December 31,
(in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Operating activities:
Net income $112,310 $125,022 $118,218
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation 148,630 142,932 130,074
Amortization of nuclear fuel 19,029 18,810 21,816
Amortization of deferred cost of cancelled
nuclear unit, net 0 19,067 0
Amortization of deferred nuclear outage
costs 18,933 7,721 6,546
Other amortization 15,702 14,692 10,158
Deferred income taxes (21,115) (4,184) 10,303
Investment tax credits (4,078) (4,092) (4,073)
Allowance for borrowed funds used during
construction (4,767) (7,478) (6,463)
Net changes in:
Accounts receivable and accrued
unbilled revenues (34,626) (20,701) 13,206
Fuel, materials and supplies 7,202 3,093 9,722
Accounts payable 2,978 23,196 (18,916)
Other current assets and liabilities 26,485 35,217 25,660
Other, net 23,975 14,847 (20,437)
- -----------------------------------------------------------------------------
Net cash provided by operating activities 310,658 368,142 295,814
- -----------------------------------------------------------------------------
Investing activities:
Plant expenditures (excluding AFUDC) (180,822) (198,771) (246,774)
Nuclear fuel expenditures (13,621) (21,934) (6,491)
Capitalized demand side management
expenditures 0 (37,007) (37,156)
Sale of plant assets, net 3,018 15,972 0
Nuclear decommissioning trust investments (20,063) (16,771) (15,189)
Electric company investments 1,058 (386) 1,106
- -----------------------------------------------------------------------------
Net cash used by investing activities (210,430) (258,897) (304,504)
- -----------------------------------------------------------------------------
Financing activities:
Issuances:
Common stock 64,888 10,634 10,855
Preferred stock 0 0 40,000
Long-term debt 125,000 15,000 815,000
Redemptions:
Preferred stock (2,000) (2,000) (40,000)
Long-term debt (100,600) (50,000) (648,625)
Net change in notes payable (88,345) 10,635 (71,349)
Dividends paid (100,152) (95,460) (92,370)
- -----------------------------------------------------------------------------
Net cash provided (used) by financing activities (101,209) (111,191) 13,511
- -----------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents (981) (1,946) 4,821
Cash and cash equivalents at the
beginning of the year 6,822 8,768 3,947
- -----------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $ 5,841 $ 6,822 $ 8,768
=============================================================================
Cash paid during the year for:
Interest, net of amounts capitalized $113,945 $108,462 $103,720
Income taxes $ 96,180 $ 46,074 $ 30,305
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
<PAGE> 33
Notes to Consolidated Financial Statements
Note A. Nature of Operations
We are an investor-owned regulated public utility operating in the energy and
energy services business. This includes the generation, purchase,
transmission, distribution and sale of electric energy and the development and
implementation of electric demand side management programs. A portion of our
generation is produced by a nuclear unit, Pilgrim Station. We supply
electricity at retail to an area of 590 square miles, including the City of
Boston and 39 surrounding cities and towns. We also supply electricity at
wholesale for resale to other utilities and municipal electric departments.
Electric operating revenues were 89% retail and 11% wholesale in 1995.
Note B. Significant Accounting Policies
1. Basis of Consolidation and Accounting
The consolidated financial statements include the activities of our wholly
owned subsidiaries, Harbor Electric Energy Company and Boston Energy
Technology Group. All significant intercompany transactions have been
eliminated. Certain prior period amounts on the financial statements were
reclassified to conform with the current presentation.
We follow accounting policies prescribed by our federal and state regulators,
the Federal Energy Regulatory Commission (FERC) and the Massachusetts
Department of Public Utilities (DPU). We are also subject to the accounting
and reporting requirements of the Securities and Exchange Commission. The
financial statements conform with generally accepted accounting principles
(GAAP). As a rate-regulated company we are subject to Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (SFAS 71), under GAAP. The application of SFAS 71 results in
differences in the timing of recognition of certain expenses from that of
other businesses and industries. The preparation of financial statements in
conformity with GAAP requires us to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosures of contingent
assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from these estimates.
2. Revenues
We record 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.
<PAGE> 34
4. Depreciation and Nuclear Fuel Amortization
Our physical property was depreciated on a straight-line basis in 1995, 1994
and 1993 at composite rates of 3.10%, 3.11% and 3.09% per year, respectively,
based on estimated useful lives of the various classes of property. The cost
of decommissioning Pilgrim Station is excluded from these 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 defer the incremental costs associated with nuclear refueling outages and
amortize them over future periods. In 1995 we changed the amortization period
to two years from five years. The two-year amortization period is consistent
with the two-year cycle between nuclear refueling outages at Pilgrim Station.
The change from the prior five-year amortization period approved in the 1992
settlement agreement was made following the DPU's August 1995 order on
electric industry restructuring, which is discussed further in the Outlook for
the Future section of Management's Discussion and Analysis. This order
requires utilities to mitigate potentially strandable costs by available and
reasonable means. The prior regulatory treatment of recovery over a five year
period resulted in a significant lag between the expenditure and recovery of
outage costs. We decided not to request recovery of the buildup of costs
resulting from this regulatory lag. Accordingly, the remaining $9 million of
deferred costs allocable to retail customers for refueling outages performed
in 1991 and 1993 was written off. Approximately $15 million of deferred costs
from the 1995 refueling outage is being amortized over two years.
6. Amortization of Discounts and Redemption Premiums on Debt
We expense discounts, 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 1995, 1994 and 1993
were 6.35%, 4.45% and 3.62%, 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 when purchased. Outstanding checks are
included in cash and accounts payable until presented for payment.
<PAGE> 35
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 are expected to be collected
from customers through future charges in accordance with agreements with the
DPU. These costs are to be expensed when the corresponding revenues are
received in order to appropriately match revenues and expenses. The majority
of these costs is currently being recovered from customers over varying time
periods. No return on investment was earned on the regulatory assets.
<TABLE>
Regulatory assets consisted of the following:
<CAPTION>
December 31,
1995 1994
- ------------------------------------------------------------------
<S> <C> <C>
Redemption premiums $ 44,709 $52,859
Income taxes, net 46,121 44,745
Power contracts 21,396 40,277
Pension and postretirement costs 13,811 22,761
Nuclear outage costs 13,471 17,804
Other 17,266 19,702
- ------------------------------------------------------------------
$156,774 $198,148
==================================================================
</TABLE>
Note C. Rate Regulation
In 1992 the DPU approved a three-year settlement agreement relating to our
rate case proceedings. The agreement provided for retail rate increases,
accounting adjustments and demand side management program expenditures;
clarified the timing and recognition of certain expenses and set limits on our
rate of return on common equity through 1995.
In February 1996 we filed an industry restructuring plan with the DPU in
response to its August 1995 order on restructuring the electric utility
industry. This plan is expected to lead to negotiations with intervening
parties that will result in new rates and performance incentives to be
implemented in a new industry structure with a competitive generation market
and incentive-regulated transmission and distribution systems. Refer to
Management's Discussion and Analysis for further information regarding the
restructuring of the electric utility industry in Massachusetts and our
proposed plan. State regulatory proceedings do not affect our contract or
wholesale power rates, which are regulated by the FERC.
Note D. Income Taxes
Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109), which
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 $46.1 million and $44.7 million and corresponding net
increases in accumulated deferred income taxes as of December 31, 1995, and
December 31, 1994, respectively. The regulatory assets represent the
additional future revenues to be collected from customers for deferred income
taxes.
<PAGE> 36
<TABLE>
Accumulated deferred income taxes consisted of the following:
<CAPTION>
December 31,
(in thousands) 1995 1994
- ------------------------------------------------------------------------------
<S> <C> <C>
Deferred tax liabilities:
Plant-related $521,280 $511,572
Other 95,148 105,786
- ------------------------------------------------------------------------------
616,428 617,358
- ------------------------------------------------------------------------------
Deferred tax assets:
Plant-related 12,590 13,216
Investment tax credits 40,632 43,273
Alternative minimum tax 0 1,332
Other 65,924 44,083
- ------------------------------------------------------------------------------
119,146 101,904
- ------------------------------------------------------------------------------
Net accumulated deferred income taxes $497,282 $515,454
==============================================================================
</TABLE>
No valuation allowances for deferred tax assets are deemed necessary.
<TABLE>
Components of income tax expense were as follows:
<CAPTION>
years ended December 31,
(in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current income tax expense $93,469 $63,358 $28,913
Deferred tax expense (21,115) (4,468) 10,303
Investment tax credits (4,078) (4,092) (4,073)
- -----------------------------------------------------------------------------
Income taxes charged to operations 68,276 54,798 35,143
- -----------------------------------------------------------------------------
Taxes on other income:
Current (1,729) 2,550 1,205
Deferred 0 284 0
- -----------------------------------------------------------------------------
(1,729) 2,834 1,205
- -----------------------------------------------------------------------------
Total income tax expense $66,547 $57,632 $36,348
=============================================================================
</TABLE>
<TABLE>
The effective income tax rates reflected in the consolidated financial
statements and the reasons for their differences from the statutory federal
income tax rate were as follows:
<CAPTION>
1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 4.3 4.3 4.2
Investment tax credits (2.3) (2.3) (2.6)
Municipal property tax adjustment - - (0.6)
Reversal of deferred taxes - settlement agreement - (5.5) (13.0)
Other 0.1 (0.1) 0.4
- -----------------------------------------------------------------------------
Effective tax rate 37.1% 31.4% 23.4%
=============================================================================
</TABLE>
Note E. Nuclear Decommissioning and Nuclear Waste Disposal
1. Nuclear Decommissioning
When Pilgrim Station's operating license expires in 2012 we will be required
to decommission the plant. We are currently expensing an estimate of the
decommissioning costs over Pilgrim's expected service life. The 1995 expense
of approximately $14 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 that documents a cost of approximately $328
million to decommission the plant using the "green field" method, which
provides for the plant site to be completely restored to its original state.
The cost estimate, which involves many uncertainties, was incorporated in our
<PAGE> 37
1992 retail settlement agreement. We receive recovery of the annual expense
from charges to our retail customers and from other utility companies and
municipalities which purchase a contracted amount of Pilgrim's electric
generation. The funds we collect from decommissioning charges are deposited
in an external trust and are restricted 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 in order to evaluate the potential impact of long-term spent fuel
storage options resulting from delays in the United States Department of
Energy (DOE) spent fuel removal program. (See part 2 below for a discussion
of spent fuel removal.) The partial update indicates an estimated
decommissioning cost of $400 million in 1991 dollars based upon a revised
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 February 1996 the Financial Accounting Standards Board (FASB) issued
proposed new rules for accounting for liabilities related to closure and
removal of long-lived assets, which includes decommissioning. If these draft
rules are adopted we would be required to retroactively recognize the entire
estimated liability for decommissioning costs on the balance sheet, offset by
an addition to nuclear plant. The plant addition would be depreciated over
Pilgrim's expected service life. The liability would be measured based on the
present value of estimated future cash flows. The cumulative effect of
adoption of these proposed rules could result in a regulatory asset to be
recovered from customers to the extent that the present value difference in
the liability between when the liability was incurred and when the rules are
adopted exceeds the depreciation expense previously recognized for
decommissioning. If it is not probable that we could recover these costs from
customers, we would have to charge the cumulative effect of the difference to
income instead of recording a regulatory asset. In addition, trust fund
earnings would be reported on the income statement.
2. Spent Nuclear Fuel
The spent fuel storage facility at Pilgrim Station provides storage capacity
through approximately 2003. We have a license amendment from the Nuclear
Regulatory Commission to modify the facility to provide sufficient room for
spent nuclear fuel generated through the end of Pilgrim's operating license in
2012; however, any further modifications are subject to review by the DPU. 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 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
1994 we and other interested parties filed petitions in the U.S. Court of
<PAGE> 38
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
We regained access to low-level radioactive waste (LLW) disposal facilities
located in Barnwell, South Carolina, in 1995. This site is currently the only
disposal facility available to us. Legislation has been enacted in
Massachusetts establishing a regulatory process for managing the state's LLW,
including the possible siting, licensing and construction of a disposal
facility within the state, or, alternatively, an agreement with one or more
other states. Pending the construction of a disposal facility within the
state or the adoption by the state of some other LLW management procedure, we
will continue to monitor the situation and investigate other available
options.
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.
Note F. Corporate Restructuring
In 1995 we streamlined the corporate organization and reorganized the company
into separate business units in order to strengthen our competitiveness in the
changing electric energy market. In conjunction with this reorganization we
offered enhanced retirement programs and implemented a special severance
program to reduce employee staffing levels. Under the enhanced retirement
programs 330 employees elected to retire, and 149 employees whose positions
were eliminated became eligible for benefits under the special severance
program. These programs resulted in a $34 million pre-tax charge ($20.7
million net of tax) over the third and fourth quarters of 1995. The charge
consisted of $24 million for the retirement programs and $10 million for the
severance program.
The enhanced retirement programs were offered to all employees at least 55
years old, with different years of service requirements for management and
union employees. The programs provided for supplemental salary payments and
waivers of the early retirement pension reduction and the medical and life
insurance benefits years of service requirement. The special severance
program was provided for all employees whose positions were eliminated in the
reorganization, who were all management and administrative support personnel.
Severance benefits provided were salary payments, medical insurance and
outplacement services. The retirement programs' pension and medical and life
insurance benefits, totalling $16 million, will be paid from pension and
employee benefit trusts. The liabilities to the trusts are included on the
consolidated balance sheet at December 31, 1995, in pension benefits and other
current liabilities. All other benefits are being paid from general corporate
funds. As of December 31, 1995, $10 million had been paid and $8 million
remained in other current liabilities.
<PAGE> 39
Note G. Pensions and Other Postretirement Benefits
1. Pensions
We have a defined benefit funded retirement plan with certain contributory
features that covers substantially all employees. Benefits are based upon an
employee's years of service and highest eligible average compensation during
the last ten years of credited employment. Our funding policy is to
contribute an amount each year that is not less than the minimum required
contribution under federal law or greater than the maximum tax deductible
amount. The retirement plan assets consist of equities, bonds, money market
funds, insurance contracts and real estate funds.
We also have a supplemental pension plan for certain management employees.
Benefits under this plan are based on final compensation upon retirement. The
plan is not funded. The plan's cost and benefit obligation amounts are
included in the following pension information for 1995. Amounts related to
the plan prior to 1995 were not material to our total pension costs and
obligations.
<TABLE>
Net pension cost consisted of the following components:
<CAPTION>
years ended December 31,
(in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current service cost - benefits earned $11,339 $15,057 $ 11,734
Interest cost on projected benefit
obligation 31,789 33,961 33,181
Actual net loss/(return) on plan assets (72,192) 214 (44,470)
Net amortization and deferral 49,557 (32,169) 8,528
- -----------------------------------------------------------------------------
Net pension cost (a) $20,493 $17,063 $ 8,973
=============================================================================
<FN>
(a) In accordance with our 1992 settlement agreement we deferred the
difference in the net pension cost of the retirement plan and its
annual funding amount. Net deferred costs amounted to ($1.2) million
and $6.5 million at December 31, 1995 and 1994, respectively. Total
net pension costs recorded as expense in 1995, 1994 and 1993 were $28
million, $25 million and $5 million, respectively.
</TABLE>
<TABLE>
We used the following assumptions for calculating pension cost:
<CAPTION>
1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 8.25% 7.00% 8.25%
Expected long-term rate of return on assets 10.00% 10.00% 10.00%
Compensation increase rate 3.90% 4.50% 4.50%
- -----------------------------------------------------------------------------
</TABLE>
<PAGE> 40
<TABLE>
The pension plans' funded status was as follows:
<CAPTION>
December 31,
(in thousands) 1995 1994
- -----------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including
vested benefits of $386,020 and $305,632 (b) $401,329 $321,072
=============================================================================
Plan assets at fair value $358,572 $289,164
Projected obligation for service rendered
to date (487,702) (387,910)
- -----------------------------------------------------------------------------
Projected benefit obligation in excess of
plan assets (129,130) (98,746)
Unrecognized prior service cost 22,506 13,328
Unrecognized net loss 83,187 67,361
Unrecognized net obligation 8,064 8,998
Minimum liability adjustment (c) (27,386) (22,849)
- -----------------------------------------------------------------------------
Net pension liability (d) $(42,759) $(31,908)
=============================================================================
<FN>
(b) The accumulated benefit obligation at December 31, 1995, includes
$13.5 million related to the enhanced retirement programs offered in
1995 as discussed in Note F.
(c) Statement of Financial Accounting Standards No. 87, Employers' Accounting
for Pensions (SFAS 87), requires the recognition of an additional minimum
liability for the excess of accumulated benefits over the fair value of
plan assets and accrued pension costs. In accordance with SFAS 87 we
recorded additional minimum liabilities and corresponding intangible
assets of $27 million and $23 million on our consolidated balance sheets
at December 31, 1995 and 1994, respectively.
(d) Net pension liability included on the consolidated balance sheets in
current liabilities is $33 million and $32 million, and in deferred
credits is $10 million and $0 at December 31, 1995 and 1994,
respectively.
</TABLE>
<TABLE>
We used the following assumptions for calculating the plans' year-end funded
status:
<CAPTION>
1995 1994
- -----------------------------------------------------------------------------
<S> <C> <C>
Discount rate 7.25% 8.25%
Compensation increase rate 3.90% 3.90%
- -----------------------------------------------------------------------------
</TABLE>
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 $9 million in 1995, $8 million in 1994 and $7 million
in 1993.
2. Other Postretirement Benefits
In addition to pension benefits, we also provide health care and other
benefits to our retired employees who meet certain age and years of service
eligibility requirements. These postretirement benefits other than pensions
(PBOPs) are accounted for in accordance with Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other
Than Pensions (SFAS 106). Our 1992 settlement agreement provides us with a
five-year expense phase-in of the PBOP costs incurred under SFAS 106 and
allows us to defer any 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
<PAGE> 41
postretirement benefits costs to external trusts. Accordingly, we recorded
expenses of $23 million in 1995, $17 million in 1994 and $15 million in 1993,
reflecting the amount of current cost recovery from customers. Net deferred
costs amounted to $15 million and $16 million at December 31, 1995 and 1994,
respectively.
<TABLE>
Net postretirement benefits cost consisted of the following components:
<CAPTION>
years ended December 31,
(in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current service cost - benefits earned $ 3,408 $ 4,978 $ 4,351
Interest cost on accumulated benefit
obligation 13,521 13,632 14,286
Actual return on plan assets (7,151) (187) 0
Amortization of transition obligation 9,151 9,151 9,151
Net amortization and deferral 3,017 (2,581) 0
- -----------------------------------------------------------------------------
Net postretirement benefits cost $21,946 $24,993 $27,788
=============================================================================
</TABLE>
<TABLE>
We used the following assumptions for calculating postretirement benefits
cost:
<CAPTION>
1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 8.25% 7.00% 8.00%
Expected long-term rate of return on assets 9.00% 9.00% 9.00%
Health care cost trend rate 7.00% 9.00% 12.50%
- -----------------------------------------------------------------------------
</TABLE>
The health care cost trend rate is assumed to decrease by one percent in 1996
and 1997 and to remain at 5% in years thereafter. Changes in the health care
cost trend rate will affect our cost and obligation amounts. A one percent
increase in the assumed health care cost trend rate would increase the total
service and interest cost components by 8% and would increase the accumulated
benefit obligation at December 31, 1995, by 7.5%.
<TABLE>
The postretirement benefits program's funded status was as follows:
<CAPTION>
December 31,
(in thousands) 1995 1994
- -----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Trust assets at fair value $ 51,064 $ 33,300
Accumulated obligation for service
rendered to date from:
Retirees $(110,877) $(93,960)
Active employees eligible to retire (31,980) (31,159)
Active employees not eligible to
retire (53,514) (196,371) (51,545) (176,664)
- -----------------------------------------------------------------------------
Accumulated benefit obligation in
excess of trust assets (145,307) (143,364)
Unrecognized prior service cost (17,889) (19,502)
Unrecognized net (gain)/loss 5,612 (1,849)
Unrecognized transition obligation 155,564 164,715
- -----------------------------------------------------------------------------
Net postretirement benefits liability $ (2,020) $ 0
=============================================================================
</TABLE>
The net postretirement benefits liability at December 31, 1995, represents the
additional PBOP obligation from the enhanced retirement programs offered in
1995 (see Note F). This additional amount was not funded as part of the 1995
PBOP cost.
The weighted average discount rates used to measure the accumulated benefit
obligation were 7.25% in 1995 and 8.25% in 1994. The trust assets consist of
equities, bonds and money market funds.
<PAGE> 42
Note H. 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 I. Cancelled Nuclear Unit
In 1982 we began expensing the cost of our cancelled Pilgrim 2 nuclear unit
over approximately eleven and one-half years in accordance with an order
received from the DPU. 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
1992 settlement agreement.
<PAGE> 43
Note J. Capital Stock
<TABLE>
<CAPTION>
December 31,
(dollars in thousands, except per share amounts) 1995 1994 1993
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Common stock equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 48,003,178,
45,535,477 and 45,129,227 shares issued and
outstanding: $ 48,003 $ 45,535 $ 45,129
Premium on common stock 683,686 622,803 612,653
Retained earnings 257,344 247,004 218,292
Surplus invested in plant 405 405 405
- ------------------------------------------------------------------------------
Total common stock equity $989,438 $915,747 $876,479
==============================================================================
</TABLE>
<TABLE>
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares
authorized; issued and outstanding:
Nonmandatory redeemable series:
<CAPTION>
Current Shares Redemption
Series Outstanding Price/Share
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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 40,000
8.25% 400,000 - 40,000 40,000 40,000
- ------------------------------------------------------------------------------
Total nonmandatory redeemable series $123,000 $123,000 $123,000
==============================================================================
</TABLE>
<TABLE>
Mandatory redeemable series:
<CAPTION>
Current Shares Redemption
Series Outstanding Price/Share
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
7.27% 440,000 $103.390 $ 44,000 $ 46,000 $ 48,000
8.00% 500,000 - 50,000 50,000 50,000
- ------------------------------------------------------------------------------
Total mandatory redeemable series 94,000 96,000 98,000
Less: due within one year 2,000 2,000 2,000
- ------------------------------------------------------------------------------
Total mandatory redeemable series, net $ 92,000 $ 94,000 $ 96,000
==============================================================================
</TABLE>
<TABLE>
Dividends Declared per Share
<S> <C> <C> <C>
Common stock $ 1.835 $ 1.775 $ 1.715
Preferred stock:
4.25% series $ 4.250 $ 4.250 $ 4.253
4.78% series 4.780 4.780 4.785
7.27% series 7.270 7.270 7.270
7.75% series 7.750 7.750 5.707
8.00% series 8.000 8.000 8.000
8.25% series 8.250 8.250 8.250
8.88% series 0 0 2.220
</TABLE>
<PAGE> 44
1. Common Stock
<TABLE>
Common stock issuances in 1993 through 1995 were as follows:
<CAPTION>
Number Total Premium on
(in thousands) of Shares Par Value Common Stock
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
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 406 406 10,150
- ------------------------------------------------------------------------------
Balance December 31, 1994 45,535 45,535 622,803
Dividend reinvestment plan (a) 468 468 11,404
New issuances (b) 2,000 2,000 49,479
- ------------------------------------------------------------------------------
Balance December 31, 1995 48,003 $48,003 $683,686
==============================================================================
<FN>
(a) At December 31, 1995, the remaining authorized common shares reserved
for future issuance under the Dividend Reinvestment and Common Stock
Purchase Plan were 1,941,219 shares.
(b) We used the net proceeds of the 1995 common stock issuances to reduce
short-term debt.
</TABLE>
2. Cumulative Nonmandatory Redeemable Preferred Stock
In 1993 we issued 400,000 shares of 7.75% cumulative nonmandatory 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 nonmandatory redeemable preferred stock.
3. Cumulative Mandatory Redeemable Preferred Stock
The 440,000 shares of 7.27% sinking fund series cumulative preferred stock are
currently redeemable at our option at $103.390. The redemption price declines
annually each May to par value in May 2002. The stock is subject to a
mandatory sinking fund requirement of 20,000 shares each May at par plus
accrued dividends. We also have the noncumulative option each May to redeem
additional shares, not to exceed 20,000, through the sinking fund at $100 per
share plus accrued dividends.
We are not able to redeem any part of the 500,000 shares of 8% series
cumulative preferred stock prior to December 2001. The entire series is
subject to mandatory redemption in December 2001 at $100 per share, plus
accrued dividends.
<PAGE> 45
Note K. Indebtedness
<TABLE>
<CAPTION>
December 31,
(in thousands) 1995 1994
- ------------------------------------------------------------------------------
<S> <C> <C>
Long-term debt:
Debentures:
8.875%, due December 1995 $ 0 $ 100,000
5.125%, due March 1996 100,000 100,000
5.700%, due March 1997 100,000 100,000
5.950%, due March 1998 100,000 100,000
6.800%, due February 2000 65,000 65,000
6.050%, due August 2000 100,000 100,000
6.800%, due March 2003 150,000 150,000
7.800%, due May 2010 125,000 0
9.875%, due June 2020 100,000 100,000
9.375%, due August 2021 115,000 115,000
8.250%, due September 2022 60,000 60,000
7.800%, due March 2023 200,000 200,000
- ------------------------------------------------------------------------------
Total debentures 1,215,000 1,190,000
Less: due within one year 100,000 100,000
- ------------------------------------------------------------------------------
Net long-term debentures 1,115,000 1,090,000
- ------------------------------------------------------------------------------
Sewage facility revenue bonds 35,700 36,300
Less: due within one year 1,600 600
Less: funds held by trustee 3,877 4,083
- ------------------------------------------------------------------------------
Net long-term sewage facility revenue bonds 30,223 31,617
- ------------------------------------------------------------------------------
Massachusetts Industrial Finance Agency bonds:
5.750%, due February 2014 15,000 15,000
- ------------------------------------------------------------------------------
Total long-term debt $1,160,223 $1,136,617
==============================================================================
Short-term debt:
Notes payable:
Bank loans $ 75,941 $ 80,786
Commercial paper 50,500 134,000
- ------------------------------------------------------------------------------
Total notes payable $ 126,441 $ 214,786
==============================================================================
</TABLE>
1. Long-Term Debt
In 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
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.
In 1994 we redeemed at par the $25 million of variable rate Series S first
mortgage bonds. 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.
In May 1995 we issued $125 million of 7.80% debentures due in 2010. We used
the net proceeds from this issuance to reduce short-term debt.
The 9 7/8% debentures due 2020 are first redeemable in June 2000 at a
redemption price of 104.483%, the 9 3/8% series due 2021 are first redeemable
<PAGE> 46
in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in
September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable
in March 2003 at 103.730%. No other series are redeemable prior to maturity.
There is no sinking fund requirement for any series of our debentures.
Sewage facility revenue bonds were issued by Harbor Electric Energy Company
(HEEC), a wholly owned subsidiary. The bonds are tax-exempt, subject to
annual mandatory sinking fund redemption requirements and mature through 2015.
In May 1995 $0.6 million was redeemed as scheduled. The weighted average
interest rate of the bonds is 7.3%. A portion of the proceeds from the bonds
is in reserve with the trustee. If HEEC should have insufficient funds to pay
for extraordinary expenses, we would be required to make additional capital
contributions or loans to the subsidiary up to a maximum of $1 million.
The aggregate principal amounts of our long-term debt (including HEEC sinking
fund requirements) due through 2000 are $101.6 million per year in 1996
through 1998, $1.6 million in 1999 and $166.6 million in 2000.
2. Short-Term Debt
We have arrangements with certain banks to provide short-term credit on both a
committed and an uncommitted and as available basis. We currently have
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.
<TABLE>
Information regarding our short-term borrowings, comprised of bank loans and
commercial paper, is as follows:
<CAPTION>
(dollars in thousands) 1995 1994 1993
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Maximum short-term borrowings $327,769 $268,100 $320,000
Weighted average amount outstanding $165,720 $214,640 $220,149
Weighted average interest rates excluding
commitment fees 6.2% 4.5% 3.4%
- -----------------------------------------------------------------------------
</TABLE>
Note L. 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 $102.9 million approximates fair value based on quoted market
prices of securities held.
Cash and cash equivalents:
The carrying amount of $5.8 million approximates fair value due to the
short-term nature of these securities.
<PAGE> 47
Mandatory redeemable cumulative preferred stock, sewage facility revenue bonds
and unsecured debt:
<TABLE>
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, 1995, are
as follows:
<CAPTION>
Carrying Fair
(in thousands) Amount Value
- ------------------------------------------------------------------------------
<S> <C> <C>
Mandatory redeemable cumulative preferred stock $ 94,000 $ 98,005
Sewage facility revenue bonds 35,700 38,446
Unsecured debt 1,230,000 1,276,213
- ------------------------------------------------------------------------------
</TABLE>
Note M. New Accounting Pronouncement
In 1995 the FASB issued Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed Of (SFAS 121), effective in 1996. This statement clarifies
when and how to recognize asset impairments. In addition, SFAS 121 requires
that all regulatory assets, which must have a high probability of recovery to
be initially established, continue to meet that high probability standard or
be written off. However, if written off, a regulatory asset can be restored
if it regains a high probability of recovery. The impact of this standard on
our plant and regulatory assets will be determined by regulatory changes
implemented by the DPU and FERC. Based on the transition principles of the
DPU's order on industry restructuring and our related plan, which are
discussed in the Outlook for the Future section of Management's Discussion and
Analysis, we do not expect SFAS 121 to have an adverse impact on our financial
position or results of operations in the near term. Our conclusion may change
as the actual shape of restructuring of the industry in Massachusetts
develops. If recovery of our plant and regulatory assets is not provided,
SFAS 121 could require a write-down of these assets.
Note N. Commitments and Contingencies
1. Contractual Commitments
At December 31, 1995, we had estimated contractual obligations for plant and
equipment of approximately $35 million.
<TABLE>
We have leases for certain facilities and equipment. Our estimated minimum
rental commitments under both transmission agreements and noncancellable
leases for the years after 1995 are as follows:
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
1996 $ 24,908
1997 22,109
1998 19,002
1999 17,408
2000 16,656
Years thereafter 108,417
- ------------------------------------------------------
Total $208,500
======================================================
</TABLE>
We will capitalize a portion of these lease rentals as part of plant
expenditures in the future. The total expense for both lease rentals and
transmission agreements was $24.5 million in 1995, $28.6 million in 1994 and
$29.8 million in 1993, net of capitalized expenses of $2.7 million in 1995,
$2.4 million in 1994 and $5.2 million in 1993.
<PAGE> 48
We also have various outstanding commitments for take or pay and throughput
agreements, primarily to supply New Boston Station with natural gas. The
fixed and determinable portions of the obligations are $16.1 million in 1996,
1997 and 1998, $24.8 million in 1999 and $13.8 million in 2000. We are also
committed to purchase natural gas at market prices. The total expense under
these agreements was $13.9 million in 1995, and $6.5 million in 1994 and 1993.
2. Hydro-Quebec
We have an approximately 11% equity ownership interest in two companies which
own and operate transmission facilities to import electricity from the
Hydro-Quebec system in Canada, which is included on 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, 1995, our portion of these guarantees was approximately $19
million.
3. Yankee Atomic Electric Company
We have a 9.5% stock investment of approximately $2 million in Yankee Atomic
Electric Company (Yankee Atomic). In 1992 the Board of Directors of Yankee
Atomic decided to permanently discontinue power operation of the Yankee Atomic
nuclear generating station and decommission the facility. We relied on Yankee
Atomic for less than one percent of our system capacity under a long-term
purchased power contract.
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 $21 million as of
December 31, 1995. This estimate is recorded on our consolidated balance
sheet as a power contract liability and an offsetting regulatory asset as we
continue to collect these costs from our customers in accordance with our 1992
settlement agreement.
4. 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 $15 million under both
<PAGE> 49
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 additional 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 any such assessment.
5. 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. We have also been named as a party in a lawsuit
by Subaru of New England, Inc. and Subaru Distributors Corporation. The
plaintiffs are claiming certain automobiles stored on lots in South Boston
suffered pitting damage caused by emissions from New Boston Station. We
believe that we have a strong defense in this case. We are also involved in
certain other legal matters. We are unable to fully determine a range of
reasonably possible litigation costs in excess of amounts previously accrued,
although based on the information currently available, we do not expect that
any such additional costs will have a material impact on our financial
condition. However, additional litigation costs that may result from a change
in estimates could have a material impact on the results of a reporting period
in the near term.
6. Hazardous Waste
We own or operate approximately 40 properties where oil or hazardous materials
were previously spilled or released. We are required to clean up these
properties in accordance with a timetable developed by the Massachusetts
Department of Environmental Protection (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 approximately ten multi-party hazardous waste sites in
Massachusetts and other states where we are alleged to have generated,
transported or disposed of hazardous waste at the sites. At the majority of
these sites we are one of many potentially responsible parties and we
currently expect to have only a small percentage of the potential liability.
Through December 31, 1995, 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 that may result
from a change in estimates could have a material impact on the results of a
reporting period in the near term.
<PAGE> 50
Note O. Long-Term Power Contracts
1. Long-Term Contracts for the Purchase of Electricity
<TABLE>
We purchase electric power under several long-term contracts for which we pay
a share of the generating unit's capital and fixed operating costs through the
contract expiration date. The total cost of these contracts is included in
purchased power expense on our consolidated income statements. Information
relating to these contracts as of December 31, 1995, is as follows:
<CAPTION>
proportionate share (in thousands)
- ------------------------------------------------------------------------------
Units of 1995 1995 Interest Debt
Contract Capacity Minimum Portion of Outstanding
Expiration Purchased(a) Debt Minimum Through Cont.
Generating Unit Date % MW Service Debt Service Exp. Date
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Canal Unit 1 2001 25.0 139 $ 1,122 $ 349 $ 3,400
Mass. Bay Trans-
portation
Authority - 1 2005 100.0 34 (b) (b) (b)
Connecticut Yankee
Atomic 2007 9.5 55 2,646 1,786 13,857
Ocean State Power -
Unit 1 2010 23.5 67 4,819 3,318 20,749
Ocean State Power -
Unit 2 2011 23.5 66 4,090 3,049 17,228
Northeast Energy
Associates (c) (c) 219 (c) (c) (c)
L'Energia 2013 73.0 64 (d) (d) (d)
MassPower (e) 2013 44.3 117 12,217 7,662 81,983
Mass. Bay Trans-
portation
Authority - 2 2019 100.0 34 (f) (f) (f)
- ------------------------------------------------------------------------------
Total 795 $24,894 $16,164 $137,217
==============================================================================
<FN>
(a) The Northeast Energy Associates contract represents 5.9% of our total
system generation capability. The remaining units listed above represent
15.6% 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 1995 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 1995 were approximately $127
million.
(d) We pay for this energy based on a price per kWh actually received. The
total charges under this contract for 1995 were approximately $25
million.
<PAGE> 51
(e) Payments for this contract 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 1995 were approximately $49 million.
(f) The second Massachusetts Bay Transportation Authority contract started in
June 1995. Capacity payments under this contract do not begin until
2003. At that time we will be required to pay $84.57 per kilowatt-year
times the qualified capacity plus incremental operating maintenance and
fuel costs.
</TABLE>
<TABLE>
Our total fixed and variable costs for these contracts in 1995, 1994 and 1993
were approximately $283 million, $286 million and $225 million, respectively.
Our minimum fixed payments under these contracts for the years after 1995 are
as follows:
<CAPTION>
(in thousands)
- ------------------------------------------------------
<S> <C>
1996 $ 106,649
1997 103,682
1998 105,778
1999 105,258
2000 103,676
Years thereafter 1,187,672
- ------------------------------------------------------
Total $1,712,715
======================================================
Total present value $ 883,409
======================================================
</TABLE>
2. Long-Term Power Sales
<TABLE>
In addition to wholesale power sales, we sell a percentage of Pilgrim
Station's output to other utilities under long-term contracts. Information
relating to these contracts is as follows:
<CAPTION>
Contract
Expiration Units of Capacity Sold
Contract Customer Date % MW
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Commonwealth Electric Company 2012 11.0 73.7
Montaup Electric Company 2012 11.0 73.7
Various municipalities 2000(a) 3.7 25.0
- ------------------------------------------------------------------------------
Total 25.7 172.4
==============================================================================
<FN>
(a) Subject to certain adjustments.
</TABLE>
Under these contracts, the utilities 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.
<PAGE> 52
<TABLE>
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
<CAPTION>
Balance
Available Earnings
Operating Operating Net for Common Per Average
Revenues Income Income Stock Common Share(a)
- --------------------------------------------------------------------------
1995
- ----
<S> <C> <C> <C> <C> <C>
First quarter $379,678 $ 47,610 $20,202 $16,300 $0.36
Second quarter 380,828 55,683 26,137 22,247 0.48
Third quarter 498,554 102,695(b) 72,368 (b) 68,478 (b) 1.46 (b)
Fourth quarter 369,443 21,412(b) (6,397)(b) (10,286)(b) (0.21)(b)
1994
- ----
First quarter $376,935 $ 45,891 $19,812 $15,850 $0.35
Second quarter 368,245 50,812 23,982 20,031 0.44
Third quarter 448,179 96,880 70,182 66,256 1.46
Fourth quarter 351,376 34,895 11,046 7,120 0.16
<FN>
(a) Based on the weighted average number of common shares outstanding during
the quarter.
(b) As discussed in Note F to the Consolidated Financial Statements, we
incurred a $34 million pre-tax charge related to our corporate
restructuring over the third and fourth quarters of 1995. Amounts
excluding the restructuring charge are as follows:
</TABLE>
<TABLE>
<CAPTION>
Balance
Available Earnings
Operating Net for Common Per Average
Income Income Stock Common Share
- --------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Third quarter $107,779 $77,452 $73,562 $1.57
Fourth quarter 36,991 9,182 5,293 0.11
</TABLE>
Certain reclassifications were made to the data reported in prior periods to
conform with the current method of presentation.
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure
- --------------------
Not applicable.
<PAGE> 53
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 28, 1996, incorporated herein by reference.
(b) Identification of Executive Officers
- -----------------------------------------
The information required by this item is included at the end of Part I of this
Form 10-K under the caption Executive Officers of the Registrant.
(c) Identification of Certain Significant Employees
- ----------------------------------------------------
Not applicable.
(d) Family Relationships
- -------------------------
Not applicable.
(e) Business Experience
- ------------------------
For information relating to the business experience during the past five years
and other directorships (of companies subject to certain SEC requirements)
held by each person nominated to be a director, see "Election of Directors -
Information about Nominees and Incumbent Directors" on pages 1 through 4 of
the definitive proxy statement dated March 28, 1996, 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 6 through 12 of the
definitive proxy statement dated March 28, 1996, incorporated herein by
reference
<PAGE> 54
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 page 5 of the
definitive proxy statement dated March 28, 1996, incorporated herein by
reference.
(c) Changes in Control
- -----------------------
Not applicable.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Not applicable.
<PAGE> 55
Part IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
<TABLE>
(a) The following documents are filed as part of this Form 10-K:
<CAPTION>
Page
----
<S> <C>
Consolidated Statements of Income for the three years ended
December 31, 1995, 1994 and 1993 30
Consolidated Statements of Retained Earnings for the three
years ended December 31, 1995, 1994 and 1993 30
Consolidated Balance Sheets as of December 31, 1995 and 1994 31
Consolidated Statements of Cash Flows for the three years
ended December 31, 1995, 1994 and 1993 32
Notes to Consolidated Financial Statements 33
Selected Consolidated Quarterly Financial Data (Unaudited) 52
Report of Independent Accountants 66
</TABLE>
No financial statement schedules are prepared as they are either not required
or not applicable.
<PAGE> 56
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 3 Articles of Incorporation and By-Laws
- --------- -------------------------------------
Incorporated herein by reference:
<S> <C> <C> <C>
3.1 Restated Articles of Organization 3.1 1-2301
Form 10-Q
for the
quarter ended
June 30, 1994
3.2 Boston Edison Company Bylaws 3.1 1-2301
April 19, 1977, as amended Form 10-Q
January 22, 1987, January 28, 1988, for the
May 24, 1988 and November 22, 1989 quarter ended
June 30, 1990
Exhibit 4 Instruments Defining the Rights of
- --------- ----------------------------------
Security Holders, Including Indentures
--------------------------------------
Incorporated herein by reference:
4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301
dated September 1, 1988, between Form 10-Q
Boston Edison Company and Bank of for the
Montreal Trust Company quarter ended
September 30,
1988
4.1.1 First Supplemental Indenture 4.1 1-2301
dated June 1, 1990 to Form 8-K
Indenture dated September 1, 1988 dated
with Bank of Montreal Trust Company - June 28, 1990
9 7/8% debentures due June 1, 2020
4.1.2 Indenture of Trust and Agreement among 4.1.26 1-2301
the City of Boston, Massachusetts Form 10-K
(acting by and through its Industrial for the
Development Financing Authority) and year ended
Harbor Electric Energy Company and December 31,
Shawmut Bank, N.A., as Trustee, dated 1991
November 1, 1991
4.1.3 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 5, 1991 re for the
9 3/8% debentures due August 15, 2021 year ended
December 31,
1991
</TABLE>
<PAGE> 57
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301
February 12, 1993 Form 10-K
for the
year ended
December 31,
1992
4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken September 10, 1992 re for the
8 1/4% debentures due September 15, 2022 year ended
December 31,
1992
4.1.6 Votes of the Pricing Committee of the 4.1.26 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken January 27, 1993 re for the
6.80% debentures due February 1, 2000 year ended
December 31,
1992
4.1.7 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken March 5,1993 re for the
5 1/8% debentures due March 15, 1996, year ended
5.70% debentures due March 15, 1997, December 31,
5.95% debentures due March 15, 1998, 1992
6.80% debentures due March 15, 2003,
7.80% debentures due March 15, 2023
4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 18, 1993 re for the
6.05% debentures due August 15, 2000 year ended
December 31,
1993
Filed herewith:
4.1.9 Votes of the Pricing Committee of the
Board of Directors of Boston Edison
Company taken May 10, 1995 re
7.80% debentures due May 15, 2010
</TABLE>
<PAGE> 58
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
4.1.10 First Amendment to Revolving Credit
Agreement
The Company agrees to furnish to the Securities and Exchange Commission, upon
request, a copy of any agreements or instruments defining the rights of
holders of any long-term debt whose authorization does not exceed 10% of the
Company's total assets.
Exhibit 10 Material Contracts
- ---------- ------------------
Incorporated herein by reference:
10.1 Key Executive Benefit Plan 10.1 1-2301
Standard Form of Agreement, May Form 10-Q
1986 for the
quarter ended
June 30, 1986
10.1.1 Key Executive Benefit Plan 10.3.1 1-2301
Standard Form of Agreement, May Form 10-K
1986, with modifications for the
year ended
December 31,
1991
10.2 Executive Annual Incentive 10.5 1-2301
Compensation Plan Form 10-K
for the
year ended
December 31,
1988
10.3 1991 Director Stock Plan 10.1 1-2301
Form 10-Q
for the
quarter ended
March 31, 1991
10.4 Boston Edison Company Deferred 10.11 1-2301
Fee Plan dated January 1, 1990 Form 10-K
for the
year ended
December 31,
1992
</TABLE>
<PAGE> 59
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
10.5 Deferred Compensation Trust 10.10 1-2301
between Boston Edison Company Form 10-K
and State Street Bank and for the
Trust Company dated year ended
February 2, 1993 December 31,
1992
10.5.1 Amendment No. 1 to Deferred 10.5.1 1-2301
Compensation Trust dated Form 10-K
March 31, 1994 for the
year ended
December 31,
1994
10.6 Directors Retirement Benefit 10.8.1 1-2301
(1993 Plan) Form 10-K
for the
year ended
December 31,
1993
10.7 Description of Supplemental Fee 10.7 1-2301
Arrangement for Certain Directors Form 10-K
for the
year ended
December 31,
1994
10.8 Performance Share Plan, Amendment 10.8 1-2301
and Restatement dated October 24, 1994 Form 10-K
for the
year ended
December 31,
1994
10.9 Boston Edison Company Deferred 10.9 1-2301
Compensation Plan, Amendment and Form 10-K
Restatement dated January 31, 1995 for the
year ended
December 31,
1994
10.10 Employment Agreement applicable to 10.10 1-2301
Ronald A. Ledgett dated April 30, 1987 Form 10-K
for the
year ended
December 31,
1994
</TABLE>
<PAGE> 60
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
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, 1995
12.2 Computation of Ratio of Earnings
to Fixed Charges and Preferred Stock
Dividend Requirements for the Year
Ended December 31, 1995
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.
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.
</TABLE>
<PAGE> 61
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
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), May 31, 1995 (File
No. 33-59693) and in the Form S-8
Registration Statements filed by
the Company on October 10, 1985
(File No. 33-00810), July 28, 1986
(File No. 33-7558), December 31,
1990 (File No. 33-38434), June 5,
1992 (33-48424 and 33-48425),
March 17, 1993 (33-59662 and
33-59682) and April 6, 1995
(33-58457)
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
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
</TABLE>
<PAGE> 62
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
99.4 Settlement Agreement Between Boston 28.2 1-2301
Edison Company and City of Holyoke Form 10-Q
Gas and Electric Department et. al., for the
dated April 26, 1990 quarter ended
March 31, 1990
99.5 Information required by SEC Form 1-2301
11-K for certain Company employee Form 10-K/A
benefit plans for the years ended Amendments to
December 31, 1994, 1993 and 1992 Form 10-K for
the years ended
December 31,
1994 and 1993
and Form 8
Amendment to
Form 10-K for
the year ended
December 31,
1992 dated
June 29, 1995,
June 30, 1994
and June 29,
1993,
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
</TABLE>
<PAGE> 63
(b) Reports on Form 8-K:
There were no Form 8-K's filed during the fourth quarter of 1995.
<PAGE> 64
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
BOSTON EDISON COMPANY
By: /s/ James J. Judge
---------------------------------------
James J. Judge
Senior Vice President and Treasurer
(Principal Financial Officer)
Date: March 28, 1996
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 28th day of March 1996.
<TABLE>
<S> <C>
/s/ Thomas J. May Chairman of the Board, President
- ------------------------------------- and Chief Executive Officer
Thomas J. May
/s/ Robert J. Weafer, Jr. Vice President - Finance,
- ------------------------------------- Controller and Chief Accounting
Robert J. Weafer, Jr. Officer
/s/ William F. Connell Director
- -------------------------------------
William F. Connell
/s/ Gary L. Countryman Director
- -------------------------------------
Gary L. Countryman
/s/ Thomas G. Dignan, Jr. Director
- -------------------------------------
Thomas G. Dignan, Jr.
/s/ Charles K. Gifford Director
- -------------------------------------
Charles K. Gifford
/s/ Nelson S. Gifford Director
- -------------------------------------
Nelson S. Gifford
/s/ Kenneth I. Guscott Director
- -------------------------------------
Kenneth I. Guscott
<PAGE> 65
/s/ Matina S. Horner Director
- -------------------------------------
Matina S. Horner
/s/ Sherry H. Penney Director
- -------------------------------------
Sherry H. Penney
/s/ Herbert Roth, Jr. Director
- -------------------------------------
Herbert Roth, Jr.
- ------------------------------------- Director
Stephen J. Sweeney
- ------------------------------------- Director
Paul E. Tsongas
</TABLE>
<PAGE> 66
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, 1995 and 1994, and the consolidated results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1995, in conformity with generally accepted accounting
principles.
COOPERS & LYBRAND L.L.P.
Boston, Massachusetts
January 25, 1996
Exhibit 4.1.9
PRICING COMMITTEE MEETING
-------------------------
BOSTON, MAY 10, 1995
A meeting of the Pricing Committee of the Board of Directors of Boston
Edison Company was held at the Executive Offices of the Company, 800 Boylston
Street, Boston, Massachusetts, on Wednesday, May 10, 1995, at twelve o'clock
noon, local time, the Chairman presiding.
Present: Mr. May - and present and participating by telephone
communications equipment, by means of which all persons participating in the
meeting could hear each other at the same time, Mr. N. Gifford and Drs. Horner
and Penney - and, by invitation, Mr. Alpert and Ms. O'Neil.
Absent: Mr. Davis.
Messrs. May and Alpert presented management's proposal to issue $125
million of debentures. The directors discussed the matters presented.
On motion duly made and seconded, it was
VOTED: That, pursuant to votes of the Board of Directors adopted
January 28, 1993, the Company issue and sell $125,000,000 aggregate principal
amount of unsecured debentures to be issued under and in accordance with the
provisions of Article Three of the Indenture dated September 1, 1988 between
the Company and Bank of Montreal Trust Company, as Trustee (the "Trustee") as
amended and supplemented as of the date hereof (the "Indenture").
VOTED: That said series of debentures be established as a separate
series of securities in accordance with and pursuant to the Indenture, to
be entitled as follows: the 7.80% Debentures due May 15, 2010 (the
"Debentures").
VOTED: That the Debentures be issued with the following terms:
<TABLE>
<S> <C>
Maturity Date: May 15, 2010
Interest Rate: 7.80%
Interest Payment Date: May 15 and November 15 of each year
commencing November 15, 1995.
Price to the Public: $124,835,000; 99.868%
Proceeds to the Company: $123,897,500; 99.118%
Redemption Provisions: No call.
</TABLE>
VOTED: That the form of the Debentures presented to the Pricing
Committee and attached to these votes as Exhibit A is hereby established,
adopted and approved with such changes, insertions and omissions as are
required or permitted by the Indenture and these votes and that such form
shall be filed with the minutes of this meeting; and that the chairman,
president, any senior vice president, the treasurer or any assistant treasurer
of the Company be, and each of them acting singly is, hereby authorized to
complete the form of Debenture as provided for in these votes, the completion
of such Debentures to be conclusive evidence that the same has been approved
by the Company.
VOTED: That the form of Purchase Agreement presented to the Pricing
Committee relating to the Debentures is hereby approved and that the chairman,
president, any senior vice president, the treasurer and any assistant
treasurer be, and each acting singly is, hereby authorized, in the name and on
behalf of the Company, to execute with and deliver to Goldman, Sachs & Co.,
Merrill Lynch & Co. and Salomon Brothers Inc a Purchase Agreement relating to
the Debentures with such changes, insertions and omissions as the officer or
officers executing the same may approve, such execution and delivery to be
conclusive evidence of the authorization and approval thereof by the Company.
VOTED: That Bank of Montreal Trust Company is hereby designated as the
transfer agent, registrar and paying agent for the Debentures and that the
Trustee and such transfer agent, registrar and paying agent shall be entitled
to the estate, powers, rights, authorities, benefits, privileges and
immunities set forth in the Indenture; and that such resolutions, if any, as
are customarily requested by the Trustee and each such transfer agent,
registrar and paying agent with respect to its authority are hereby adopted
and shall be filed with the minutes of this meeting.
VOTED: That the chairman, president, any senior vice president, the
treasurer or any assistant treasurer be, and each of them is, hereby
authorized to file with the Trustees a certificate setting forth the form and
terms of the Debentures as established by and pursuant to these votes and the
written order for the certification and delivery to the purchasers at the time
and in the manner specified in the Purchase Agreement for the Debentures; and
that the officers of the Company be, and each of them acting singly is, hereby
authorized to take such further action and execute such certificates,
instruments and other documents as in the judgment of such officers or officer
will comply with the provisions of the Indenture and the Purchase Agreement
and to issue and deliver the Debentures in accordance therewith.
VOTED: That the treasurer or any assistant treasurer be, and each of
them acting singly is, hereby authorized and directed to apply the proceeds
from the issue and sale of the Debentures to repay obligations incurred under
bank lines of credit and commercial paper for capital expenditures for
extensions, additions and improvements to the Company's plant and property
and for working capital purposes.
VOTED: That the officers of the Company are, and each acting singly is,
hereby authorized to execute and deliver such other documents and take such
further actions in the name of the Company as the officers or officer so
acting shall deem advisable to implement the foregoing votes, such execution
and delivery or the taking of any such action to be conclusive evidence of its
authorization by the Company.
No further business being presented, on motion duly made and seconded,
the meeting dissolved at fifteen minutes past twelve o'clock p.m., local time.
A true record.
Attest:
By: /s/ Theadora S. Convisser
-------------------------------------
Clerk
Exhibit 4.1.10
FIRST AMENDMENT TO
REVOLVING CREDIT AGREEMENT
This FIRST AMENDMENT, dated as of May 19, 1995, by and among (a) Boston
Edison Company (the "Borrower"), a Massachusetts corporation, (b) each of the
Banks named on the signature pages hereof (collectively, the "Banks"), (c) The
First National Bank of Boston and Citibank, N.A., as co-agents (collectively,
the "Agents") and (d) The First National Bank of Boston as administrative
agent (the "Administrative Agent").
WHEREAS, the Borrower, the Banks, the Agents and the Co-Agents are
parties to that certain Revolving Credit Agreement dated as of February 12,
1993, as in effect on the date hereof (the "Credit Agreement"); and
WHEREAS, the Borrower has requested and the Banks have agreed, subject to
the terms and conditions set forth herein, to modify certain provisions of the
Credit Agreement:
NOW, THEREFORE, the Borrower, the Banks, the Agents and the
Administrative Agent hereby covenant and agree as follows:
1. Defined Terms. Capitalized terms which are used herein without
-------------
definition and which are defined in the Credit Agreement shall have the same
meanings herein as in the Credit Agreement.
2. Amendment to Section 1 - Definitions. Section 1 of the Credit
------------------------------------
Agreement is hereby amended as follows:
(a) The definition of "Balance Sheet Date" is hereby amended by
substituting "December 31, 1994" for "September 20, 1992" therein.
(b) The definition of "Commitment Fee Rate" is hereby deleted;
(c) The definition of "DPU Approval" is hereby amended and restated in
its entirety as follows:
DPU Approval. An appropriate order of the DPU authorizing the
------------
incurrence of indebtedness (i) after December 31, 1996 (for purposes
of satisfying the Extension Conditions) or (ii) after the DPU Final
Incurrence Date, in each case payable more than one year after the
date of incurrence, such order to contain no condition inconsistent
with the provisions hereof or reasonably unacceptable to the
Majority Banks.
(d) The definition of "Extension Conditions" is hereby amended by
substituting the date "December 31, 1996" for the date "December 31, 1994"
therein;
(e) The definition of "Extension Date" is hereby amended by substituting
the date "December 31, 1996" for the date "December 31, 1994" therein;
(f) The definition of "FERC Approval" is hereby amended and restated in
its entirety to read as follows:
FERC Approval. The order of the FERC dated June 27, 1994
-------------
authorizing the Borrower to incur, on or before December 31, 1996,
short-term indebtedness with a final maturity date not later than
December 31, 1997.
(g) The definition of "Interest Period" is hereby amended by deleting
the second sentence thereof in its entirety and inserting the following
sentence therefor:
The Interest Period for each Loan, as so determined, shall be (a)
with respect to Alternate Base Rate Loans any period ending on or
prior to the Termination Date, (b) with respect to Eurodollar Rate
Loans, one, two, three or six months and (c) up to 270 days with
respect to Competitive Bid Rate Loans.
(h) The definition of "Termination Date" is hereby amended and restated
in its entirety to read as follows:
Termination Date. May 15, 1999; provided that if all of the
---------------- --------
Extension Conditions have not been complied with on or prior to
December 31, 1996, the Termination Date shall be December 30, 1997;
provided, further, that if the Extension Conditions have been
-------- -------
complied with but the DPU Approval delivered to satisfy the
Extension Conditions provides for a DPU Final Incurrence Date prior
to May 15, 1999, the Termination Date shall be the earlier to occur
of the date which is 364 days following the DPU Final Incurrence
Date specified in such DPU Approval or May 15, 1999; provided,
--------
further, that if the Second Extension Conditions have been complied
-------
with but the DPU Approval delivered to satisfy the Second Extension
Conditions provides for a Second DPU Final Incurrence Date prior to
May 15, 1999, the Termination Date shall be the earlier to occur of
the date which is 364 days following the Second DPU Final Incurrence
Date specified in such DPU Approval or May 15, 1999.
Notwithstanding the foregoing, the Termination Date shall be May 15,
1999 with respect to any outstanding Loans incurred pursuant to a
DPU Approval authorizing such Loans.
(i) Section 1 of the Credit Agreement is hereby amended by inserting the
following new definitions in appropriate alphabetical order:
DPU Final Incurrence Date. The date specified in the DPU Approval
--- ----- ---------- ----
delivered for purposes of satisfying the Extension Conditions as the
last date upon which the Borrower may incur indebtedness pursuant to
such order.
Facility Fee Rate. For each day that the First Mortgage Bonds have
-------- --- ----
a rating equal to or higher than BBB by Standard & Poor's
Corporation and Baa2 by Moody's Investors Service, Inc. the Facility
Fee Rate shall equal 0.1875% per annum provided, that in the event
--------
there are no First Mortgage Bonds outstanding, the condition
specified herein shall be deemed to be met if the Borrower has
outstanding debentures or other unsecured debt having a rating equal
to or higher than BBB- by Standard & Poor's Corporation and Baa3 by
Moody's Investor Service, Inc. For each day that the condition
specified in the preceding sentence is not satisfied, the Facility
Fee Rate shall equal 0.2875% per annum. In the event that the First
Mortgage Bonds or unsecured debt of the Borrower, as applicable, is
not rated by one of Standard & Poor's Corporation or Moody's
Investor Service, Inc., the condition specified herein shall be
deemed to be met if the applicable rating from the other such
rating company is achieved and the First Mortgage Bonds have a
rating of BBB or higher from Duff & Phelps Corporation, or, if the
First Mortgage Bonds are not then outstanding, the Borrower's
unsecured debt has a rating of BBB- or higher from Duff & Phelps
Corporation.
Second DPU Final Incurrence Date. The date specified in the DPU
------ --- ----- ---------- ----
Approval delivered for purposes for satisfying the Second Extension
Conditions as the last date upon which the Borrower may incur
indebtedness pursuant to such order.
Second Extension Conditions. (1) The Banks shall have received on
------ --------- ----------
or prior to the Second Extension Date, copies of the DPU Approval
authorizing the Borrower to incur long-term indebtedness after the
DPU Final Incurrence Date, which approval or order shall not have
been rescinded or stayed or materially adversely modified, or the
right of the Borrower to incur indebtedness thereunder restrained
by the DPU or by any court of competent jurisdiction or other
regulatory agency with appropriate jurisdiction and all applicable
appeal periods with respect to such approval or order shall have
expired and (2) Ropes & Gray, Borrower's counsel shall have
delivered to the Administrative Agent a legal opinion dated the
Second Extension Date, addressed to the Banks and reasonably
satisfactory to the Majority Banks to the effect that the incurrence
by, or existence of, indebtedness of the Borrower under this
Agreement after the DPU Final Incurrence Date has been duly approved
to the extent required by law and all applicable regulations by such
approval or order which remains in full force and effect and no
further authorization, order or approval or other action by, and no
notice to or filing with any governmental authority or regulatory
body is required for the incurrence of such indebtedness pursuant
hereto; and (3) the representations and warranties of the Borrower
contained in Section 4 are true and complete in all material
respects on and as of the Second Extension Date.
Second Extension Date. A date selected by the Borrower on or prior
------ --------- ----
to the DPU Final Incurrence Date on which the Second Extension
Conditions shall have been satisfied.
3. Amendment to Section 2.3 - Commitment Fee. Section 2.3 of the
--------- -- ------- ---
Credit Agreement is hereby amended by (i) substituting in the heading thereof
the phrase "Facility Fee" for the phrase "Commitment Fee" and (ii) deleting
the text thereof in its entirety and substituting the following text therefor:
The Borrower agrees to pay to the Administrative Agent for the
accounts of the Banks in accordance with their respective Commitment
Percentages a facility fee calculated daily at the Facility Fee Rate
on the amount of the Total Commitment in effect on such day. The
facility fee shall accrue from April 1, 1995 through the Termination
Date and be payable quarterly in arrears on the last day of each
March, June, September and December for the fiscal quarter (or
portion thereof) then ended, with the first such payment on June 30,
1995 and with a final payment on the Termination Date (or the date
of termination in full of the Commitments, if earlier).
4. Amendment to Section 2.4 - Extension of Commitment. Section 2.4 of
--------- -- ------- --- --------- -- ----------
the Credit Agreement is hereby amended by (i) substituting the phrase
"facility fee" for the phrase "commitment fee" in the penultimate sentence of
paragraph (a) thereof and (ii) deleting paragraph (c) thereof in its entirety.
5. Amendment to Section 2.6 - Interest Period. Section 2.6 of the
--------- -- ------- --- -------- ------
Credit is hereby amended as follows:
(a) Section 2.6(a) is amended by deleting clause (ii) thereof in
its entirety and substituting the following therefor:
(ii) on or prior to May 15, 1998 for the Eurodollar Loans,
at a rate per annum equal to the sum of (A) the Euro Rate plus (B)
----
0.4125%; and
(iii) after May 15, 1998 for Eurodollar Loans, at a rate per
annum equal to the sum of (A) the Euro Rate plus (B) 0.600%; and
----
(b) Section 2.6(b) is hereby amended by deleting clause (ii)
thereof in its entirety and substituting the following therefor:
(ii) on or prior to May 15, 1998 for Eurodollar Loans, at a
rate per annum equal to the sum of (A) the Euro Rate plus (B)
----
0.5375%; and
(iii) after May 15, 1998 for Eurodollar Loans, at a rate per
annum equal to the sum of (A) the Euro Rate plus (B) 0.725%; and
----
6. Amendment to Section 3.1 - Funds for Payments. Section 3.1 of the
--------- -- ------- --- ----- --- --------
Credit Agreement is hereby amended by substituting the phrase "facility fee"
for the phrase "commitment fee" in the first sentence thereof.
7. Amendment to Section 3.2 - Computations. Section 3.2 of the Credit
--------- -- ------- --- ------------
Agreement is hereby amended by substituting the phrase "facility fee" for the
phrase "commitment fee" in the first sentence thereof.
8. Amendment to Section 4.2 - Government Approvals. Section 4.2 of the
--------- -- ------- --- ---------- ---------
Credit Agreement is hereby amended and restated in its entirety as follows:
Except for (i) obtaining DPU approval authorizing the incurring of
indebtedness after December 31, 1996 (or such later date as shall be
specified therefor in the DPU Approval) pursuant to this Agreement
payable more than one year after the date of incurrence thereof and
(ii) obtaining approval of the Federal Energy Regulatory Commission
("FERC") authorizing the incurring of short-term indebtedness
pursuant to this Agreement after December 31, 1996 (or such later
date as shall be specified therefor in any extension of the FERC
Approval), the execution, delivery and performance by the Borrower
of this Agreement and the notes and the transactions contemplated
hereby and thereby do not require the approval or consent of, or
filing with, any governmental agency or authority other than those
already obtained or made and in full force and effect.
9. Amendment to Section 4.3 - Financial Statements. Section 4.3 of the
--------- -- ------- --- --------- ----------
Credit Agreement is hereby amended by substituting the date "December 31,
1994" for the date "December 31, 1991" therein and by deleting the second
sentence thereof.
10. Amendment to Section 4.6 - Litigation. Section 4.6 of the Credit
--------- -- ------- --- ----------
Agreement is hereby amended by substituting the date "December 31, 1994" for
the date "December 31, 1991" therein.
11. Amendment to Section 4.7 - Compliance with Other Instruments, Laws,
--------- -- ------- --- ---------- ---- ----- ------------ -----
Etc. Section 4.7 of the Credit Agreement is hereby amended by substituting
- ----
the date "December 31, 1994" for the date "December 31, 1991" therein.
12. Amendment to Section 5.1 - Punctual Payment. Section 5.1 of the
--------- -- ------- --- -------- -------
Credit Agreement is hereby amended by substituting the phrase "facility fee"
for the phrase "commitment fee" in the second sentence thereof.
13. Amendment to Section 5.8 - Compliance with Laws, Contracts,
--------- -- ------- --- ---------- ---- ----- ----------
Licenses, and Permits. Section 5.8 of the Credit Agreement is hereby
- --------- --- -------
amended by substituting the date December 31, 1994" for the date "December 31,
1991" therein.
14. Amendment to Section 7.2 - All Borrowings. Section 7.2 of the
--------- -- ------- --- --- ----------
Credit Agreement is hereby amended by inserting the following paragraph (d)
at the end thereof:
(d) Certificate of Capacity. The Borrower shall have delivered to
----------- -- --------
the Administrative Agent an Officers' Certificate certifying that
the Borrower has capacity to incur additional indebtedness in the
amount of the Loan then being requested pursuant to the terms of (i)
if the earliest possible Termination Date applicable to such Loan is
365 days or more after the Drawdown Date for such Loan, the then
applicable order of the DPU authorizing the Borrower to incur long-
term indebtedness and (ii) if earliest possible Termination Date
applicable to such Loan is less than 365 days after the Drawdown
Date for such Loan, the then applicable order of FERC authorizing
the Borrower to incur short-term indebtedness.
15. Amendment to Section 7.3 - Borrowings After December 31, 1996.
--------- -- ------- --- ---------- ----- -------- --- ----
Section 7.3 of the Credit Agreement is hereby amended and restated in its
entirety as follows:
7.3 Borrowings After December 31, 1996. (i) In the case of each
---------- ----- -------- --- ----
Loan made after December 31, 1996 and prior to the Extension Date,
the Borrower shall have received an extension of the FERC Approval
authorizing the Borrower to incur indebtedness on the Drawdown Date
for such Loan, (ii) if the Extension Conditions shall have been
satisfied, in the case of each Loan made after the DPU Final
Incurrence Date but prior the Second Extension Date, the Borrower
shall have received an extension of the FERC Approval authorizing
the Borrower to incur indebtedness on the Drawdown Date for such
Loan, (iii) if the Second Extension Conditions shall have been
satisfied, in the case of each Loan made after the Second DPU Final
Incurrence Date, the Borrower shall have received an extension of
the FERC Approval authorizing the Borrower to incur indebtedness on
the Drawdown Date for such Loan, and (iv) notwithstanding the
foregoing , in the case of each Loan made after May 15, 1998, the
Borrower shall have received an extension of the FERC Approval
authorizing the Borrower to incur short-term indebtedness on the
Drawdown Date for such Loan, and, in the case of each clause (i),
(ii), (iii) and (iv), the Borrower shall have delivered a copy of
the applicable FERC Approval to the Administrative Agent, or shall
have delivered to the Administrative Agent an opinion of Ropes &
Gray, Borrower's counsel, that such approval is not required.
16. Amendment to Section 8 - Events of Default. Section 8(b) of the
--------- -- ------- - ------ -- -------
Credit Agreement is hereby amended by substituting the phrase "facility fee"
for the phrase "commitment fee" therein.
17. Amendment to Section 18 - Consents, Amendments, Waivers, Etc.
--------- -- ------- -- --------- ----------- -------- ----
Section 18 of the Credit Agreement is hereby amended by substituting the
phrase "facility fee" for the phrase "commitment fee" in the second sentence
thereof.
18. Amendment to Notices. Notwithstanding anything to the contrary set
--------- -- -------
forth in 15(d) of the Credit Agreement, the address for notices to each of
State Street Bank & Trust Company and Shawmut Bank, N.A., shall be that
address set forth for each such Bank in the signature pages hereof, or such
other address for notice as such Bank shall have last furnished in writing to
the Person giving such notice.
19. Conditions to Effectiveness. This Amendment shall become effective
---------- -- -------------
upon satisfaction of the following conditions:
(a) the execution of this Amendment by the Company, the Agents and
the Banks; and
(b) the delivery to the Banks from Messrs. Ropes & Gray, counsel to
the Borrower, a favorable legal opinion, dated as of the date hereof,
addressed to the Banks and substantially in the form of Exhibit A hereto.
------- -
20. No Other Amendments. Except as expressly provided in this
-- ----- ----------
Amendment, all of the terms and conditions of the Credit Agreement remain
unchanged, and the terms and conditions of the Credit Agreement as amended
hereby remain in full force and effect.
21. Execution in Counterparts. This Amendment may be executed in any
--------- -- ------------
number of counterparts and by each party on a separate counterpart, each of
which when so executed and delivered shall be an original, but all of which
together shall constitute one instrument. In proving this Amendment, it shall
not be necessary to produce or account for more than one such counterpart
signed by the party against whom enforcement is sought.
22. Miscellaneous. This Amendment shall be deemed to be a contract
-------------
under seal under the laws of The Commonwealth of Massachusetts and shall for
all purposes be construed in accordance with and governed by the laws of The
Commonwealth of Massachusetts. The captions in this Amendment are for
convenience of reference only and shall not define or limit the provisions
hereof.
IN WITNESS WHEREOF, the parties have executed this Amendment as of the
date first above written.
BOSTON EDISON COMPANY
By: /s/ Marc S. Alpert
-------------------------------------
Title: Vice President and Treasurer
THE FIRST NATIONAL BANK OF BOSTON
as Co-Agent and Administrative Agent
By: /s/ Michael Kane
-------------------------------------
Title: Managing Director
THE FIRST NATIONAL BANK OF BOSTON
By: /s/ Michael Kane
-------------------------------------
Title: Managing Director
CITIBANK, N.A.
as Co-Agent
By: /s/ Paul J. Addison
-------------------------------------
Title: Attorney In Fact
CITIBANK, N.A.
By: /s/ Paul J. Addison
-------------------------------------
Title: Attorney In Fact
THE FIRST NATIONAL BANK OF CHICAGO
By: /s/ Ronald L. Coleman
-------------------------------------
Title: Vice President
FLEET BANK OF MASSACHUSETTS, N.A.
By: /s/ Michael W. Borsey
-------------------------------------
Title: Vice President
BANK OF MONTREAL
By: /s/ John L. Smith
-------------------------------------
Title: Director
THE BANK OF NOVA SCOTIA
By: /s/ Michael R. Bradley
-------------------------------------
Title: Authorized Signatory
SWISS BANK CORPORATION
By: /s/ Darryl M. Monasebian
-------------------------------------
Title: Associate Director
Merchant Banking
By: /s/ John A. McCall
-------------------------------------
Title: Associate Director
THE BANK OF NEW YORK
By: /s/ John W. Hall
-------------------------------------
Title: Vice President
SHAWMUT BANK, N.A.
By: /s/ John P. Rafferty
-------------------------------------
Title: Director
One Federal Street, OF-0308
Boston, Massachusetts 02211
Attention: John P. Rafferty, Director
STATE STREET BANK & TRUST COMPANY
By: /s/ Lise Anne Boutiette
-------------------------------------
Title: Vice President
225 Federal Street
Boston, Massachusetts 02110
Attention: Lise Boutiette, Vice President
<TABLE>
Exhibit 12.1
Boston Edison Company
Computation of Ratio of Earnings to Fixed Charges
Year ended December 31, 1995
(in thousands)
<S> <C>
Net income from continuing operations $112,310
Income taxes 66,547
Fixed charges 129,576
--------
Total $308,433
========
Interest expense $119,282
Interest component of rentals 10,294
--------
Total $129,576
========
Ratio of earnings to fixed charges 2.38
====
</TABLE>
<TABLE>
Exhibit 12.2
Boston Edison Company
Computation of Ratio of Earnings to Fixed Charges
and Preferred Stock Dividend Requirements
Year ended December 31, 1995
(in thousands)
<S> <C>
Net income from continuing operations $112,310
Income taxes 66,547
Fixed charges 129,576
--------
Total $308,433
========
Interest expense $119,282
Interest component of rentals 10,294
--------
Subtotal $129,576
--------
Preferred stock dividend requirements 24,755
--------
Total $154,331
========
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.00
====
</TABLE>
Exhibit 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the incorporation by reference in the registration
statements of Boston Edison Company on Form S-3 (File Nos. 33-36824,
33-57840 and 33-59693) and on Form S-8 (File Nos. 33-00810, 33-7558,
33-38434, 33-48424, 33-48425, 33-59662, 33-59682 and 33-58457) of our
report dated January 25, 1996 on our audits of the consolidated financial
statements of Boston Edison Company as of December 31, 1995 and 1994 and
for each of the three years in the period ended December 31, 1995, which
report is included in this Annual Report on Form 10-K.
By: /s/ Coopers & Lybrand, L.L.P.
-------------------------------------
Coopers & Lybrand, L.L.P.
Boston, Massachusetts
March 28, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,955,642
<OTHER-PROPERTY-AND-INVEST> 126,514
<TOTAL-CURRENT-ASSETS> 345,306
<TOTAL-DEFERRED-CHARGES> 216,387
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,643,849
<COMMON> 48,003
<CAPITAL-SURPLUS-PAID-IN> 683,686
<RETAINED-EARNINGS> 257,749
<TOTAL-COMMON-STOCKHOLDERS-EQ> 989,438
92,000
123,000
<LONG-TERM-DEBT-NET> 1,160,223
<SHORT-TERM-NOTES> 75,941
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 50,500
<LONG-TERM-DEBT-CURRENT-PORT> 100,667
2,000
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,050,080
<TOT-CAPITALIZATION-AND-LIAB> 3,643,849
<GROSS-OPERATING-REVENUE> 1,628,503
<INCOME-TAX-EXPENSE> 68,276
<OTHER-OPERATING-EXPENSES> 1,332,827
<TOTAL-OPERATING-EXPENSES> 1,401,103
<OPERATING-INCOME-LOSS> 227,400
<OTHER-INCOME-NET> (575)
<INCOME-BEFORE-INTEREST-EXPEN> 226,825
<TOTAL-INTEREST-EXPENSE> 114,515
<NET-INCOME> 112,310
15,571
<EARNINGS-AVAILABLE-FOR-COMM> 96,739
<COMMON-STOCK-DIVIDENDS> 86,399
<TOTAL-INTEREST-ON-BONDS> 3,481
<CASH-FLOW-OPERATIONS> 310,658
<EPS-PRIMARY> 2.08
<EPS-DILUTED> 0
</TABLE>
