<PAGE> 1
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, 1993
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. [X]
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
---
The aggregate market value of the voting stock held by non-affiliates of
the registrant as of February 28, 1994 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: $1,220,739,336.
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 28, 1994
-------------------------- --------------------------------
<S> <C>
Common Stock, $1 par value 45,212,568 shares
</TABLE>
<TABLE>
DOCUMENTS INCORPORATED BY REFERENCE
<CAPTION>
Part Document
- ---- --------
<S> <C>
III Portions of definitive Proxy Statement dated March 17, 1994 for Annual Meeting of Stockholders to be held April 22, 1994.
</TABLE>
Exhibit list appears on page 51.
<PAGE> 2
Boston Edison Company
- -------------------------------------------------------------------------------
Form 10-K Annual Report
- -------------------------------------------------------------------------------
December 31, 1993
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Part I Page
- -------------------------------------------------------------------------------
<S> <C>
Item 1. Business 2
Item 2. Properties and Power Supply 10
Item 3. Legal Proceedings 13
Item 4. Submission of Matters to a Vote of Security Holders 13
Part II
- -------------------------------------------------------------------------------
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 17
Item 6. Selected Financial Data 18
Item 7. Management's Discussion and Analysis 19
Item 8. Financial Statements and Supplementary Financial
Information 28
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 48
Part III
- -------------------------------------------------------------------------------
Item 10. Directors and Executive Officers of the Registrant 48
Item 11. Executive Compensation 48
Item 12. Security Ownership of Certain Beneficial Owners and
Management 49
Item 13. Certain Relationships and Related Transactions 49
Part IV
- -------------------------------------------------------------------------------
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 50
</TABLE>
1
<PAGE> 3
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 demand side management (DSM) programs.
In 1993 the Company established an unregulated subsidiary known as the
Boston Energy Technology Group (BETG) following approval from the Massachusetts
Department of Public Utilities (DPU). The Company was granted authority to
invest up to $45 million in this wholly-owned subsidiary over the next three
years. BETG will engage in demand side management, electric transportation and
electric generation and distribution activities through its wholly-owned
subsidiaries Ener-G-Vision, Inc. and TravElectric Services Corporation. In
January 1994 BETG acquired a substantial majority interest in the assets of
REZ-TEK International, Inc. The new entity, REZ-TEK International Corporation,
will continue the business of manufacturing ozone water treatment systems. 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 approximately
590 square miles encompassing the City of Boston and 39 surrounding cities and
towns. The population of the area served with electricity at retail is
approximately 1.5 million. In 1993 the Company served an average of
approximately 651,000 customers. The Company also supplies electricity at
wholesale for resale to other utilities and municipal electric departments.
Revenues by class for the last three years are as follows:
<TABLE>
<CAPTION>
1993 1992 1991
- ----------------------------------------------------------------
<S> <C> <C> <C>
Retail electric revenues:
Commercial 49% 47% 47%
Residential 27% 26% 26%
Industrial 10% 10% 10%
Other 2% 4% 5%
Wholesale and contract revenues 12% 13% 12%
================================================================
</TABLE>
2
<PAGE> 4
Sources and Availability of Fuel
<TABLE>
The Company's generating units, other than Pilgrim Nuclear
Power Station, are fueled by oil, natural gas or both. The
Company's generation by type of fuel and the cost of fuel for
each of the last five years are as follows:
<CAPTION>
Percentage of Company Average Cost (Dollars per Million)
Generation by Source (%) of BTU's on a Burned Basis ($)
------------------------- -------------------------------
1993 1992 1991 1990 1989 1993 1992 1991 1990 1989
- ------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil 31.3 33.7 42.8 33.6 53.7 2.38 2.40 2.60 2.76 2.67
Gas 24.3 25.7 24.9 33.3 31.7 2.67 2.55 2.08 2.35 2.34
Nuclear 44.4 40.6 32.3 33.1 14.6 0.51 0.52 0.56 0.59 0.57
==================================================================
</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.
Most of the Company's natural gas is supplied on an interruptible basis
whereby a contract permits interruptions in deliveries by the supplier when
natural gas pipeline capacity is unavailable. Deliveries of natural gas to the
Company's generating units from suppliers may also be dependent on the
availability of pipeline capacity to the New England region and competitive
forces prevailing in the pipeline industry. Beginning in April 1995 the Company
will be required to operate New Boston Station using exclusively natural gas as
fuel, except in certain emergency circumstances, as part of a 1991 consent order
from the Massachusetts Department of Environmental Protection (DEP). The
Company has arrangements for a nine month supply of natural gas to the station
until April 1995 and is currently in the process of negotiating with suppliers
and transporters concerning the economics and availability of natural gas to the
station on a year-round basis after that time. Year-round gas supplies are
currently not available to the station and, as a result, the outcome of the
Company's negotiations with natural gas suppliers and transporters and the
impact on the operation of New Boston Station are uncertain.
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 that will individually allow operation of Pilgrim Station through
1998, 2000, 2001 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
3
<PAGE> 5
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 locations are unlimited in time, but their
rights are not vested and are subject to the action of these authorities and the
legislature.
Seasonal Nature of Business
The Company's kWh sales and revenues have historically been less in the
spring and fall than during winter and summer as sales tend to vary with weather
conditions. In addition, the Company bills higher base rates to commercial and
industrial customers during the billing months of June through September as
mandated by the DPU. Accordingly, a significant portion of annual earnings
occurs in the Company's third quarter. See Selected Consolidated Quarterly
Financial Data (Unaudited) in Item 8.
Working Capital Practices
The Company has no special practices with respect to working capital
that would be considered unusual for the electric utility industry or
significant for the understanding of the Company's business.
Customer Dependence
No material portion of the Company's business is dependent upon one or a
few customers.
Government Contracts
No material portion of the Company's business is subject to
renegotiation or termination of government contracts or subcontracts.
Competitive Conditions
The Company is experiencing a substantial increase in competition from
other electric utilities and non-utility generators to sell electricity for
resale. In response to the current environment the Company has secured
long-term power supply agreements with its four current wholesale customers
which set rates principally through the year 2002. The Company also obtained a
new wholesale customer for which it will provide up to 30 megawatts (MW) of
contract demand power for ten years beginning November 1994.
The DPU has created an 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. The Company submitted a draft IRM filing in March 1994 that covers
the period 1994 through 2004. In this filing the Company concluded that
adequate resources exist to meet customer needs for continued reliable, low cost
power through the period without procurement of any new generation resources.
The IRM process requires a settlement period in which intervenors and other
interested parties have the opportunity to review, comment and request
information on the draft filing. Any settlements reached will be reflected in
the Company's final IRM filing to be submitted in July 1994. Any remaining
issues will be litigated at the DPU through formal proceedings.
4
<PAGE> 6
Direct competition with other electric utilities for retail electricity
sales is still subject to substantial limitations, but these limitations may be
reduced in the future. The Company and other Massachusetts electric utilities
are protected in several ways by the DPU and municipal statutes against other
utilities offering service to retail customers in their service areas. Another
electric utility may not extend its service area to include municipalities other
than those named in its agreement of association or charter without DPU
authorization granted after notice and public hearing. Also, another company
may not obtain an initial location for its lines in a municipality served by the
Company without the approval of municipal authorities, subject to the right of
appeal to the DPU. Additionally, a municipality may not engage in the electric
utility business without complying with statutes requiring specific city or town
approval and the purchase of Company property within municipality limits.
However, the Company is currently experiencing some forms of competition
in the retail electric market. Current legislation allows industrial and large
commercial customers to own and operate their own electric generating units.
Retail customers may also substitute natural gas or oil for electricity as fuel
for heating and cooling purposes. The Company is responding to the current and
anticipated competitive pressures with a commitment to cost control and
increased operating efficiencies without sacrificing quality of service or
profitability.
Research Activities
The Company actively participates in several industry-sponsored
research activities. These expenditures, included in other operations and
maintenance expense on the consolidated income statements in Item 8, were not
material in 1993.
Environmental Matters
The Company is subject to numerous federal, state and local standards
with respect to air and water quality, waste disposal and other environmental
considerations. These standards can require modification of existing facilities
or curtailment or termination of operations at facilities, delay construction of
new facilities or increase capital and operating costs by substantial amounts.
Noncompliance with certain standards can, in some cases, also result in the
imposition of monetary civil penalties. The Company believes that its operating
facilities are in substantial compliance with currently applicable statutory and
regulatory environmental requirements.
The Company's capital expenditures for environmental purposes during the
five years 1989 through 1993 were approximately $125 million.
Environmental-related capital expenditures for the years 1994 through 1998 are
currently expected to approximate $43 million, including $17 million in 1994 and
$9 million in 1995. These amounts exclude costs associated with asbestos removal
which were approximately $11 million during the five years 1989 through 1993 and
are currently expected to be approximately $10 million for the years 1994
through 1998. The 1994 expected capital expenditures for environmental purposes
include costs to complete modifications at New Boston Station in order to
improve air quality and reduce emissions of nitrogen oxides, as discussed in the
Environmental section of Other Matters in Item 7, and to install air monitoring
systems at other Company generating units.
5
<PAGE> 7
Substantial additional expenditures could be required as changes in
environmental requirements occur.
The Company is subject to regulation by the United States Environmental
Protection Agency (EPA) and the Massachusetts Department of Environmental
Protection (DEP) with respect to discharges of effluent from the Company's
generating stations into receiving waters. The Federal Clean Water Act and the
Massachusetts Clean Waters Act require the Company to receive permits that limit
discharges in accordance with applicable water quality standards and are subject
to renewal every five years. The Company has received discharge permits as
required by the EPA and the DEP for each of its electric generating stations.
The Company is also subject to EPA and DEP regulation relative to
emissions from its fossil-fired generating units pursuant to Federal and
Massachusetts clean air laws, including the 1990 Clean Air Act Amendments.
These regulations require the installation of various emissions controls and the
use of low sulfur content fuels in certain cases. The Company's current status
regarding compliance with DEP regulations and the 1990 Clean Air Act Amendments
is discussed in the Environmental section in Item 7.
The Company is subject to various federal, state and local laws and
regulations pertaining to the generation, treatment, transportation, storage and
disposal of certain hazardous substances and to the cleanup of locations where
such substances have either been disposed of or spilled. One of the
requirements of these laws and regulations is that certain facilities which
treat, store or dispose of hazardous wastes must be licensed. The only facility
owned by the Company which requires such a license is Pilgrim Station.
Currently Pilgrim Station has received interim status approval for the treatment
and storage of certain wastes that are both hazardous and radioactive.
The Company has exposure to potential joint and several liability for
the cleanup of sites where hazardous wastes may have been spilled or disposed of
in the past. The Company has been notified of such potential liability for
approximately twelve sites, most of which involve numerous parties. Complex
litigation or negotiations among the parties and with regulatory authorities is
in process concerning the scope and cost of cleanup and the sharing of costs
among the potentially responsible parties for several of these sites. The
Company also faces additional exposure for the cleanup of Company-owned or
operated sites due to state regulations revised in 1993. The potential
hazardous waste liabilities are further described in the Environmental section
of Item 7.
The Company currently disposes of low-level radioactive waste (LLW)
generated at Pilgrim Station through arrangements with licensed disposal
facilities located in Barnwell, South Carolina. As a result of developments
which have occurred pursuant to the Low-Level Radioactive Waste Policy
Amendments Act of 1985, the Company's continued access to such disposal
facilities has become severely limited and significantly increased in cost. See
Note D to the consolidated financial statements in Item 8 for further discussion
regarding LLW disposal.
The Company's existing fuel storage facility at Pilgrim Station includes
sufficient room for spent nuclear fuel generated through early 1995. A request
for a license amendment to allow modification of the storage facility
6
<PAGE> 8
to provide sufficient room for spent nuclear fuel generated through the end of
Pilgrim's operating license in 2012 is pending before the Nuclear Regulatory
Commission (NRC). The Company expects approval of the request in 1994. At that
time the Company will initially modify the facility to provide spent fuel
storage capacity through approximately 2003. In addition, the United States
Department of Energy (DOE), which is ultimately responsible for the disposal of
spent nuclear fuel as required by the Nuclear Waste Policy Act of 1982, is
currently conducting scientific studies evaluating a potential spent nuclear
fuel repository site at Yucca Mountain, Nevada. The potential site, however,
has encountered substantial public and political opposition and litigation
and the DOE has publicly stated that it may be unable to construct such a
repository in a timely manner. The Company is unable to predict whether and on
what schedule the DOE will eventually construct a repository and what the effect
will be on the Company.
Published reports have discussed the possibility that adverse health
effects may be caused by electromagnetic fields associated with electric
transmission and distribution facilities and appliances and wiring in buildings
and homes. This topic is discussed more fully in the Environmental section of
Item 7.
Number of Employees
The Company had 4,404 full-time and 14 part-time employees as of the end
of 1993, 2,775 of which are represented by two locals of the Utility Workers
Union of America, AFL-CIO. The current four-year labor contract in effect with
the locals is scheduled to expire in May 1994. Labor contract negotiations
began in early February 1994 and the Company anticipates favorable resolution of
these negotiations.
(d) Financial Information about Foreign and Domestic Operations
- ---------------------------------------------------------------
and Export Sales
- ----------------
See Principal Products and Services for information regarding the
geographical area served by the Company and revenues by class for the last three
years.
(e) Additional Information
- --------------------------
Regulation
The Company and its wholly-owned subsidiary, Harbor Electric Energy
Company (HEEC), operate primarily under the authority of the DPU, whose
jurisdiction includes supervision over retail rates for electricity, financing,
investing and accounting. In addition, the Federal Energy Regulatory Commission
(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 such power, certain issuances of short-term debt and
regulation of the system of accounts. The Company's subsidiary BETG and its
subsidiaries are not subject to such regulation.
Recent requirements imposed on the Company by the DPU are discussed
under Competitive Conditions of this item and Non-Utility Generator Purchase
Contracts in Item 2.
7
<PAGE> 9
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 under long-term contracts. The Company provides
quarterly generating unit performance progress reports to the DPU. The DPU has
the right to reduce subsequent fuel clause 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.
In 1993 the Company received a generating unit performance order from
the DPU for the performance period November 1990 through October 1991. The
order required the Company to make refunds to its customers due to its not
meeting certain performance standards. A subsequent order was received from the
DPU in February 1994 for the performance period November 1991 through October
1992. The Company is currently assessing the potential customer refunds
associated with missed performance goals. The Company has not yet received an
order from the DPU for the performance period November 1992 through October
1993. The Company believes that its current provision for refunds will be
sufficient to cover all potential refunds.
The NRC has broad jurisdiction over the siting, construction and
operation of nuclear reactors with respect to public health and safety,
environmental matters and antitrust considerations. A license granted by the NRC
may be revoked, suspended or modified for failure to construct or operate a
facility in accordance with its terms. The Company currently holds an operating
license for Pilgrim Station which 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 may result in the issuance of
notices of violation. These notices may be accompanied by orders directing that
certain actions be taken or by the imposition of monetary civil penalties. In
addition, the Company might undertake certain actions in regard to Pilgrim
Station at the request or suggestion of its insurers or the Institute of Nuclear
Power Operations (INPO), a voluntary association of nuclear utilities dedicated
to the promotion of safety and reliability in the operation of nuclear power
plants.
Nuclear power continues to be a subject of political controversy and
public debate manifested from time to time in the form of requests for various
kinds of federal, state and local legislative or regulatory action, direct voter
initiatives or referenda or litigation. The Company cannot predict the extent,
cost or timing of any modifications to Pilgrim Station which might be required
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.
8
<PAGE> 10
Capital Expenditures and Financings
<TABLE>
The Company's most recent estimate of capital expenditures, allowance
for funds used during construction (AFUDC), long-term debt maturities and
sinking fund requirements for the years 1994 through 1998 are as follows:
<CAPTION>
(in thousands) 1994 1995 1996 1997 1998
- --------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Capital
expenditures (1) $201,000 $206,000 $184,000 $181,000 $172,000
AFUDC (2) 6,000 4,000 4,000 5,000 5,000
Long-term debt - 100,600 101,600 101,600 101,600
Preferred stock
sinking fund 2,000 2,000 2,000 2,000 2,000
====================================================================
<FN>
(1) Excludes estimated nuclear fuel expenditures of $19,000, $9,000, $23,000,
$12,000 and $25,000, respectively and capitalized DSM expenditures.
(2) Excludes estimated AFUDC on nuclear fuel of approximately $1,000 per year.
The estimated AFUDC rate varies from 4.0% to 6.5%.
</TABLE>
The Company conducts a continuing review of its capital expenditure and
financing programs. These programs and the estimates shown above are therefore
subject to revision due to changes in environmental standards, regulatory
requirements, availability and cost of capital, interest rates and other
assumptions. In addition, depending upon the outcome of certain air quality
modeling studies, the Company may be required to make additional expenditures by
1999 in order to comply with the provisions of the 1990 Clean Air Act
Amendments. The extent of any additional expenditures is uncertain at this
time.
Capital expenditures in 1993 were approximately $247 million and
consisted primarily of additions to the Company's transmission and distribution
systems and fossil and nuclear generation facilities. Significant projects
included spending for transmission and distribution of approximately $13 million
for the replacement of electric system property, $9 million for a new substation
and $7 million for a new energy control system. Capital spending for fossil
generation facilities included approximately $24 million for environmental
modifications at New Boston Station as described in the Environmental section of
Other Matters in Item 7. Expenditures in 1993 for Pilgrim Station included
approximately $32 million to improve efficiencies and meet regulatory
requirements and $8 million for a new administrative building. Funds generated
internally represented approximately 74%, 90% and 89% of capital expenditures in
1993, 1992 and 1991, respectively. It is expected that a significant portion of
future capital expenditures will be funded internally.
The Company intends to continue spending significant amounts on its DSM
programs. The Company spent approximately $53 million on these programs in
1993, of which $37 million was capitalized and is being collected from customers
over six years in accordance with the Company's 1992 settlement agreement. See
the Liquidity and Outlook for the Future sections in Item 7 for further
discussion regarding the Company's DSM programs.
9
<PAGE> 11
In 1993 the DPU approved a financing plan allowing the Company to issue
up to $1.1 billion in securities through 1994 and to use the proceeds to
refinance long-term securities and short-term debt. See Note F to the
consolidated financial statements in Item 8 for specific information relating to
the Company's financing activities.
Item 2. Properties and Power Supply
- ------------------------------------
Company-Owned Facilities
The Company's total installed electric generation capacity as
of December 31, 1993 is as follows:
<TABLE>
<CAPTION>
Installed
Capacity Year
Unit Location (MW) Type Installed
- -------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Pilgrim Nuclear Plymouth, MA 678 Nuclear 1972
Power Station
New Boston Station South Boston, MA 718 Fossil 1965-1967
Units 1 and 2
Mystic Station Everett, MA
Units 4-5-6 469 Fossil 1957-1961
Unit 7 617 Fossil 1975
Combustion turbine Various 239 Fossil 1966-1971
generators (ten)
=========================================================================
</TABLE>
All of the Company's steam fossil fuel-fired electric generating units
are located at tide water and have access to fuel oil storage and/or natural gas
or oil pipelines from nearby suppliers.
The Company is also a 5.888% joint owner in W.F. Wyman Unit 4. The 619
MW oil-fired unit located in Yarmouth, Maine began operations in 1978 and is
operated by Central Maine Power Company.
Additional electric generation capacity is available to the Company
through its contractual arrangements with other utilities and non-utilities and
its participation in the New England Power Pool as further described in this
item.
As of December 31, 1993 the Company's transmission system was comprised
of approximately 362 miles of overhead circuits operating at 115,000, 230,000
and 345,000 volts and approximately 155 miles of underground circuits operating
at 115,000 and 345,000 volts. The substations supported by these lines consist
of 42 transmission or combined transmission and distribution substations with
transformer capacity of 10,025 megavolt amperes (MVA), 71 distribution
substations with transformer capacity of 1,238 MVA and 18 primary network units
with 88 MVA capacity. In addition, high tension service was delivered to 231
customers' substations. The overhead distribution system covers approximately
4,652 miles of streets and the underground distribution system extends through
approximately 892 miles of streets. HEEC, the Company's regulated subsidiary,
has a distribution system that consists
10
<PAGE> 12
principally of a 4.09 mile 115Kv submarine distribution line and a temporary
substation which is located on Deer Island in Boston, Massachusetts.
The Company's significant items of property consist of electric
generating stations, substations and certain service centers and are generally
located on Company-owned land, with certain exceptions as set forth in the
Company's First Mortgage Bond Indenture and its supplements. 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 local or state authorities.
The Massachusetts Energy Facilities Siting Board (EFSB) must approve
Company plans for the construction of certain new generation or transmission
facilities based upon findings that such facilities are consistent with state
public health, environmental protection and resource use and development
policies. The Company currently has no proceedings before the EFSB.
Long-Term Power Contracts
Refer to Note K 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 contract with a subsidiary of Commonwealth Energy
System and two other utilities in which the participants are sharing in equal
amounts the output of an oil-fired electric generation plant. The Company is
obligated to pay 25% of the unit's fixed and operating costs plus an annual
return over a period of approximately 33 years for its proportionate share of
generation.
The Company has two long-term purchased power contracts with the
Massachusetts Bay Transit 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 but the Company retains New England Power
Pool credit for their capacity and output.
The Company owns 9.5% of the common stock of Connecticut Yankee Atomic
Power Company, which operates a nuclear generating unit. The Company is
entitled to receive 9.5% of the unit's output and is obligated to pay
Connecticut Yankee 9.5% of its fixed and operating costs plus an annual return
on investment.
Non-Utility Generator Purchase Contracts:
- -----------------------------------------
The Company currently purchases approximately 500 MW of capacity and
associated energy from non-utility generators. A majority of these purchases
are from Ocean State Power and Northeast Energy Associates. In 1993 the
L'Energia facility located in Lowell, Massachusetts was declared commercial and
the Company began purchasing electricity from this unit under a twenty-year
agreement. In addition, the Company is purchasing power from two
11
<PAGE> 13
small hydro facilities, and began purchasing capacity and energy from the
MassPower facility located in Springfield, Massachusetts in January 1994.
In June 1993 the DPU ordered the Company to purchase 132 MW of power
from Altresco Lynn, LP, an independent power producer, starting as early as
1995. The Company opposes this order since it does not believe it needs any new
power for several years. In July 1993 the Company asked the Massachusetts
Supreme Judicial Court to reverse the order. The Court has not yet ruled on the
Company's request. The Company has supported an appeal filed by other
interested parties of the Energy Facilities Siting Board's conditional approval
of Altresco Lynn's project. In February 1994 Altresco Lynn alleged that the
Company's actions in opposing the project were improper and that it may seek to
hold the Company responsible for any resulting damages.
Sales Contracts:
- ----------------
The Company has agreements with Montaup Electric Company, a subsidiary
of Eastern Utilities Associates, and with Commonwealth Electric Company, a
subsidiary of Commonwealth Energy System, under which Montaup and Commonwealth
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.
Montaup and Commonwealth have also agreed to indemnify the Company to the extent
of 11% each of all loss, liability or damage not covered by insurance resulting
from the operation, condemnation, shutdown or retirement of the unit. In
addition, the Company has similar agreements with multiple municipal electric
companies for a total of 3.7% of the capacity and corresponding energy of
Pilgrim Station.
New England Power Pool
The Company is a member of the New England Power Pool (NEPOOL), a
voluntary association of electric utilities in New England responsible for the
coordination, monitoring and directing of the operations of the major generating
and transmission facilities in the region. To assume 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 generating 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.
<TABLE>
The table below sets forth certain information as of the date of the
Company's 1993 summer and 1993-1994 winter peak loads:
<CAPTION>
January 19, 1994 July 7, 1993
(Winter 1993-94) (Summer 1993)
- ------------------------------------------------------------------------
<S> <C> <C>
NEPEX utilities installed capacity:
Seasonal maximum rating 25,529 MW 24,368 MW
Seasonal normal rating 25,232 MW 24,160 MW
NEPEX peak load (estimate) 19,422 MW 19,570 MW
Company territory peak load 2,474 MW 2,662 MW
========================================================================
</TABLE>
12
<PAGE> 14
The Company's net capacity was 3,663 MW at its summer peak and 3,533 MW
at is winter peak. Its corresponding NEPOOL capacity obligations were estimated
to be 3,190 MW and 3,289 MW, respectively.
In 1983 the NEPOOL participants signed an agreement, known as Phase I,
with Hydro-Quebec of Canada to provide up to three million MWH of hydro-electric
power annually to NEPOOL from 1986-1997. In 1985 a second agreement, known as
Phase II, was made between NEPOOL and Hydro-Quebec to provide an additional
seven million MWH of hydro-electric power annually for ten years. This
agreement required expansion of the existing 690 MW Phase I interconnection.
The Company and other New England electric utilities entered into an agreement
to expand the interconnection with the Hydro-Quebec system of Canada to 2,000
MW.
The Phase II facilities began full commercial operation up to the 2,000
MW level in July 1991. The price of this energy is based on the average cost of
fossil fuel in New England for the previous year. The contract price for the
first five years is 80% of that average, and for the second five years will be
95% of that average. 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 constructed the Phase II facilities. All equity
participants are required to guarantee, in addition to their own share, the
total obligations of those participants not meeting certain credit criteria.
Amounts so guaranteed by the Company were approximately $22 million at December
31, 1993.
As a result of the continuing additions to New England generating
capacity and minimally increasing energy requirements, the dispatching of
Company-owned generating facilities by NEPEX may be affected.
Item 3. Legal Proceedings
- --------------------------
In March 1991 the Company was named in a lawsuit brought in the United
States District Court for the District of Massachusetts alleging discriminatory
employment practices under the Age Discrimination in Employment Act of 1967
concerning 46 employees affected by the Company's 1988 reduction in force. Legal
counsel is vigorously defending this case. Based on the information presently
available, the Company does not expect that this litigation will have a material
impact on the Company's financial condition. However, an unfavorable decision
ordered against the Company could have a material impact on quarterly earnings.
See also Item 1, Environmental Matters and Note H to the consolidated
financial statements in Item 8 for a discussion of legal issues involving
hazardous waste sites.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
There were no matters submitted to a vote of security holders during the
fourth quarter of 1993.
13
<PAGE> 15
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, 1994 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>
Bernard W. Reznicek, 57 Chairman of the Board and Chief
Chairman of the Board and Executive Officer (since 1993),
Chief Executive Officer formerly Chairman, President
and Chief Executive Officer
(1992-1993), President and
Chief Executive Officer
(1990-1992) and President and
Chief Operating Officer
(1987-1990). Director (since
1987). Chairman of the Board,
Chief Executive Officer and
Director, Harbor Electric
Energy Company, Boston Energy
Technology Group, TravElectric
Services Corp. and Ener-G-
Vision, Inc.
Thomas J. May, 46 President and Chief Operating Officer
President and Chief (since 1993), formerly Executive Vice
Operating Officer President (1990-1993) and
Senior Vice President (1987-
1990). Director (since 1991).
President, Chief Operating
Officer and Director, Harbor
Electric Energy Company;
President and Director, Boston
Energy Technology Group;
Director, TravElectric Services
Corp., Ener-G-Vision, Inc. and
REZ-TEK International Corp.
</TABLE>
14
<PAGE> 16
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- -----------------------
<S> <C>
George W. Davis, 60 Executive Vice President (since
Executive Vice President 1992), responsible for all
power supply and delivery operations.
Director (since 1991). Senior
Vice President - Nuclear (1990-
1992). Vice President -
Nuclear Administration (1989-
1990).
E. Thomas Boulette, 51 Senior Vice President - Nuclear
Senior Vice President - Nuclear (since 1993). Vice President -
Nuclear Operations and Station
Director (1992-1993). Vice
President - Operations (1989-
1992) and Plant Manager (1988-
1989) of Maine Yankee Atomic
Power Company.
Cameron H. Daley, 48 Senior Vice President - Power
Senior Vice President - Supply (since 1989).
Power Supply Vice President - Power
Production (1982-1989).
John J. Desmond, III, 60 Senior Vice President - Legal (since
Senior Vice President - Legal 1992). Vice President and
General Counsel (1985-1992).
L. Carl Gustin, 50 Senior Vice President - Marketing &
Senior Vice President - Corporate Relations
Marketing & (since 1989).
Corporate Relations Vice President - Corporate Relations
(1986-1989).
John J. Higgins, Jr., 61 Senior Vice President - Human Resources
Senior Vice President - (since 1990).
Human Resources Vice President - Human
Resources (1988-1990).
Ronald A. Ledgett, 55 Senior Vice President - Power
Senior Vice President - Power Delivery (since 1991).
Delivery Director,
Special Projects (1989-1991).
</TABLE>
15
<PAGE> 17
<TABLE>
<CAPTION>
Business Experience
Name, Age and Position During Past Five Years
- ---------------------- ----------------------
<S> <C>
Charles E. Peters, Jr., 42 Senior Vice President - Finance
Senior Vice President - Finance (since 1991). Chief Financial
Officer and Senior Vice
President of Genrad, Inc.
(1985-1991). Vice President,
Treasurer and Director, Harbor
Electric Energy Company;
Treasurer and Director, Boston
Energy Technology Group;
Director, TravElectric Services
Corp., Ener-G-Vision, Inc. and
REZ-TEK International Corp.
Marc S. Alpert, 49 Vice President and Treasurer (since
Vice President and Treasurer 1988). Assistant Treasurer,
Harbor Electric Energy Company
and Boston Energy Technology
Group.
Robert J. Weafer, Jr., 47 Vice President, Controller and
Vice President, Controller Chief Accounting Officer
and Chief Accounting Officer (since 1991). Controller and Chief
Accounting Officer (1988-1991).
Theodora S. Convisser, 46 Clerk of the Corporation (since
Clerk of the Corporation 1986). Clerk of Harbor
Electric Energy Company, Boston
Energy Technology Group,
TravElectric Services Corp.,
Ener-G-Vision, Inc. and REZ-TEK
International Corp.
</TABLE>
16
<PAGE> 18
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 1993
and 1992:
<CAPTION>
1993 1992
- ------------------------------------------------------------------------
High Low High Low
- ------------------------------------------------------------------------
<S> <C> <C> <C> <C>
First quarter $30 1/2 $26 3/8 $24 5/8 $22 1/8
Second quarter 30 7/8 27 7/8 26 22 3/8
Third quarter 32 5/8 29 3/4 26 7/8 24 7/8
Fourth quarter 32 1/4 27 7/8 28 1/4 24 3/4
========================================================================
</TABLE>
(b) Holders
- -----------
As of December 31, 1993, the Company had 42,392 holders of
record of its common stock (actual count of record holders).
(c) Dividends
- -------------
<TABLE>
Following are the dividends declared per share of common
stock for each of the quarters in 1993 and 1992:
<CAPTION>
1993 1992
- -----------------------------------------------------------------------
<S> <C> <C>
First quarter $0.425 $0.410
Second quarter 0.425 0.410
Third quarter 0.425 0.410
Fourth quarter 0.440 0.425
=======================================================================
</TABLE>
17
<PAGE> 19
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>
1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating
revenues $1,482,253 $1,411,753 $1,354,501 $1,314,440 $1,339,956
Net income/
(loss) 118,218 107,298 94,670 79,616(a) (16,135)(b)
Earnings/(loss)
per common
share 2.28 2.10 1.96 1.60(a) (0.88)(b)
Total assets 3,477,299 3,294,234 3,119,285 3,012,589 2,876,691
Long-term debt 1,272,497 1,091,073 1,136,765 1,074,025 948,839
Redeemable
preferred/
preference
stock 221,000 221,000 221,333 221,333 221,333
Cash dividends
declared per
common share 1.715 1.655 1.595 1.535 1.745
===================================================================================================
<FN>
(a) Before cumulative effect of change in accounting principle ($15,824 or $0.41 per common share).
(b) Includes $106,280 or $2.78 per common share loss applicable to rate and contract settlements.
</TABLE>
18
<PAGE> 20
Item 7. Management's Discussion and Analysis
- ---------------------------------------------
REGULATORY PROCEEDINGS
Retail settlement agreements
Effective November 1992 our state regulators, the Massachusetts
Department of Public Utilities, approved a three-year settlement
agreement. This agreement provides us with retail rate
increases, allows for the recovery of demand side management
(DSM) conservation program expenditures, specifies certain
accounting adjustments and clarifies the timing and recognition
of certain expenses. The agreement also sets 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 consist of a new annual
performance adjustment charge effective November 1992 and two
additional rate increases of $29 million effective November 1993
and November 1994. The performance adjustment charge varies
annually based upon the performance of our Pilgrim Nuclear Power
Station. This charge is further described in our discussion of
financial condition.
Our 1993 results of operations were affected by the recovery
of DSM program expenditures, accounting adjustments and timing
and recognition of certain expenses as further described in the
following Results of Operations section.
Our state regulators approved a previous three-year
settlement agreement effective November 1989. That agreement
also provided us with retail rate increases and specified certain
accounting adjustments. The 1989 agreement primarily affected
our results of operations through 1992.
RESULTS OF OPERATIONS
1993 VERSUS 1992
Earnings per common share were $2.28 in 1993 and $2.10 in 1992.
The increase in earnings is primarily the result of an annual
rate increase effective November 1992, lower purchased power
expense due to a long-term contract expiration, no amortization
of deferred cancelled nuclear unit costs and lower interest
expense. These positive changes were partially offset by higher
operations and maintenance expense and higher income tax and
property tax expenses.
Operating revenues
<TABLE>
Operating revenues increased 5% over 1992 as follows:
<S> <C>
(in thousands)
- ------------------------------------------------------------
Retail electric revenues $70,837
Demand side management revenues 33,601
Wholesale and other revenues (2,794)
Short-term sales revenues (31,144)
- ------------------------------------------------------------
Increase in operating revenues $70,500
============================================================
</TABLE>
19
<PAGE> 21
Retail electric revenues increased $70.8 million. The
November 1992 and 1993 rate increases resulted in $40.6 million
of additional revenues in 1993. Fuel and purchased power
revenues increased $29.5 million over 1992, partly due to lower
revenues received from short-term power sales as discussed below.
We began recovery of certain demand side management program
costs, lost base revenues and incentives in August 1992. Our
1993 revenues provided $45.9 million related to 1991, 1992 and
1993 DSM programs. Our 1992 revenues of $12.3 million related
primarily to 1991 programs.
The decrease in wholesale and other revenues reflects an
estimated provision for refunds to customers of approximately $8
million as a result of orders from our state regulators on our
generating unit performance program.
Lower short-term power sales revenues were a result of changes
in our generation availability and the needs of short-term power
purchasers. All revenues from short-term sales serve to reduce
fuel and purchased power billings to retail customers and have no
effect on earnings.
Operating expenses
Fuel expense decreased $19.5 million primarily due to a 21.5%
decrease in generation, resulting from planned overhauls of our
fossil plants. Interchange purchases increased due to the lower
generation, resulting in a $7.5 million net increase in purchased
power expense. The net increase also reflects savings of
approximately $10 million from a long-term purchased power
contract that expired in October 1993. Both our fuel and
purchased power expenses are substantially fully recoverable
through fuel and purchased power revenues.
Other operations and maintenance expense increased 7.1%
primarily due to increases in employee benefits and nuclear
production expenses. Postretirement benefits expense increased
by $7 million primarily as a result of the adoption of a new
accounting standard and pension expense increased by $5 million;
both are provided for in our 1992 settlement agreement and
further explained in Note I to the consolidated financial
statements. A refueling outage at Pilgrim Station in 1993
resulted in higher nuclear production expenses.
Depreciation and amortization expense increased in 1993
primarily due to a higher annual decommissioning charge for
Pilgrim Station effective November 1992 provided by the 1992
settlement agreement. The new charge is based on a 1991 estimate
of decommissioning costs as further discussed in Note D to the
consolidated financial statements. In addition, the effect of
lower depreciation rates implemented in accordance with the
settlement agreement was offset by the effect of a higher
depreciable plant balance.
In accordance with our 1992 settlement agreement we did not
expense any of the $19 million of remaining deferred costs
associated with the cancelled Pilgrim 2 nuclear unit in 1993. We
will expense the remaining costs in 1994 and/or 1995.
Amortization of deferred nuclear outage costs includes 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
20
<PAGE> 22
these costs in June 1993 over five years are approved in
the 1992 settlement agreement.
The increase in demand side management programs expense is
consistent with the increase in DSM revenues. DSM expense
includes some costs recovered over a twelve month period and
other costs recovered over six years. We began to recover
previously deferred DSM expenses in August 1992. In 1993 we
expensed and collected from customers approximately $30 million
of deferred 1991, 1992 and 1993 program costs. Over six years we
are expensing and collecting from our customers $11 million of
costs capitalized in 1992 and $37 million of costs capitalized in
1993. The 1993 expense related to these capitalized costs was $7
million.
Municipal property and other taxes increased in 1993 due to
the absence of tax abatements. In 1992 property taxes were
reduced by $10.4 million of tax abatements in accordance with our
1989 settlement agreement.
Our effective annual income tax rate for 1993 was 23.4% vs.
8.7% for 1992. Both rates were significantly reduced by
adjustments to deferred income taxes of $20 million in 1993 and
$23 million in 1992 made in accordance with the 1992 and 1989
settlement agreements. The 1992 rate was also reduced due to tax
benefits of approximately $7 million resulting from mandated
payments made in accordance with the 1989 agreement. Our
adoption of a new accounting standard for income taxes in 1993
did not significantly affect earnings. We expect our effective
tax rate to be close to the statutory rate in 1994.
Interest charges and preferred and preference dividends
Total interest charges decreased $3.8 million in 1993. Interest
on long-term debt decreased primarily due to the refinancing of
substantially all our first mortgage bonds in 1993 at lower
interest rates, partially offset by higher amortization of
redemption premiums. Other interest charges decreased due to a
lower short-term debt level and lower short-term interest rates.
Allowance for funds used during construction (AFUDC), which
represents the financing costs of construction, decreased as a
result of a lower AFUDC rate related to lower short-term interest
rates.
Preferred and preference dividends decreased 5% due to the
replacement of a preferred and a preference stock issue with less
costly issues of preferred stock.
1992 VERSUS 1991
Earnings per common share were $2.10 in 1992 and $1.96 in 1991.
The increase in earnings is primarily the result of a rate
increase effective November 1991, incentive revenues earned from
the performance of Pilgrim Station and lower income tax and
interest expenses. These increases were partially offset by
higher operations and maintenance and property tax expenses. We
also had a one-time charge in 1992 for costs incurred for a
deferred generating plant project.
21
<PAGE> 23
Operating revenues
<TABLE>
Operating revenues increased 4.2% over 1991 as follows:
<S> <C>
(in thousands)
- -------------------------------------------------------------
Retail electric revenues $27,672
Demand side management revenues 12,343
Wholesale and other revenues 1,881
Short-term sales revenues 15,356
- -------------------------------------------------------------
Increase in operating revenues $57,252
=============================================================
</TABLE>
Retail electric revenues increased $27.7 million. We
received a $25 million rate increase effective November 1991 as
part of the 1989 settlement agreement. We also earned $8.2
million in incentive revenues in 1992 as a result of Pilgrim
Station's capacity factor exceeding its target set in the
agreement. Fuel and purchased power revenues decreased
approximately $5 million due to higher purchased power costs more
than offset by higher revenues received from short-term power
sales as discussed below.
In 1992 we began to receive revenues for the recovery of
certain DSM program costs, lost base revenues and incentives.
The 1992 revenues relate primarily to 1991 DSM programs.
Our short-term power sales increased in 1992 as a result of
our high generating unit availability and the greater power needs
of other New England utilities. All revenues from short-term
sales served to reduce fuel and purchased power billings to
retail customers and had no effect on earnings.
Operating expenses
Purchased power expense increased $18 million in 1992 due to new
long-term purchased power contracts. Both our fuel and purchased
power expenses are substantially fully recoverable through fuel
and purchased power revenues.
Other operations and maintenance expense increased 2.3% due
primarily to increases in employee benefit expenses and bad
debts.
Amortization of deferred nuclear outage costs in 1992 and 1991
includes amounts primarily related to the 1991 refueling outage
at Pilgrim Station. In 1991 we deferred approximately $23
million of refueling outage costs. We began to expense these
costs over five years in September 1991 as approved by our state
regulators.
Municipal property and other taxes increased 21% primarily due
to a reduction in residential and commercial real estate values
caused by the depressed economy. This resulted in higher tax
rates applied to our personal property values. In accordance
with our 1989 settlement agreement, municipal property tax
expenses were reduced by tax abatements of $10.4 million in 1992
and $13.6 million in 1991.
Our effective annual income tax rate for 1992 was 8.7% vs.
16.5% for 1991. Both rates were significantly reduced by
adjustments to deferred income taxes of $23 million in 1992 and
$13 million in 1991 made in accordance with the 1989 settlement
agreement. We also received tax benefits in both years as a
result of payments mandated by the agreement.
22
<PAGE> 24
Other income and expense
In 1992 we expensed $8 million of costs previously invested in
the proposed Edgar Energy Park generation project. This project
was deferred indefinitely as additional generating capacity is
not expected to be needed for several years.
Interest charges and preferred and preference dividends
Total interest charges decreased 4.6% primarily due to lower
interest rates on our average short-term borrowings. AFUDC
decreased 12.7% due to a lower AFUDC rate related to lower
short-term interest rates.
Preferred and preference dividends decreased approximately $1
million primarily due to the replacement of two preference stock
series with less costly issues of preferred stock.
Earnings per share
Net income increased 13%. However, earnings per common share for
1992 increased only 7%, reflecting an increase in the weighted
average number of common shares outstanding primarily a result of
our 1991 and 1992 common stock issuances.
FINANCIAL CONDITION
Our 1992 settlement agreement provides us with increased revenues
from retail customers over the three-year period ending October
1995. Additionally, a long-term purchased power contract with
annual charges of approximately $60 million expired in October
1993 with no related change in revenues. We are limited to an
annual rate of return on equity during the three-year period of
11.75%, excluding any penalties or rewards from performance
incentives.
Our continued ability to achieve or exceed the 11.75% rate of
return on equity will be primarily dependent upon our ability to
control costs and to earn performance incentives from generation
performance mechanisms specified in both the 1989 and 1992
settlement agreements. The most significant impact that
incentives can have on our financial results is based on Pilgrim
Station's annual capacity factor. Effective November 1993 an
annual capacity factor between 60% and 68% will provide us with
approximately $45 million of revenues through the performance
adjustment charge. For each percentage point increase in capacity
factor above 68%, annual revenues will increase by $670,000. For
each percentage point decrease in capacity factor below 60% (to a
minimum of 35%) annual revenues will decrease by $770,000.
Pilgrim's capacity factor for the performance year ending October
1994 is expected to be approximately 81% (assuming normal
operating conditions), an increase over the 66% capacity factor
achieved in the performance year ended October 1993, as no
refueling outage is scheduled for 1994. We earned approximately
$40 million in performance charge revenues in the performance
year ended October 1993.
Our fossil generation unit performance can provide an increase
or decrease of up to $4 million in revenues in each performance
year, however, we do not expect any revenue adjustments from this
mechanism.
23
<PAGE> 25
LIQUIDITY
We meet our plant expenditure cash requirements primarily with
internally generated funds. These funds (excluding payments made
related to settlement agreements) provided for 74%, 90% and 89% of our
plant expenditures in 1993, 1992 and 1991, respectively. Our current
estimate of plant expenditures for 1994 is $233 million, including $20
million of nuclear fuel additions. These expenditures will be used
primarily to maintain and improve existing transmission, distribution
and generation facilities. We also estimate capitalizable DSM
expenditures to be $38 million in 1994, which will be collected from
customers over six years. We do not expect plant expenditures,
excluding nuclear fuel and DSM, to vary significantly from the 1994
amount in the four years thereafter. We have long-term debt and
preferred stock payment requirements of $2 million in 1994, $102.6
million in 1995, and $103.6 million per year in 1996 through 1998.
External financings continue to be necessary to supplement our
internally generated funds, primarily the issuance of short-term
commercial paper and bank borrowings. We currently have authority
from our federal regulators to issue up to $350 million of short-term
debt. We have a $200 million revolving credit agreement and
arrangements with several banks to provide additional short-term
credit on a committed as well as on an uncommitted and as available
basis. At December 31, 1993 we had $204.1 million of short-term debt
outstanding, none of which was incurred under the revolving credit
agreement. In 1993 our state regulators approved a financing plan
allowing us to issue up to $1.1 billion in securities through 1994 and
to use the proceeds to refinance long-term securities and short-term
debt. At December 31, 1993 we had $245 million remaining authorized
to be issued under the plan which can be used to issue common stock,
preferred stock and long-term debt. As a result of our refinancing
activities in 1993 we expect to realize annualized savings of
approximately $11.5 million. Refer to Note F to the consolidated
financial statements for specific information relating to our recent
financing activities.
OUTLOOK FOR THE FUTURE
Electricity sales
A significant portion of our electricity sales are made to commercial
customers rather than industrial customers. As a result our sales
have been only moderately impacted by the decline in the local
Massachusetts economy. Our retail sales increased 1.2% in 1993 and we
anticipate only slight growth in retail sales in the near term.
Implementation of DSM programs, which are designed to assist
customers in reducing electricity use, will result in lower growth in
electricity sales. The 1992 settlement agreement established annual
DSM spending levels over $50 million through 1994. The agreement
provides for collection from customers of certain costs primarily in
the year incurred and others over a six-year period. We are also
provided with incentives and recovery of lost revenues based on the
actual reduction in customer electricity usage from these programs and
a return on the costs that we recover over six years.
Competition
As we are operating in a time of increasing competition from other
electric utilities and non-utility generators to sell electricity for
resale, we have secured long-term power supply agreements with our
four wholesale customers. Through these
24
<PAGE> 26
agreements our rates are set principally through the year 2002. We
also obtained a new wholesale customer in 1993 for which we will provide
up to 30 megawatts of contract demand power for ten years beginning
November 1994.
Our state regulators require utilities to purchase power from
qualifying non-utility generators at prices set through a bidding
process. In June 1993 our state regulators ordered us to purchase 132
megawatts of power from an independent power producer, starting as
early as 1995. We oppose this order since we do not believe we need
any new power for several years. In July 1993 we asked the
Massachusetts Supreme Judicial Court to reverse the order. We are
currently awaiting a decision from the court. In addition, our state
regulators have created an integrated resource management (IRM)
process in which electric utilities forecast their future energy needs
and propose how they will meet those needs by balancing conservation
programs with all other supplies of energy. We will submit an IRM
filing in March 1994.
Direct competition with other electric utilities for retail
electricity sales is still subject to substantial limitations, but
these limitations may be reduced in the future. In 1993 we announced
our goal of not seeking additional rate increases, other than those
provided in the 1992 settlement agreement, for our residential,
commercial and industrial customers until at least the year 2000. We
plan to accomplish this by controlling costs and increasing operating
efficiencies without sacrificing quality of service or profitability.
The announcement reflects our strong commitment to be a competitively
priced reliable provider of energy.
Non-utility business
In 1993 we created an unregulated subsidiary known as the Boston
Energy Technology Group (BETG) following approval from our state
regulators. We have authority to invest up to $45 million in this
wholly-owned subsidiary over the next three years. BETG will engage
in demand side management activities through its wholly-owned
subsidiary Ener-G-Vision, Inc. and businesses involving electric
transportation and the related infrastructure through its wholly-owned
subsidiary TravElectric Services Corporation. 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.
In January 1994 BETG acquired a substantial majority interest in
the assets of REZ-TEK International, Inc., a manufacturer of ozone
water treatment systems. The new entity, which will be known as
REZ-TEK International Corp., will continue the business of producing a
system that treats cooling water used in commercial and industrial air
conditioning systems in an energy efficient and environmentally sound
manner.
OTHER MATTERS
Environmental
We are subject to numerous federal, state and local standards with
respect to air and water quality, waste disposal and other
environmental considerations. These standards can require that we
modify our existing facilities or incur increased operating costs.
In 1991 we entered into a consent order with the Massachusetts
Department of Environmental Protection (DEP) and other interested
parties to undertake certain improvements in the emission control
systems at New Boston Station. These
25
<PAGE> 27
improvements included the replacement of four existing chimney stacks
with two taller stacks in order to improve the air quality in the
vicinity of the station, and the installation of low nitrogen oxides
burners. The capital cost of these modifications along with other
associated improvements has been approximately $78 million through
1993 with an additional $3 million expected to complete these
projects in 1994.
New Boston Station has the ability to burn natural gas, oil
or both. As part of the DEP consent order we also agreed to
operate the station using natural gas as fuel for a minimum of
nine months per year beginning in April 1992. Beginning in April
1995 we will be required to operate the station fueled
exclusively by natural gas, except in certain emergency
circumstances. We have made arrangements for a nine month supply
of natural gas to the station until April 1995 and are currently
in the process of negotiating with natural gas suppliers and
transporters concerning the economics and availability of natural
gas to New Boston on a year-round basis after that time. Year-
round gas supplies are currently not available to the station
and, as a result, the outcome of our negotiations with natural
gas suppliers and transporters and the impact on the operation of
New Boston Station are uncertain.
The 1990 Clean Air Act Amendments will require a significant
reduction in nationwide emissions of sulfur dioxide from fossil fuel-
fired generating units. The reduction will be accomplished by
restricting sulfur dioxide emissions through a market-based system of
allowances. We believe that we will have allowances issued to us that
are in excess of our needs and which may be marketable. Any gain from
the sale of these may be subject to future regulatory treatment.
Other provisions of the 1990 Clean Air Act Amendments involve
limitations on emissions of nitrogen oxides from existing generating
units. Combustion system modifications made to New Boston and Mystic
Stations, including the installation of the low nitrogen oxides
burners at New Boston, will allow the units to meet the provisions of
the 1995 standards. Depending upon the outcome of certain air quality
modeling studies, additional emission reductions may also be required
by 1999. The extent of any additional reductions and the cost of any
further modifications is uncertain at this time.
State regulations revised in 1993 require that properties where
releases of hazardous materials occurred in the past be further
cleaned up according to a timetable developed by the DEP. We are
currently evaluating the potential costs associated with the cleanup
of sites where we have been identified as the owner or operator.
There are uncertainties associated with these potential 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 certain other multi-party hazardous waste sites in
Massachusetts and other states. At the majority of these other sites
we are one of many potentially responsible parties and our alleged
share of the responsibility is a small percentage. We do not expect
any of our potential cleanup liabilities to have a material impact on
financial condition, although provisions for cleanup costs could have
a material impact on quarterly earnings.
We presently dispose of low-level radioactive waste (LLW) generated
at Pilgrim Station at licensed disposal facilities in Barnwell, South
Carolina. As a result of developments which have occurred pursuant to
the Low-Level Radioactive Waste Policy Amendments Act of 1985, our
continued access to such disposal facilities has become severely
limited and significantly increased in cost. Refer to Note D to the
consolidated financial statements for further discussion regarding LLW
disposal.
In recent years a number of published reports have discussed the
possibility that adverse health effects may be caused by
electromagnetic fields (EMF) associated with
26
<PAGE> 28
electric transmission and distribution facilities and appliances and
wiring in buildings and homes. Some scientific reviews conducted to
date by several state and federal agencies have suggested associations
between EMF and such 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 before regulators, or in requests for legislation or
regulatory standards concerning EMF levels. We have not been
significantly affected to date by these developments and cannot predict
their potential impact on us, however, we continue to closely monitor all
aspects of the EMF issue.
Litigation
In March 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 is vigorously defending this
case. Based on the information presently available we do not
expect that this litigation or certain other legal matters in
which we are currently involved will have a material impact on
our financial condition. However, an unfavorable decision
ordered against us could have a material impact on quarterly
earnings.
Labor negotiations
We began negotiations involving our labor contracts in early February
1994. These contracts expire on May 15, 1994. We anticipate
favorable resolution of these negotiations prior to that date.
New accounting pronouncements
We will adopt Statement of Financial Accounting Standards (SFAS)
No. 112, Employers' Accounting for Postemployment Benefits, and
SFAS No. 115, Accounting for Certain Investments in Debt and
Equity Securities, in the first quarter of 1994. Refer to Notes
I and J to the consolidated financial statements for further
discussion of these pronouncements.
27
<PAGE> 29
<TABLE>
ITEM 8. Financial Statements and Supplementary Financial Information
- ---------------------------------------------------------------------
Consolidated Statements of Income
<CAPTION>
years ended December 31,
(in thousands, except earnings per share) 1993 1992 1991
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $1,482,253 $1,411,753 $1,354,501
Operating expenses:
Fuel 176,366 195,873 200,912
Purchased power 364,482 356,931 338,994
Other operations and maintenance 406,271 379,350 370,758
Depreciation and amortization 137,722 129,045 126,151
Amortization of deferred cost of
cancelled nuclear unit 0 24,381 24,381
Amortization of deferred nuclear
outage costs 6,546 4,901 2,443
Demand side management programs 37,504 8,221 1,674
Taxes - property and other 93,102 80,426 66,216
Income taxes 34,941 11,725 17,111
- ----------------------------------------------------------------------------------------
Total operating expenses 1,256,934 1,190,853 1,148,640
- ----------------------------------------------------------------------------------------
Operating income 225,319 220,900 205,861
Other income (expense), net 589 (2,074) 5,684
- ----------------------------------------------------------------------------------------
Operating and other income 225,908 218,826 211,545
- ----------------------------------------------------------------------------------------
Interest charges:
Long-term debt 104,375 106,850 108,912
Other 9,778 12,525 16,947
Allowance for borrowed funds used
during construction (6,463) (7,847) (8,984)
- ----------------------------------------------------------------------------------------
Total interest charges 107,690 111,528 116,875
- ----------------------------------------------------------------------------------------
Net income 118,218 107,298 94,670
Preferred and preference dividends provided 15,705 16,550 17,611
- ----------------------------------------------------------------------------------------
Balance available for common stock $ 102,513 $ 90,748 $ 77,059
========================================================================================
Common shares outstanding (weighted average) 44,959 43,144 39,348
Earnings per share of common stock $ 2.28 $ 2.10 $ 1.96
========================================================================================
</TABLE>
<TABLE>
Consolidated Statements of Retained Earnings
<CAPTION>
years ended December 31,
(in thousands) 1993 1992 1991
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance at beginning of year $192,948 $174,477 $161,143
Net income 118,218 107,298 94,670
- ----------------------------------------------------------------------------------------
Subtotal 311,166 281,775 255,813
- ----------------------------------------------------------------------------------------
Cash dividends declared:
Preferred stock 15,705 14,923 9,476
Preference stock 0 1,953 8,135
Common stock 77,169 71,951 63,725
- ----------------------------------------------------------------------------------------
Subtotal 92,874 88,827 81,336
- ----------------------------------------------------------------------------------------
Balance at end of year $218,292 $192,948 $174,477
========================================================================================
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
28
<PAGE> 30
<TABLE>
Consolidated Balance Sheets
<CAPTION>
December 31,
(in thousands) 1993 1992
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Assets
Property, plant and equipment, at
original cost:
Utility plant in service $3,904,776 $3,629,727
Less: accumulated depreciation 1,258,359 $2,646,417 1,177,294 $2,452,433
- ---------------------------------------------------------------------------------------------
Nuclear fuel 273,867 270,420
Less: accumulated amortization 220,477 53,390 201,978 68,442
- ---------------------------------------------------------------------------------------------
Construction work in progress 144,835 182,458
- ---------------------------------------------------------------------------------------------
Total 2,844,642 2,703,333
Investments in electric companies, at equity 24,292 25,398
Nuclear decommissioning fund, at cost 66,060 50,871
Current assets:
Cash and cash equivalents 8,768 3,947
Accounts receivable 171,098 185,563
Accrued unbilled revenues 29,823 28,564
Fuel, materials and supplies, at
average cost 79,381 93,931
Prepaid expenses and other 9,738 298,808 6,644 318,649
- ---------------------------------------------------------------------------------------------
Deferred debits:
Power contracts 36,275 43,717
Cancelled nuclear unit 19,067 19,067
Nuclear outage costs 25,524 17,970
Pension and postretirement costs 24,416 10,449
Redemption premiums 59,116 40,506
Regulatory asset-income taxes, net 26,916 0
Other 52,183 243,497 64,274 195,983
- ---------------------------------------------------------------------------------------------
Total assets $3,477,299 $3,294,234
=============================================================================================
Capitalization and Liabilities
Common stock equity $ 876,479 $ 840,312
Cumulative preferred stock:
Non-mandatory redeemable series 123,000 123,000
Mandatory redeemable series 96,000 98,000
First mortgage bonds 40,000 631,825
Sewage facility revenue bonds, net 32,497 24,248
Debentures 1,200,000 385,000
Unsecured medium-term notes 0 50,000
Current liabilities:
Long-term debt/preferred
stock due within one year $ 2,000 $ 6,800
Notes payable 204,151 275,500
Accounts payable 144,760 154,251
Interest accrued 25,467 21,497
Dividends payable 22,696 22,192
Other 27,336 426,410 12,482 492,722
- ---------------------------------------------------------------------------------------------
Deferred credits:
Power contracts 36,275 43,717
Accumulated deferred income taxes 484,796 448,720
Accumulated deferred investment
tax credits 71,140 75,213
Nuclear decommissioning reserve 73,744 57,165
Other 16,958 682,913 24,312 649,127
- ---------------------------------------------------------------------------------------------
Commitments and contingencies - -
- ---------------------------------------------------------------------------------------------
Total capitalization and liabilities $3,477,299 $3,294,234
=============================================================================================
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
29
<PAGE> 31
<TABLE>
Consolidated Statements of Cash Flows
<CAPTION>
Years ended December 31,
(in thousands) 1993 1992 1991
- -------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income $118,218 $107,298 $ 94,670
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation 130,074 123,243 121,572
Amortization of nuclear fuel 21,816 25,473 19,869
Amortization of deferred cost of cancelled
nuclear unit, net 0 22,340 21,112
Other amortization 9,433 2,132 1,696
Allowance for funds used during (6,463) (7,847) (8,984)
construction
Deferred income taxes 10,303 17,165 24,476
Investment tax credits (4,073) (4,273) (4,290)
(Deferral) amortization of nuclear outage
costs, net (7,554) 4,901 (22,062)
Net changes in:
Accounts receivable and accrued
unbilled revenues 13,206 (18,188) (3,519)
Fuel, materials and supplies 9,722 (2,330) 12,716
Accounts payable (9,491) 41,899 (19,510)
Rate and contract settlements (175) (31,363) (44,546)
Other current assets and liabilities 16,408 (2,565) 3,079
Other, net (4,958) (13,777) (24,588)
- -------------------------------------------------------------------------------------
Net cash provided by operating activities 296,466 264,108 171,691
- -------------------------------------------------------------------------------------
Cash flows provided (used) by investing activities:
Plant and nuclear fuel (excluding AFUDC) (253,885) (231,025) (214,213)
Capitalized demand side management costs (37,156) (11,469) 0
Decommissioning fund (15,189) (7,210) (5,896)
Investments in electric companies 1,106 1,836 (1,515)
- -------------------------------------------------------------------------------------
Net cash used by investing activities (305,124) (247,868) (221,624)
- -------------------------------------------------------------------------------------
Cash flows provided (used) by financing activities:
Issuances:
Common stock 10,823 68,345 68,800
Preferred stock 40,000 40,000 50,000
Long-term debt 815,000 60,000 146,120
Redemptions:
Debt retirements (648,625) (123,600) (118,600)
Preferred/preference stock (40,000) (40,333) (50,000)
Net change in short-term debt (71,349) 65,200 35,770
Dividends paid (92,370) (86,184) (79,545)
- -------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 13,479 (16,572) 52,545
- -------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents 4,821 (332) 2,612
Cash and cash equivalents at the
beginning of the year 3,947 4,279 1,667
- -------------------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $ 8,768 $ 3,947 $ 4,279
=====================================================================================
Cash paid during the year for:
Interest, net of amounts capitalized $103,720 $113,076 $115,488
Income taxes $ 30,305 $ 10,095 $ 18,979
</TABLE>
The accompanying notes are an integral part of the consolidated financial
statements.
30
<PAGE> 32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE A. SIGNIFICANT ACCOUNTING POLICIES
1. Basis of Consolidation and Accounting
The consolidated financial statements include the activities of our
wholly-owned subsidiaries, Harbor Electric Energy Company and Boston Energy
Technology Group. All significant intercompany transactions have been
eliminated.
We follow accounting policies prescribed by our federal and state
regulators. We are also subject to the accounting and reporting requirements
of the Securities and Exchange Commission. The financial statements comply
with generally accepted accounting principles. Certain prior period amounts on
the financial statements were reclassified to conform with current
presentation.
2. Revenue Recognition
We record revenues for electricity used by our customers, but not yet billed,
in order to more closely match revenues with expenses.
3. Forecasted Fuel and Purchased Power Rates
The rate charged to retail customers for fuel and purchased power allows for
all fuel costs, the capacity portion of some purchased power costs and some
transmission costs to be billed to customers monthly using a forecasted rate.
The difference between actual and estimated costs is included in accounts
receivable on our consolidated balance sheets until subsequent rates are
adjusted. State regulators have the right to reduce our subsequent fuel rates
if they find that we have been unreasonable or imprudent in the operation of
our generating units or in purchasing fuel.
4. Depreciation and Nuclear Fuel Amortization
Our physical property was depreciated on a straight-line basis in 1993, 1992
and 1991 at composite rates of approximately 3.09%, 3.36% and 3.41% per year,
respectively, based on estimated useful lives of the various classes of
property. The cost of decommissioning Pilgrim Station, our nuclear unit, is
excluded from the depreciation rates. When property units are retired, their
cost, net of salvage value, is charged to accumulated depreciation.
The cost of nuclear fuel is amortized based on the amount of energy Pilgrim
Station produces. Nuclear fuel expense also includes an amount for the
estimated costs of ultimately disposing of the spent nuclear fuel and for the
decontamination and decommissioning of the United States enrichment facilities
used in the production of nuclear fuel. These costs are recovered from our
customers through fuel charges.
5. 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. AFUDC is not an item of current cash income, but payment is received
for these costs from customers over the service life of the plant in the form
of increased revenues collected as a result of higher depreciation expense.
Our AFUDC rates in 1993, 1992 and 1991 were 3.62%, 4.48%, and 6.85%,
respectively, and represented only the cost of debt.
31
<PAGE> 33
6. Cash and Cash Equivalents
Cash and cash equivalents are comprised of highly liquid securities with
maturities of three months or less.
7. 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.
8. Deferred Debits
Deferred debits consist primarily of costs incurred which will be collected
from customers through future charges in accordance with agreements with our
state regulators. These costs will be expensed when the corresponding revenues
are received in order to appropriately match revenues and expenses. A portion
of these costs is currently being charged to and collected from customers.
9. Amortization of Discounts, Premiums and Redemption Premiums on Securities
We expense discounts, premiums, redemption premiums and related expenses
associated with issuances of securities or refinancing of existing securities
in equal annual installments over the life of the replacement securities
subject to regulatory approval.
NOTE B. RETAIL SETTLEMENT AGREEMENTS
In 1992 and 1989 our state regulators, the Massachusetts Department of Public
Utilities, approved three-year settlement agreements relating to our rate case
proceedings. These agreements provided for retail rate increases, accounting
adjustments and demand side management program expenditures; clarified the
timing and recognition of certain expenses and set limits on our rate of return
on common equity. Refer to Management's Discussion and Analysis for further
information related to these settlement agreements.
The settlement agreements did not affect our contract or wholesale power
rates charged to other utilities, which are regulated by our federal
regulators, the Federal Energy Regulatory Commission.
NOTE C. INCOME TAXES
In the first quarter of 1993 we prospectively adopted Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). This
required us to change our methodology of accounting for income taxes from the
deferred method to an asset and liability approach. The deferred method of
accounting was based on the tax effects of timing differences between income
for financial reporting purposes and taxable income. The asset and liability
approach requires the recognition of deferred tax liabilities and assets 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 a net regulatory asset of $26.9 million and a corresponding net
increase in accumulated deferred income taxes as of December 31, 1993. The
regulatory asset represents the additional future revenues to be collected from
customers for deferred income taxes.
Accumulated deferred income taxes on our consolidated balance sheet at
December 31, 1993 includes $587.8 million of gross deferred income tax
liabilities net of $103.0 million of gross
32
<PAGE> 34
deferred income tax assets. We have approximately $19 million of
alternative minimum tax carryforwards available at December 31, 1993. The
major components of accumulated deferred income taxes are a result of
differences between book and tax expenses relating to property, plant and
equipment.
Deferred income tax expense reflected in our consolidated income statements
is incurred when certain income and expenses are reported on the tax return in
different years than reported in the financial statements. Investment tax
credits are included in income over the estimated useful lives of the related
property.
<TABLE>
Components of income tax expense are as follows:
<CAPTION>
(in thousands) 1993 1992 1991
- ----------------------------------------------------------------------------
<S> <C> <C> <C>
Excess tax depreciation over book $12,382 $9,765 $10,802
depreciation
Deferred fuel expense (3,142) 2,587 56
Debt portion of allowance for funds used
during construction 2,114 2,495 2,856
Massachusetts corporate franchise tax 5,089 6,134 7,140
Deferred nuclear outage expense 2,472 (1,558) 7,014
Cost of removal 3,272 6,904 4,277
Rate and contract settlements 0 10,013 10,196
Municipal property taxes (489) 3,351 3,745
Demand side management programs 3,775 2,978 2,256
Cancelled nuclear unit 0 (4,621) (8,998)
Reversal of deferred taxes-settlement
agreement, net (19,231) (23,000) (13,000)
Adjustment of prior year income tax accrual (2,154) 4,134 2,563
Call premiums on refunded bond issues 5,821 1,029 (288)
Trust contributions-postretirement benefits 3,451 0 0
Other (3,057) (3,828) (5,395)
- ----------------------------------------------------------------------------
Subtotal deferred income taxes 10,303 16,383 23,224
Current income tax expense 28,711 (385) (1,823)
Investment tax credits (4,073) (4,273) (4,290)
- ----------------------------------------------------------------------------
Provision for income taxes 34,941 11,725 17,111
- ----------------------------------------------------------------------------
Taxes on other income:
Current 1,205 (2,348) 405
Deferred 0 782 1,252
- ----------------------------------------------------------------------------
Subtotal 1,205 (1,566) 1,657
- ----------------------------------------------------------------------------
Total income tax expense $36,146 $10,159 $18,768
============================================================================
</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 are explained below:
<CAPTION>
1993 1992 1991
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Statutory tax rate 35.0% 34.0% 34.0%
State income tax, net of federal income 4.2 3.9 4.1
tax benefit
Investment tax credits (2.6) (3.6) (3.8)
Municipal property tax adjustment (0.6) (1.6) (1.6)
Adjustment of deferred taxes on cancelled
nuclear unit - 2.7 -
Reversal of deferred taxes-settlement (13.0) (19.6) (11.5)
agreement
Federal tax benefit of mandated
payments from settlement agreements - (6.2) (3.3)
Other 0.4 (0.9) (1.4)
- -----------------------------------------------------------------------------
Effective tax rate 23.4% 8.7% 16.5%
=============================================================================
</TABLE>
33
<PAGE> 35
NOTE D. ESTIMATED FUTURE COSTS OF DISPOSING OF SPENT NUCLEAR FUEL AND RETIRING
NUCLEAR GENERATING PLANTS
The existing fuel storage facility at Pilgrim Station includes sufficient room
for spent nuclear fuel generated through early 1995. We have a request for a
license amendment pending before the Nuclear Regulatory Commission (NRC) to
allow modification of the storage facility to provide sufficient room for spent
nuclear fuel generated through the end of Pilgrim's operating license in 2012.
The NRC is reviewing our request and we expect approval in 1994. At that time
we will initially modify the facility to provide spent fuel storage capacity
through approximately 2003. It is the ultimate responsibility of the United
States Department of Energy (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.
When Pilgrim Station's operating license expires in 2012 we will be required
to decommission the plant. During rate proceedings we provided our regulators
a 1991 study documenting a cost of $328 million to decommission the plant. The
study is based on the "green field" method of decommissioning, which provides
for the plant site to be completely restored to its original state. We are
expensing these estimated decommissioning costs over Pilgrim's expected service
life. The 1993 expense of approximately $13 million is included in
depreciation expense on the consolidated income statements. We receive
recovery of this expense from charges to our retail customers and from other
utility companies and municipalities who purchase a contracted amount of
Pilgrim's electric generation. The funds we collect from decommissioning
charges are deposited in an external trust and are restricted so that they may
only be used for decommissioning and related expenses. The net earnings on the
trust funds, which are also restricted, increase the nuclear decommissioning
fund balance and nuclear decommissioning reserve, thus reducing the amount to
be collected from customers. The 1991 decommissioning study has been partially
updated for internal planning purposes to evaluate the potential financial
impact of long-term spent fuel storage options resulting from delays in DOE
spent fuel removal on the estimated decommissioning cost. The partial update
indicates an estimated decommissioning cost of approximately $400 million in
1991 dollars based upon a revised spent fuel removal schedule and utilization
of dry spent fuel storage technology. We will continue to monitor DOE spent
fuel removal schedules and developments in spent fuel storage technology along
with their impact on the decommissioning estimate.
We are also an investor in two other domestic nuclear units. Both of these
units receive through the rates charged to their customers an amount to cover
the estimated cost to dispose of their spent nuclear fuel and to retire the
units at the end of their useful lives.
We presently dispose of low-level radioactive waste (LLW) generated at
Pilgrim Station at licensed disposal facilities in Barnwell, South Carolina.
As a result of developments which have occurred pursuant to the Low-Level
Radioactive Waste Policy Amendments Act of 1985, our continued access to such
disposal facilities has become severely limited and significantly increased in
cost. We have access to the South Carolina site through July 1994, but do not
presently believe that disposal site access will be provided after that date.
Although legislation has been enacted in Massachusetts establishing a
regulatory method for managing the state's LLW including the possible siting,
licensing and construction of a LLW disposal facility within the state, it
appears unlikely that such a facility will be constructed in a timely manner.
Pending the construction of a disposal facility within the state or the
adoption by the state of some other LLW management method, we continue to
monitor the situation and are investigating other available options, including
the possibility of on-site storage.
34
<PAGE> 36
NOTE E. CANCELLED NUCLEAR UNIT
In May 1982 we began to expense the cost of our cancelled Pilgrim 2 nuclear
unit over approximately eleven and one-half years in accordance with an order
received from state regulators. We did not expense any of these costs in 1993.
Instead, the remaining balance of approximately $19 million at December 31,
1993 and 1992 will be expensed in 1994 and/or 1995 as approved by our state
regulators in our 1992 settlement agreement.
35
<PAGE> 37
NOTE F. CAPITAL STOCK AND INDEBTEDNESS
<TABLE>
Capital Stock
<CAPTION>
December 31,
(dollars in thousands, except per share amounts) 1993 1992 1991
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
COMMON STOCK EQUITY:
Common stock, par value $1 per share,
100,000,000 shares authorized;
45,129,227, 44,763,055 and
42,047,356 shares issued
and outstanding $ 45,129 $ 44,763 $ 42,047
Premium on common stock 612,653 602,196 536,567
Retained earnings 218,292 192,948 174,477
Surplus invested in plant 405 405 405
- ------------------------------------------------------------------------------
Total common stock equity $876,479 $840,312 $753,496
==============================================================================
</TABLE>
<TABLE>
CUMULATIVE PREFERRED STOCK:
Par value $100 per share, 2,410,000 shares currently
authorized; issued and outstanding:
Non-mandatory 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 0 0
8.25% 400,000 - 40,000 40,000 0
8.88% 0 - 0 40,000 40,000
- ------------------------------------------------------------------------------
Total non-mandatory redeemable series $123,000 $123,000 $ 83,000
==============================================================================
</TABLE>
<TABLE>
Mandatory redeemable series:
<CAPTION>
Current Shares
Series Outstanding
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
7.27% 480,000 $48,000 $48,000 $ 50,000
8.00% 500,000 50,000 50,000 50,000
- ------------------------------------------------------------------------------
Total mandatory redeemable series 98,000 98,000 100,000
Less: due within one year 2,000 0 0
- ------------------------------------------------------------------------------
Total mandatory redeemable series, net $96,000 98,000 $100,000
==============================================================================
</TABLE>
<TABLE>
CUMULATIVE PREFERENCE STOCK:
Par value $1 per share, 8,000,000 shares
authorized; none currently issued and outstanding
Non-mandatory redeemable series:
<S> <C> <C <C> <C> <C>
$1.46 series $ 0 $ 0 $ 2,675
Premium on $1.46 series 0 0 35,658
- ------------------------------------------------------------------------------
Total preference stock $ 0 $ 0 $ 38,333
==============================================================================
</TABLE>
<TABLE>
Dividends Declared per Share
<S> <C> <C> <C>
COMMON STOCK $1.715 $1.655 $1.595
PREFERRED STOCK:
4.25% series $4.253 $4.250 $4.250
4.78% series 4.785 4.780 4.780
7.27% series 7.270 7.270 7.270
7.75% series 5.707 0 0
8.00% series 8.000 8.000 1.337
8.25% series 8.250 5.278 0
8.88% series 2.220 8.880 8.880
PREFERENCE STOCK:
$1.46 series $ 0 $0.365 $1.460
Stated rate auction preference stock 0 0 6.900
</TABLE>
36
<PAGE> 38
<TABLE>
Indebtedness
<CAPTION>
December 31,
(dollars in thousands) 1993 1992
- -------------------------------------------------------------------------------
LONG-TERM DEBT:
First mortgage bonds:
Interest
Series Rate Maturity
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
I 4.750% 1995 $ 0 $ 25,000
J 6.125% 1997 0 40,000
K 6.875% 1998 0 50,000
L 9.000% 1999 0 50,000
M 9.375% 2000 0 60,000
N 8.125% 2001 0 75,000
S Variable 2002 25,000 25,000
Q 9.750% 2003 0 59,375
R 10.950% 2004 0 44,250
P 9.250% 2007 0 60,000
U 10.250% 2014 15,000 15,000
W 9.500% 2016 0 135,000
- ------------------------------------------------------------------------------
Total first mortgage bonds 40,000 638,625
Less: due within one year 0 6,800
- ------------------------------------------------------------------------------
Total first mortgage bonds, net $ 40,000 $ 631,825
==============================================================================
Sewage facility revenue bonds $ 36,300 $ 36,300
Less: funds held by trustee 3,803 12,052
- ------------------------------------------------------------------------------
Total sewage facility revenue bonds, net $ 32,497 $ 24,248
==============================================================================
Debentures:
8.875%, due 1995 $ 100,000 $100,000
5.125%, due 1996 100,000 0
5.700%, due 1997 100,000 0
5.950%, due 1998 100,000 0
6.800%, due 2000 65,000 0
6.050%, due 2000 100,000 0
6.800%, due 2003 150,000 0
9.875%, due 2020 100,000 100,000
9.375%, due 2021 125,000 125,000
8.250%, due 2022 60,000 60,000
7.800%, due 2023 200,000 0
- ------------------------------------------------------------------------------
Total debentures $1,200,000 $385,000
==============================================================================
Unsecured medium-term notes $ 0 $ 50,000
==============================================================================
SHORT-TERM DEBT:
Notes payable:
Bank loans $106,501 $ 162,500
Commercial paper 97,650 113,000
- ------------------------------------------------------------------------------
Total notes payable $204,151 $ 275,500
==============================================================================
</TABLE>
37
<PAGE> 39
<TABLE>
1. Common Stock
Since December 31, 1990, we issued the following shares of common stock:
<CAPTION>
Number Total Premium on
(in thousands) of Shares Par Value Common Stock
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance December 31, 1990 38,998 $194,993 $314,822
Dividend reinvestment plan 449 2,181 6,844
Change in par value of common
stock (a) 0 (157,727) 157,727
New issue (b) 2,600 2,600 57,174
- -----------------------------------------------------------------------------
Balance December 31, 1991 42,047 42,047 536,567
Dividend reinvestment plan 416 416 9,658
New issue (c) 2,300 2,300 55,971
- -----------------------------------------------------------------------------
Balance December 31, 1992 44,763 44,763 602,196
Dividend reinvestment plan (d) 366 366 10,457
- -----------------------------------------------------------------------------
Balance December 31, 1993 45,129 $ 45,129 $612,653
=============================================================================
</TABLE>
(a) In November 1991 our Articles of Organization were amended to increase
authorized common stock from 50 million to 100 million shares and reduce
the par value from $5 to $1 per common share.
(b) We used the net proceeds of the 1991 common stock issuance to retire $55
million of Series X, 11% first mortgage bonds.
(c) We used the net proceeds of the 1992 common stock issuance to reduce
short-term debt.
(d) At December 31, 1993, the remaining authorized common shares reserved
for future issuance under the Dividend Reinvestment and Common Stock
Purchase Plan were 815,170 shares.
2. Cumulative Non-Mandatory Redeemable Preferred and Preference Stock
In June 1992 we issued 400,000 shares of 8.25% cumulative non-mandatory
redeemable preferred stock at par. The stock is redeemable at $100 per share
plus accrued dividends beginning in June 1997. 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 $1.46 series cumulative non-mandatory redeemable preference stock.
In May 1993 we issued 400,000 shares of 7.75% cumulative non-mandatory
redeemable preferred stock at par. The stock is redeemable at $100 per share
plus accrued dividends beginning in May 1998. These shares were sold in the
form of 1.6 million depositary shares, each representing a one-fourth interest
in a share of the preferred stock. We used the proceeds of this issue to fully
retire the 8.88% series cumulative non-mandatory redeemable preferred stock.
3. Cumulative Mandatory Redeemable Preferred Stock
The 480,000 shares of our 7.27% sinking fund series cumulative preferred stock
are currently redeemable at our option at $104.36. The redemption price
declines annually each May to par value in May 2002. In May 1993 the stock
became subject to sinking fund requirements to retire 20,000 shares at $100 per
share plus accrued dividends each year through May 2002. In 1992 we purchased
20,000 shares at a discount on the open market which satisfied the mandatory
sinking fund requirement for May 1993. Beginning in 1993, we have the
non-cumulative option each May to redeem additional shares, not to exceed
20,000, for the sinking fund at $100 per share plus accrued dividends.
38
<PAGE> 40
We are not able to redeem any part of our 500,000 shares of $100 par value
8% series cumulative preferred stock prior to December 2001. The entire
series is subject to mandatory redemption in December 2001 at $100 per share,
plus accrued dividends.
4. Long-Term Debt
Substantially all our property, plant, equipment, materials and supplies are
subject to lien under the terms of our Indenture of Trust and First Mortgage
dated December 1, 1940, and its supplements. Currently only the outstanding
Series S and U first mortgage bonds are subject to the terms of the indenture.
The aggregate principal amounts of our first mortgage bonds, debentures, and
sewage facility revenue bonds (including sinking fund requirements) due in 1994
and 1995 are $0 and $100.6 million, respectively, and $101.6 million per year
in 1996 through 1998.
Our first mortgage bonds, Series S, adjustable rate due 2002, paid interest
at 9.2% per year for the period January 15, 1993 through January 14, 1994. The
rate is adjusted annually and is based upon the ten-year constant maturity
Treasury rate as published by the Federal Reserve Board. The interest rate for
the period January 15, 1994 through January 14, 1995 is 8.2%.
In September 1992 we issued $60 million of 8.25% debentures which mature in
September 2022. The debentures are redeemable at prices decreasing from
103.78% of par beginning in September 2002, to 100% of par beginning in
September 2012. We used the net proceeds from the sale to reduce short-term
debt. In October 1992 we redeemed the remaining balance of $45 million Series
X first mortgage bonds.
In February 1993 we issued $65 million of 6.8% debentures due in 2000. We
used the proceeds of this issue to reduce short-term debt. These debentures
are not redeemable prior to maturity.
In March 1993 we issued $650 million of debentures and used the proceeds to
retire ten of twelve outstanding series of first mortgage bonds and reduce
short-term debt. The debentures were issued in five separate series with
interest rates ranging from 5.125% to 7.8% and maturing between 1996 and 2023.
The 5 1/8% debentures due 1996, 5.70% due 1997, 5.95% due 1998 and 6.80% due
2003 are not redeemable prior to maturity. The 7.80% debentures due 2023 are
first redeemable in March 2003 at a redemption price of 103.73%. The
redemption price decreases annually each March to par value in March 2013.
There is no sinking fund requirement for any series of the debentures.
In August 1993 we issued $100 million of 6.05% debentures due in 2000. We
used the proceeds from this sale to reduce short-term debt. These debentures
are not redeemable prior to maturity and have no sinking fund requirements.
We redeemed $50 million of 9.65% medium-term notes in September 1992 and $50
million of 9.75% medium-term notes in September 1993.
5. Sewage Facility Revenue Bonds
In December 1991, Harbor Electric Energy Company (HEEC), a wholly-owned
subsidiary, issued $36.3 million of long-term sewage facility revenue bonds.
The bonds are tax-exempt, subject to annual mandatory sinking fund redemption
requirements and mature in the years 1995-2015. The weighted average interest
rate of the bonds is 7.3%. A portion of the proceeds from the bonds was used
to retire $21 million of short-term sewage facility revenue bonds at maturity.
The remainder of the proceeds, which is on deposit with the trustee, is being
used to finance the construction of HEEC's permanent substation located on Deer
Island (in Boston Harbor) and to
39
<PAGE> 41
fund an amount which must remain in reserve with the trustee. If HEEC should
have insufficient funds to pay certain costs on a timely basis or be unable to
meet certain net worth requirements, we would be required to make additional
capital contributions or loans to the subsidiary up to a maximum of $7 million.
6. 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>
(thousands of dollars) 1993 1992 1991
- ------------------------------------------------------------------------------
<S> <C> <C> <C>
Maximum short-term borrowings $320,000 $314,998 $324,400
Weighted average amount outstanding $220,149 $233,286 $221,481
Weighted average interest rates, excluding
commitment fees 3.4% 4.1% 6.4%
- ------------------------------------------------------------------------------
</TABLE>
NOTE G. 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 fund
The fair value of $70.1 million is based on quoted market prices of securities
held.
Cash and cash equivalents
The carrying amount of $8.8 million approximates fair value due to the
short-term nature of these securities.
Mandatory redeemable cumulative preferred stock, first mortgage bonds, sewage
facility revenue bonds and debentures
<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, 1993 are
as follows:
<CAPTION>
Carrying Fair
(in thousands) Amount Value
- ----------------------------------------------------------------------
<S> <C> <C>
Mandatory redeemable cumulative preferred $ 98,000 $ 105,935
stock
First mortgage bonds 40,000 44,132
Sewage facility revenue bonds 36,300 40,528
Debentures 1,200,000 1,237,924
- ----------------------------------------------------------------------
</TABLE>
NOTE H. COMMITMENTS AND CONTINGENCIES
1. Capital Commitments
At December 31, 1993, we had estimated contractual obligations for plant and
equipment of approximately $71 million.
40
<PAGE> 42
2. Lease Commitments
<TABLE>
We have leases for certain facilities and equipment. Our estimated minimum
rental commitments under both noncancelable leases and transmission agreements
for the years after 1993 are as follows:
<CAPTION>
(in thousands)
- ------------------------------------------------------------------------
<S> <C>
1994 $ 27,375
1995 23,878
1996 21,299
1997 19,217
1998 17,969
Years thereafter 139,474
- ------------------------------------------------------------------------
Total $249,212
========================================================================
</TABLE>
We will capitalize a portion of these lease rentals as part of plant
expenditures in the future. Our total expense for both lease rentals and
transmission agreements for 1993, 1992 and 1991 was $30 million, $30 million
and $33.5 million, respectively, net of capitalized expenses of $5 million, $5
million, and $4.8 million, respectively.
3. Hydro-Quebec
We have an approximately 11% equity ownership interest in two companies which
own and operate transmission facilities to import electricity from the
Hydro-Quebec system in Canada, which is included in our consolidated financial
statements. As an equity participant we are required to guarantee, in addition
to our own share, the total obligations of those participants who do not meet
certain credit criteria and are compensated accordingly. At December 31, 1993,
our portion of these guarantees was approximately $22 million.
4. Yankee Atomic Electric Company
In February 1992 the Board of Directors of Yankee Atomic Electric Company
(Yankee Atomic) decided to permanently discontinue power operation of the
Yankee Atomic nuclear generating station and, in time, decommission that
facility. We relied on Yankee Atomic for less than one percent of our system
capacity. We have a 9.5% stock investment of approximately $2 million in
Yankee Atomic.
In 1993 Yankee Atomic received approval from federal regulators to continue
to collect its investment and decommissioning costs through July 2000, the
period of the plant's operating license. The estimate of our share of Yankee
Atomic's investment and costs of decommissioning is approximately $33 million
as of December 31, 1993. This estimate is recorded on our consolidated balance
sheet as a power contract liability in deferred credits. An offsetting power
contract regulatory asset is included in deferred debits as we continue to
collect these costs from our customers in accordance with our 1992 settlement
agreement.
5. Nuclear Insurance
The federal Price-Anderson Act currently provides $9.4 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 $8.8 billion is provided by a retrospective assessment of up to
$75.5 million per incident levied on each of the 116 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 new commercial nuclear units are licensed and 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
41
<PAGE> 43
from any nuclear accident exceeds the maximum amount of financial protection,
each licensee can be assessed an additional five percent of the maximum
retrospective assessment.
We have purchased insurance from Nuclear Electric Insurance Limited
(NEIL) to cover some of the costs to purchase replacement power during a
prolonged accidental outage at Pilgrim Station and the cost of repair,
replacement, decontamination or decommissioning of our utility property
resulting from covered incidents at Pilgrim Station. Our maximum potential
total assessment for losses which occur during current policy years is
approximately $14.6 million under both the replacement power and excess
property damage, decontamination and decommissioning policies. All companies
insured with NEIL are subject to retroactive assessments if losses are in
excess of the total funds available to NEIL. While assessments may also be
made for losses in certain prior policy years, we are not aware of any losses
in those years which we believe are likely to result in an assessment.
6. Litigation
In March 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 is vigorously
defending this case. Based on the information presently available we do not
expect that this litigation or certain other legal matters in which we are
currently involved will have a material impact on our financial condition.
However, an unfavorable decision ordered against us could have a material
impact on quarterly earnings.
7. Hazardous Waste
State regulations revised in 1993 require that properties where releases of
hazardous materials occurred in the past be further cleaned up according to a
timetable developed by the Massachusetts Department of Environmental
Protection. We are currently evaluating the potential costs associated with
the cleanup of sites where we have been identified as the owner or operator.
There are uncertainties associated with these potential 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 certain other
multi-party hazardous waste sites in Massachusetts and other states. At the
majority of these other sites we are one of many potentially responsible
parties and our alleged share of the responsibility is a small percentage. We
do not expect any of our potential cleanup liabilities to have a material
impact on financial condition, although provisions for cleanup costs could have
a material impact on quarterly earnings.
NOTE I. PENSIONS, OTHER POSTRETIREMENT AND POSTEMPLOYMENT BENEFITS
1. Pensions
We have a noncontributory funded retirement plan, with certain features that
allow voluntary contributions. Benefits are based upon an employee's years of
service and compensation during the last years of employment. Our funding
policy is to contribute each year an amount that is not less than the minimum
required contribution under federal law or greater than the maximum tax
deductible amount. Plan assets are primarily equities, bonds, insurance
contracts and real estate.
42
<PAGE> 44
<TABLE>
Net pension cost included the following components:
<CAPTION>
(in thousands) 1993 1992 1991
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Current service cost - benefits earned $11,734 $10,683 $ 8,567
Interest cost on projected benefit
obligation 33,181 32,287 29,817
Actual return on plan assets (44,470) (23,281) (60,873)
Net amortization and deferral 8,528 (13,549) 26,811
- -----------------------------------------------------------------------------
Net pension cost(a) $ 8,973 $ 6,140 $ 4,322
=============================================================================
<FN>
(a) In accordance with an agreement with our state regulators, we deferred our
net pension costs in excess of the annual funding amounts and will recover
these costs from customers over time. Net pension costs recorded as expense
were approximately $5 million in 1993 and $0 in 1992 and 1991.
</TABLE>
<TABLE>
We used the following assumptions for calculating pension cost:
<CAPTION>
1993 1992 1991
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
Discount rate 8.25% 8.25% 9.00%
Expected long-term rate of return on
assets 10.00% 10.00% 10.00%
Compensation increase rate 4.50% 4.50% 4.50%
- -----------------------------------------------------------------------------
</TABLE>
We changed our discount rate assumption to 7.0% for calculating pension cost
effective January 1994.
<TABLE>
The plan's funded status at December 31, 1993 and 1992 was as follows:
<CAPTION>
(in thousands) 1993 1992
- -----------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including
vested benefits of $384,150 and $322,836 $400,895 $339,035
=============================================================================
Plan assets at fair value $394,233 $392,407
Projected obligation for service rendered
to date (509,661) (418,312)
- -----------------------------------------------------------------------------
Projected benefit obligation in excess of
plan assets (115,428) (25,905)
Unrecognized prior service cost 8,139 8,817
Unrecognized net (gain) loss 75,352 (6,810)
Unrecognized net obligation 9,932 10,866
- -----------------------------------------------------------------------------
Net pension liability $(22,005) $(13,032)
=============================================================================
</TABLE>
<TABLE>
We used the following assumptions for calculating the plan's year-end funded
status:
<CAPTION>
1993 1992
<S> <C> <C>
- ---------------------------------------------------------------------------
Discount rate 7.00% 8.25%
Compensation increase rate 4.50% 4.50%
- ---------------------------------------------------------------------------
</TABLE>
2. Other Postretirement Benefits
In addition to pension benefits, we also currently provide health care and
other benefits to our retired employees who meet certain age and years of
service eligibility requirements. Effective January 1993 we adopted Statement
of Financial Accounting Standards No. 106, Employer's Accounting for
Postretirement Benefits Other Than Pensions (SFAS 106). This requires us to
record a liability during the working years of employees for the expected costs
of providing their postretirement benefits other than pensions (PBOPs). Prior
to 1993 our
43
<PAGE> 45
policy was to record the cost of PBOPs when paid. Our transition obligation on
January 1, 1993 was approximately $183 million, which we elected to recognize
over 20 years as permitted by SFAS 106. Our total cost of PBOPs under SFAS 106
in 1993 was approximately $28 million, an increase of approximately $18 million
over costs incurred under our prior method of accounting for PBOPs. Our 1992
settlement agreement provides us with a phase-in of a portion of the increased
costs and allows us to defer the additional costs in excess of the phase-in
amounts to the extent that we fund an external trust. In December 1993 we
deposited $18 million on a tax deductible basis into external trusts for the
payment of PBOPs. Accordingly, in 1993 we recorded an expense of approximately
$16 million, reflecting the amount of cost recovery from customers, and
deferred approximately $12 million for future recovery. We capitalized
approximately 19% of these costs.
<TABLE>
Postretirement benefits cost consisted of the following in 1993:
<CAPTION>
(in thousands)
- ------------------------------------------------------------------------------
<S> <C>
Current service cost - benefits earned $ 4,351
Interest cost on transition obligation 14,286
Amortization of transition obligation 9,151
- ------------------------------------------------------------------------------
Net postretirement benefits cost $27,788
==============================================================================
</TABLE>
We used an 8.0% weighted average discount rate and 4.5% rate of
compensation increase assumption for calculating the transition obligation and
the 1993 postretirement benefits cost. Our expected long-term rate of return
on assets is 9.0%. We also assumed a 12.5% health care cost trend rate.
Effective January 1, 1994 we changed the discount and health care cost trend
rates to 7.0% and 9.0%, respectively, in order to more accurately estimate our
future benefit payments. The health care cost trend rate is assumed to
decrease by one percent each year to 5% in 1998 and years thereafter. Changes
in the health care cost trend rate will affect our cost and obligation amounts.
For example, a one percent increase in the rate would increase the total
service and interest costs in 1993 by approximately 16% and would increase the
accumulated obligation at December 31, 1993 by approximately 13%.
<TABLE>
The postretirement benefits program's funded status at December 31, 1993
was as follows:
<CAPTION>
(in thousands)
<S> <C> <C>
- -------------------------------------------------------------------------------------
Trust assets at fair value $ 18,016
Accumulated obligation for service rendered to date from:
Retirees $(75,216)
Active employees eligible to retire (64,880)
Active employees not eligible to retire (73,285) (213,381)
- -------------------------------------------------------------------------------------
Accumulated benefit obligation in excess of trust assets (195,365)
assets
Unrecognized loss 21,497
Unrecognized net obligation 173,868
- -------------------------------------------------------------------------------------
Net postretirement benefits liability $ 0
=====================================================================================
</TABLE>
The trust assets consist of money market funds at December 31, 1993.
3. Postemployment Benefits
Statement of Financial Accounting Standards No. 112, Employers' Accounting for
Postemployment Benefits, will be effective for the first quarter of 1994. This
statement will require us to record a liability computed on an actuarial basis
for the estimated cost of providing postemployment benefits. Postemployment
benefits provided to former or inactive employees, their beneficiaries and
covered dependents include salary continuation, severance benefits,
disability-related benefits (including workers' compensation), job training and
counseling and continuation of health care and life insurance coverage. We
currently recognize
44
<PAGE> 46
the cost of these benefits primarily as claims are paid. We do not
anticipate a material effect on net income from adopting this statement.
NOTE J. NEW ACCOUNTING PRONOUNCEMENT
We will adopt Statement of Financial Accounting Standards No. 115, Accounting
for Certain Investments in Debt and Equity Securities, in the first quarter of
1994. This statement may require us to classify the investments in our nuclear
decommissioning fund on our consolidated balance sheet based on how long we
intend to hold the individual securities. These investments may be classified
as "available for sale" and we may also be required to report any unrealized
gains and losses on the investments as a separate component of shareholders'
equity. We do not expect the adoption of this statement to have a material
effect on shareholders' equity.
NOTE K. LONG-TERM POWER CONTRACTS
1. Long-Term Contracts for the Purchase of Electricity
We purchase electric power under several long-term contracts for which we pay a
share of the generating unit's capital and fixed operating costs through the
contract expiration date. The total cost of these contracts is included in
purchased power expense in our consolidated income statements. Information
relating to these contracts as of December 31, 1993 is as follows:
45
<PAGE> 47
<TABLE>
<CAPTION>
proportionate share (in thousands)
Units of ---------------------------------------
Capacity 1993 1993 Interest Debt
Contract Purchased(a) Minimum Portion of Outstanding
Expiration ------------ Debt Minimum Through Cont.
Contract Date % MW Service Debt Service Exp. Date
- --------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Canal Unit 1 2001 25.0 142 $ 781 $ 314 $ 2,118
Mass. Bay Trans-
portation Authority 2005 100.0 35 (b) (b) (b)
Connecticut Yankee
Atomic 2007 9.5 56 2,579 1,670 15,898
Ocean State Power -
Unit 1 2010 23.5 65 5,323 3,948 22,747
Ocean State Power -
Unit 2 2011 23.5 65 4,422 3,376 19,401
Northeast Energy
Associates (c) (c) 219 (c) (c) (c)
L'Energia 2013 73.0 64 (d) (d) (d)
- ---------------------------------------------------------------------------------------
Total 646 $13,105 $9,308 $60,164
=======================================================================================
<FN>
(a) The Northeast Energy Associates contract represents 6.4% of our total
system generation capability. The remaining units listed above represent
12.6% 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
33.6MW) plus incremental operating, maintenance and fuel costs. The total
charges for this contract in 1993 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 1993 were approximately $116 million.
(d) The L'Energia contract started in March 1993. We purchase 73% of the
energy output of this unit. We pay for this energy based on a price per kWh
actually received. The total charges under this contract for 1993 were
approximately $15 million.
</TABLE>
Our total fixed and variable costs for these contracts in 1993, 1992 and
1991 were approximately $225 million, $217 million and $154 million,
respectively. Our minimum fixed payments under these contracts for the years
after 1993 are as follows:
<TABLE>
<CAPTION>
(in thousands)
- ----------------------------------------------------------------------------
<S> <C>
1994 $ 69,432
1995 72,418
1996 75,376
1997 71,147
1998 72,429
Years thereafter 725,236
- -----------------------------------------------------------------------------
Total $1,086,038
=============================================================================
Total present value $ 558,600
=============================================================================
</TABLE>
46
<PAGE> 48
2. Long-Term Power Sales
<TABLE>
In addition to our power sales to four wholesale customers, we sell a
percentage of Pilgrim Station's output to other utilities under long-term
contracts. Information relating to these contracts is as follows:
<CAPTION>
Contract Units of Capacity Sold
Expiration -----------------------
Contract Customer Date % MW
- ---------------------------------------------------------------------
<S> <C> <C> <C>
Commonwealth Electric Company 2012 11.0 73.7
Montaup Electric Company 2012 11.0 73.7
Various municipalities 2000(a) 3.7 25.0
- ---------------------------------------------------------------------
Total 25.7 172.4
=====================================================================
<FN>
(a) Subject to certain adjustments.
</TABLE>
Under these contracts, the utilities 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.
<TABLE>
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
<CAPTION>
Balance Earnings
Available Per Share of
Operating Operating Net for Common Common
Revenues Income Income Stock Stock (a)
- -----------------------------------------------------------------------------
1993
<S> <C> <C> <C> <C> <C>
First quarter $354,752 $ 41,721 $15,452 $11,377 $0.25
Second quarter 346,074 49,282 22,829 19,125 0.43
Third quarter 436,024 96,319 70,015 66,052 1.47
Fourth quarter 345,403 37,997 9,922 5,959 0.13
1992
First quarter $343,505 $ 41,930 $13,816 $ 9,553 $0.23
Second quarter 300,566 32,629 4,953 852 0.02
Third quarter 408,255 100,890 73,698 69,593 1.60
Fourth quarter 359,427 45,451 14,831 10,750 0.24
<FN>
(a) Based upon the weighted average number of common shares outstanding during
the quarter.
</TABLE>
Electricity sales and revenues are seasonal in nature, with both being lower
in the spring and fall seasons. Quarterly earnings for 1993 reflect a change
in the months for which certain customers were billed at higher rates as
mandated by the DPU. These customers were billed at these higher rates in July
through October in 1992 and in June through September in 1993. The change in
billing increased second quarter earnings and reduced fourth quarter earnings
by approximately $0.23 per share in 1993.
47
<PAGE> 49
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------- ---------------------------------------------------------------
Financial Disclosure
--------------------
None.
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
17, 1994 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 17, 1994, incorporated
herein by reference.
For information relating to the business experience during the past five
years of each person who is an executive officer, see Executive Officers of the
Registrant in this Form 10-K.
(f) Involvement in Certain Legal Proceedings
- ---------------------------------------------
Not applicable.
(g) Promoters and Control Persons
- ----------------------------------
Not applicable.
Item 11. Executive Compensation
- --------------------------------
See "Director and Executive Compensation" on pages 5 through 11 of the
definitive Proxy Statement dated March 17, 1994, incorporated herein by
reference.
48
<PAGE> 50
Item 12. Security Ownership of Certain Beneficial Owners and Management
- ------------------------------------------------------------------------
(a) Security Ownership of Certain Beneficial Owners
- ----------------------------------------------------
To the knowledge of management, no person owns beneficially more than five
percent of the outstanding voting securities of the Company.
(b) Security Ownership of Management
- -------------------------------------
See "Stock Ownership by Directors and Executive Officers" on pages 4
through 5 of the definitive Proxy Statement dated March 17, 1994, incorporated
herein by reference.
(c) Changes in Control
- -----------------------
Not applicable.
Item 13. Certain Relationships and Related Transactions
- --------------------------------------------------------
Not applicable.
49
<PAGE> 51
Part IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
<TABLE>
<CAPTION>
(a) Exhibits and Consolidated Financial Statement Schedules Page
- ----------------------------------------------------------- ----
<S> <C>
Consolidated Statements of Income for each of the three
years in the period ended December 31, 1993 28
Consolidated Statements of Retained Earnings for each of
the three years in the period ended December 31, 1993 28
Consolidated Balance Sheets as of December 31, 1993 and 1992 29
Consolidated Statements of Cash Flows for each of the three
years in the period ended December 31, 1993 30
Notes to Consolidated Financial Statements 31
Selected Consolidated Quarterly Financial Data (Unaudited) 47
Report of Independent Accountants 64
Schedules for years ended December 31, 1993, 1992 and 1991:
V - Property, Plant and Equipment S-1
VI - Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment S-4
VII - Guarantees of Securities of Other Issuers S-7
IX - Short-Term Borrowings S-8
X - Supplementary Income Statement Information S-9
</TABLE>
All other schedules are omitted since they are not required, not
applicable, or contain only information which is otherwise provided in the
financial statements or notes in Item 8.
50
<PAGE> 52
<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 2(a)4 2-58587
3.1.1 Amendment to Restated Articles of 2.4 2-64975
Organization, filed May 5, 1977
3.1.2 Amendment to Restated Articles of 3.1.2 1-2301
Organization, filed May 26, 1978 Form 10-K
for the
year ended
December 31, 1991
3.1.3 Amendment to Restated Articles of 3.1.3 1-2301
Organization, filed May 6, 1980 Form 10-K
for the
year ended
December 31, 1991
3.1.4 Amendment to Restated Articles of 3.1 1-2301
Organization, filed May 4, 1983 Form 10-Q
for the
quarter ended
March 31, 1983
3.1.5 Amendment to Restated Articles of 3.1 1-2301
Organization, filed April 28, 1986 Form 10-Q
for the
quarter ended
March 31, 1986
3.1.6 Amendment to Restated Articles of 3.5 1-2301
Organization, filed August 27, 1986 Form 10-K
for the
year ended
December 31, 1986
3.1.7 Amendment to Restated Articles of 3.1 1-2301
Organization, filed February 19, 1987 Form 10-Q
for the
quarter ended
March 31, 1987
3.1.8 Certificate of Vote of Directors 4.2 1-2301
Establishing a Series of a Class Form 10-Q
of Stock, filed March 9, 1987 for the
quarter ended
September 30, 1988
</TABLE>
51
<PAGE> 53
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
3.1.9 Amendment to Restated Articles of 3.1.8 1-2301
Form 10-K
Organization, filed May 5, 1987 for the
year ended
December 31, 1987
3.1.10 Amendment to Restated Articles of 4.1 33-24271
Organization, filed May 27, 1988 Registration
Statement dated
September 22, 1988
3.1.11 Certificate of Vote of Directors 4.3 1-2301
Establishing a Series of a Class Form 10-Q
of Stock, filed October 4, 1988 for the
quarter ended
September 30, 1988
3.1.12 Amendment to Restated Articles of 3.1.12 1-2301
Organization, filed November 7, 1991 Form 10-K
for the
year ended
December 31, 1991
3.1.13 Certificate of Vote of Directors 3.1.13 1-2301
Establishing a Series of a Class Form 10-K
of Stock, filed November 26, 1991 for the
year ended
December 31, 1991
3.1.14 Certificate of Vote of Directors 4.1 1-2301
Establishing a Series of a Class Form 10-Q
of Stock, filed June 8, 1992 for the
quarter ended
June 30, 1992
3.1.15 Certificate of Vote of Directors 3.1 1-2301
Establishing a Series of a Class Form 10-Q
of Stock, filed April 30, 1993 for the
quarter ended
June 30, 1993
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
</TABLE>
52
<PAGE> 54
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 4 Instruments Defining the Rights of
- --------- ----------------------------------
Security Holders, Including Indentures
--------------------------------------
Incorporated herein by reference:
<S> <C> <C> <C>
4.1 Indenture of Trust and First Mortgage B-2 2-4564
dated December 1, 1940 with
State Street Trust Company
4.1.1 Tenth supplemental indenture dated 7.5 2-8349
April 1, 1950
4.1.2 Twelfth supplemental indenture dated 4.2 2-80748
November 15, 1951
4.1.3 Twenty-fourth supplemental indenture 4.1.3 1-2301
dated June 1, 1962 Form 10-K
for the
year ended
December 31, 1990
4.1.4 Twenty-seventh supplemental indenture 4.1.4 1-2301
dated November 1, 1965 Form 10-K
for the
year ended
December 31, 1990
4.1.5 Twenty-ninth supplemental indenture 4.1.5 1-2301
dated June 1, 1967 Form 10-K
for the
year ended
December 31, 1990
4.1.6 Thirtieth supplemental indenture 4.1.6 1-2301
dated November 1, 1968 Form 10-K
for the
year ended
December 31, 1990
4.1.7 Thirty-first supplemental indenture 4.1.7 1-2301
dated December 1, 1969 Form 10-K
for the
year ended
December 31, 1990
4.1.8 Thirty-second supplemental indenture 4.1.8 1-2301
dated July 1, 1970 Form 10-K
for the
year ended
December 31, 1990
</TABLE>
53
<PAGE> 55
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
4.1.9 Thirty-third supplemental indenture 4.1.9 1-2301
dated May 15, 1971 Form 10-K
for the
year ended
December 31, 1990
4.1.10 Thirty-fifth supplemental indenture 4.1.10 1-2301
dated April 15, 1977 Form 10-K
for the
year ended
December 31, 1989
4.1.11 Thirty-sixth supplemental indenture 4.1.11 1-2301
dated December 15, 1978 Form 10-K
for the
year ended
December 31, 1989
4.1.12 Thirty-seventh supplemental indenture 4.1.12 1-2301
dated October 31, 1979 Form 10-K
for the
year ended
December 31, 1989
4.1.13 Thirty-eighth supplemental indenture 4.1.13 1-2301
dated January 1, 1982 Form 10-K
for the
year ended
December 31, 1991
4.1.14 Thirty-ninth supplemental indenture 4.1 1-2301
dated April 15, 1983 Form 10-Q
for the
quarter ended
March 31, 1983
4.1.15 Fortieth supplemental indenture 4.1 1-2301
dated April 1, 1984 Form 10-Q
for the
quarter ended
March 31, 1984
4.1.16 Forty-first supplemental indenture 4.1 1-2301
dated April 1, 1985 Form 10-Q
for the
quarter ended
March 31, 1985
</TABLE>
54
<PAGE> 56
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
4.1.17 Forty-second supplemental indenture 4.1 1-2301
dated July 15, 1986 Form 10-Q
for the
quarter ended
June 30, 1986
4.1.18 Forty-third supplemental indenture 4.1 1-2301
dated September 15, 1987 Form 10-Q
for the
quarter ended
September 30, 1987
4.1.19 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
4.1.20 First Supplemental Indenture 4.1 1-2301
dated June 1, 1990 to Form 8-K
Indenture dated September 1, dated
1988 with Bank of Montreal Trust June 28, 1990
Company - 9 7/8% debentures due
June 1, 2020
4.1.21 Votes of the Pricing Committee of the 4.1 1-2301
Board of Directors of Boston Edison Form 10-Q
Company taken December 11, 1990 for the
re 8 7/8% debentures due quarter ended
December 15, 1995 March 31, 1991
4.1.22 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, 1991
Shawmut Bank, N.A., as Trustee, dated
November 1, 1991
4.1.23 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 5, 1991 re for the
9 3/8% debentures due August 15, 2021 year ended
December 31, 1991
4.1.24 Revolving Credit Agreement dated 4.1.24 1-2301
February 12, 1993 Form 10-K
for the
year ended
December 31, 1992
</TABLE>
55
<PAGE> 57
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
4.1.25 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
4.1.26 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
6.8% debentures due February 1, 2000 year ended
December 31, 1992
4.1.27 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, 1992
5.95% debentures due March 15, 1998,
6.80% debentures due March 15, 2003,
7.80% debentures due March 15, 2023
Filed herewith:
4.1.28 Votes of the Pricing Committee of the -- --
Board of Directors of Boston Edison
Company taken August 18, 1993 re
6.05% debentures due August 15, 2000
</TABLE>
<TABLE>
<CAPTION>
Exhibit 10 Material Contracts
- ----------- ------------------
Executive Compensation:
Incorporated herein by reference:
<S> <C> <C> <C>
10.1 Key Executive Benefit Plan 10.13 1-2301
(1982 Form of Agreement) Form 10-K
for the
year ended
December 31, 1992
10.1.1 Amendment to Key Executive Benefit 10.4.1 1-2301
Plan dated February 1, 1986 Form 10-K
for the
year ended
December 31, 1985
10.1.2 Key Executive Benefit Plan 10.1 1-2301
Standard Form of Agreement, for the
May 1986 quarter ended
June 30, 1986
</TABLE>
56
<PAGE> 58
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
10.1.3 Key Executive Benefit Plan 10.3.1 1-2301
Standard Form of Agreement, May Form 10-K
1986, with modifications, applicable for the
to Bernard W. Reznicek, George W. year ended
Davis and Thomas J. May 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 Performance Share Plan 10.1 1-2301
Form 10-Q
for the
quarter ended
September 30, 1991
10.4 1991 Director Stock Plan 10.1 1-2301
Form 10-Q
for the
quarter ended
March 31, 1991
10.5 Boston Edison Company Deferred 10.11 1-2301
Fee Plan dated January 1, 1990 Form 10-K
for the
year ended
December 31, 1992
10.6 Boston Edison Company Deferred 10.12 1-2301
Compensation Plan dated Form 10-K
January 1, 1990 for the
year ended
December 31, 1992
10.7 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
10.8 Description of Supplemental 10.5 1-2301
Fee Arrangement for Certain Form 10-K
Directors for the
year ended
December 31, 1983
Filed herewith:
10.8.1 Directors Retirement Benefit -- --
(1993 Plan)
</TABLE>
57
<PAGE> 59
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 18 Letter re Change in Accounting Principle
- ---------- ----------------------------------------
Incorporated herein by reference:
<S> <C> <C> <C>
18.1 Letter of Independent Certified 18.1 1-2301
Public Accountants Form 10-Q
for the
quarter ended
March 31, 1990
</TABLE>
<TABLE>
<CAPTION>
Exhibit 21 Subsidiaries of the Registrant
- ---------- ------------------------------
<S> <C>
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.
</TABLE>
58
<PAGE> 60
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
Exhibit 23 Consent of Independent Accountants
- ---------- ----------------------------------
Filed herewith:
<S> <C>
23.1 Consent of Independent Accountants
to incorporate, by reference, their
opinion included with this Form
10-K, in the Form S-3 Registration
Statements filed by the Company on
September 14, 1990 (File No.
33-36824), February 3, 1993 (File
No. 33-57840) and in the Form S-8
Registration Statements filed by
the Company on October 10, 1985
(File No. 33-00810) July 28, 1986
(File No. 33-7558), December 31,
1990 (File No. 33-38434), June 5,
1992 (33-48424 and 33-48425) and
March 17, 1993 (33-59662 and
33-59682).
</TABLE>
<TABLE>
<CAPTION>
Exhibit 99 Additional Exhibits
- ---------- -------------------
Incorporated herein by reference:
<S> <C> <C> <C>
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, 1989
Light Department of the Town of
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, 1989
21, 1989
99.4 Settlement Agreement Between Boston 28.2 1-2301
Edison Company and City of Holyoke Form 10-Q
Gas and Electric Department et. al., for the
dated April 26, 1990 quarter ended
March 31, 1990
</TABLE>
59
<PAGE> 61
<TABLE>
<CAPTION>
Exhibit SEC Docket
------- ----------
<S> <C> <C> <C>
99.5 Information required by SEC Form - 1-2301
11-K for certain Company employee Form 8
benefit plans for the years ended Amendments to
December 31, 1992, 1991 and 1990 Form 10-K for the
years ended
December 31, 1992,
1991 and 1990 dated June 29, 1993,
June 26, 1992 and June 28, 1991,
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>
60
<PAGE> 62
(b) Reports on Form 8-K
- ------------------------
A Form 8-K dated October 28, 1993 was filed with the Securities and
Exchange Commission by the Company. This report announced the Company's
earnings for the three and twelve months ended September 30, 1993.
A Form 8-K dated January 27, 1994 was filed with the Securities and
Exchange Commission by the Company. This report contained a press release
announcing the Company's earnings for the twelve and three months ended
December 31, 1993.
61
<PAGE> 63
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
BOSTON EDISON COMPANY
By /s/ Charles E. Peters, Jr.
-------------------------------
Charles E. Peters, Jr.
Senior Vice President - Finance
(Principal Financial Officer)
Date: March 24, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934
this report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on the 24th day of March 1994.
<TABLE>
<S> <C>
/s/ Bernard W. Reznicek
- ------------------------------- Chairman of the Board and Chief Executive
Bernard W. Reznicek Officer
/s/ Thomas J. May
- ------------------------------- President and Chief Operating Officer
Thomas J. May and Director
/s/ George W. Davis
- ------------------------------- Executive Vice President and Director
George W. Davis
/s/ Robert J. Weafer, Jr.
- ------------------------------- Vice President, Controller and
Robert J. Weafer, Jr. Chief Accounting Officer
/s/ William F. Connell
- ------------------------------- Director
William F. Connell
/s/ Gary L. Countryman
- ------------------------------- Director
Gary L. Countryman
- ------------------------------- Director
Thomas G. Dignan, Jr.
</TABLE>
62
<PAGE> 64
<TABLE>
<S> <C>
/s/ Charles K. Gifford
- ------------------------------- Director
Charles K. Gifford
/s/ Nelson S. Gifford
- ------------------------------- Director
Nelson S. Gifford
/s/ Kenneth I. Guscott
- ------------------------------- Director
Kenneth I. Guscott
/s/ Matina S. Horner
- ------------------------------- Director
Matina S. Horner
/s/ Sherry H. Penney
- ------------------------------- Director
Sherry H. Penney
/s/ Herbert Roth, Jr.
- ------------------------------- Director
Herbert Roth, Jr.
- ------------------------------- Director
Stephen J. Sweeney
/s/ Paul E. Tsongas
- ------------------------------- Director
Paul E. Tsongas
/s/ Charles A. Zraket
- ------------------------------- Director
Charles A. Zraket
</TABLE>
63
<PAGE> 65
REPORT OF INDEPENDENT ACCOUNTANTS
To the Stockholders and Directors of Boston Edison Company:
We have audited the consolidated financial statements and the financial
statement schedules of Boston Edison Company and subsidiaries (the Company)
listed in Item 14(a) of this Form 10-K. These consolidated financial
statements and financial statement schedules are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements and financial statement schedules 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, 1993 and 1992, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
In addition, in our opinion, the consolidated financial statement schedules
referred to above, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly, in all material
respects, the information required to be included therein.
COOPERS & LYBRAND
Boston, Massachusetts
January 25, 1994
64
<PAGE> 66
<TABLE>
Boston Edison Company Schedule V
Property, Plant and Equipment
December 31, 1993
(in thousands)
<CAPTION>
Column A Column F
- ------------------------------ ----------
Balance at
end
Classification of period
- ------------------------------ ----------
<S> <C>
Electric plant:
Land and rights of way $ 38,944
Generating station and substation
buildings and misc. structures 472,789
Electric generating equipment 1,622,664
Transmission, distribution, street
lighting and other utilization equipment 1,720,798
Capitalized DSM 48,625
----------
Total electric plant 3,903,820
Nuclear fuel 273,867
Non-utility property 956
Construction work in progress 144,835
Total $4,323,478
==========
<FN>
(1) The information required in columns B, C, D and E is omitted as
neither the total additions nor the total retirements during the
year exceed 10% of the balance at the end of 1993. Total additions
and retirements were $252,770 and $34,147, respectively.
(2) Electric plant was depreciated on a straight-line basis at various
rates ranging from 1.80% to 4.03% in 1993. For further information
relating to the Company's policies regarding depreciation and
amortization, see Note A included in Item 8.
(3) Approximately $92,000 of additions in 1993 relate to various
modifications made to the Company's transmission and distribution
systems, approximately $73,000 represent an increase in generating
equipment, approximately $37 million represent capitalized DSM and
the remainder includes additions to generating station and other
plant.
</TABLE>
S-1
<PAGE> 67
<TABLE>
Boston Edison Company Schedule V
Property, Plant and Equipment
December 31, 1992
(in thousands)
<CAPTION>
Column A Column F
- ------------------------------ ----------
Balance at
end
Classification of period
- ------------------------------ ----------
<S> <C>
Electric plant:
Land and rights of way $ 38,488
Generating station and substation
buildings and misc. structures 427,780
Electric generating equipment 1,484,509
Transmission, distribution, street
lighting and other utilization equipment 1,666,525
Capitalized DSM 11,469
----------
Total electric plant 3,628,771
Nuclear fuel 270,420
Non-utility property 956
Construction work in progress 182,458
----------
Total $4,082,605
==========
<FN>
(1) The information required in columns B, C, D and E is omitted as
neither the total additions nor the total retirements during the
year exceed 10% of the balance at the end of 1992. Total additions
and retirements were $244,215 and $34,036, respectively.
(2) Electric plant was depreciated on a straight-line basis at various
rates ranging from 2.67% to 4.29% in 1992. For further information
relating to the Company's policies regarding depreciation and
amortization, see Note A included in Item 8.
(3) Approximately $95,000 of additions in 1992 relate to various
modifications made to the Company's transmission and distribution
systems, approximately $78,000 represent an increase in generating
equipment, approximately $31,000 represent increases in nuclear
fuel and the remainder includes additions to generating station
and other plant.
</TABLE>
S-2
<PAGE> 68
<TABLE>
Boston Edison Company Schedule V
Property, Plant and Equipment
December 31, 1991
(in thousands)
<CAPTION>
Column A Column F
- ----------------------------- ----------
Balance at
end
Classification of period
- ----------------------------- ----------
<S> <C>
Electric plant:
Land and rights of way $ 38,495
Generating station and substation
buildings and misc. structures 408,249
Electric generating equipment 1,475,395
Transmission, distribution, street
lighting and other utilization equipment 1,609,912
----------
Total electric plant 3,532,051
Nuclear fuel 256,199
Non-utility property 956
Construction work in progress 99,870
----------
Total $3,889,076
==========
<FN>
(1) The information required in columns B, C, D and E is omitted as
neither the total additions nor the total retirements during the
year exceed 10% of the balance at the end of 1991. Total additions
and retirements were $210,885 and $30,333, respectively.
(2) Electric plant was depreciated on a straight-line basis at various
rates ranging from 2.84% to 4.59% in 1991. For further information
relating to the Company's policies regarding depreciation and
amortization, see Note A included in Item 8.
(3) Approximately $87,000 of additions in 1991 relate to various
modifications made to the Company's transmission and distribution
systems, approximately $99,000 represent an increase in generating
equipment and the remainder includes additions to generating station
and other plant.
</TABLE>
S-3
<PAGE> 69
<TABLE>
Boston Edison Company Schedule VI
Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
1993
(in thousands)
<CAPTION>
- ------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
- ------------------------------------------------------------------------------------------
Additions
Balance at Charged to Balance
beginning Costs and Other at end
Description of period Expenses Retirements Changes of period
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Depreciation reserve:
Electric plant:
Production-fossil $ 275,749 $ 25,981 $17,619 $ 182 $ 284,293
-nuclear 352,997 43,184(A) 2,883 0 393,298
-other 18,884 1,089 579 100 19,494
--------------------------------------------------------------------
Total production 647,630 70,254 21,081 282 697,085
Transmission 129,710 6,627 289 46 136,094
Distribution 339,153 29,727 17,863 2,428 353,445
General 58,490 15,584(B) 12,608 65 61,531
Capitalized DSM 0 6,968 0 0 6,968
Harbor Electric
Energy Company 2,311 925 0 0 3,236
--------------------------------------------------------------------
Total electric 1,177,294 130,085 51,841 2,821(D) 1,258,359
Accumulated
amortization
of nuclear
fuel (F) 201,978 21,815 0 (3,316)(E) 220,477
--------------------------------------------------------------------
Total $1,379,272 $151,900 $51,841(C) $ (495) $1,478,836
====================================================================
<FN>
(A) Excludes $12,865 of nuclear decommissioning costs.
(B) Includes $9,237 of amortization of leasehold improvements, computer software and load management program costs.
(C) Includes $17,694 of removal costs.
(D) Includes salvage value of property retired of $2,568 and FERC audit adjustments from audit report covering the period
1/1/87 - 12/31/90 of $253.
(E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal.
(F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial
statements included in Item 8.
</TABLE>
S-4
<PAGE> 70
<TABLE>
Boston Edison Company Schedule VI
Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
1992
(in thousands)
<CAPTION>
- ---------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
- --------------------------------------------------------------------------------------
Additions
Balance at Charged to Balance
beginning Costs and Other at end
Description of period Expenses Retirements Changes of period
- --------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Depreciation reserve:
Electric plant:
Production-fossil $ 268,744 $ 26,106 $19,141 $ 40 $ 275,749
-nuclear 313,870 39,948(A) 1,209 388 352,997
-other 18,499 1,713 1,978 650 18,884
------------------------------------------------------------------
Total production 601,113 67,767 22,328 1,078 647,630
Transmission 120,533 9,770 628 35 129,710
Distribution 323,178 34,362 19,919 1,532 339,153
General 51,795 10,416(B) 3,723 2 58,490
Harbor Electric
Energy Company 1,372 939 0 0 2,311
------------------------------------------------------------------
Total electric 1,097,991 123,254 46,598 2,647(D) 1,177,294
Accumulated
amortization
of nuclear
fuel (F) 180,137 25,473 0 (3,632)(E) 201,978
------------------------------------------------------------------
Total $1,278,128 $148,727 $46,598(C) $ (985) $1,379,272
==================================================================
<FN>
(A) Excludes $5,575 of nuclear decommissioning costs.
(B) Includes $5,976 of amortization of leasehold improvements, computer software and load management program costs.
(C) Includes $12,562 of removal costs.
(D) Represents salvage value of property retired.
(E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal.
(F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial
statements included in Item 8.
</TABLE>
S-5
<PAGE> 71
<TABLE>
Boston Edison Company Schedule VI
Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
1991
(in thousands)
<CAPTION>
- ----------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
- ----------------------------------------------------------------------------------------
Additions
Balance at Charged to Balance
beginning Costs and Other at end
Description of period Expenses Retirements Changes of period
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Depreciation reserve:
Electric plant:
Production-fossil $ 254,402 $ 24,989 $10,790 $ 143 $ 268,744
-nuclear 276,126 38,109(A) 365 0 313,870
-other 16,713 1,788 2 0 18,499
-----------------------------------------------------------------
Total production 547,241 64,886 11,157 143 601,113
Transmission 110,369 10,308 148 4 120,533
Distribution 312,855 33,711 25,112 1,724 323,178
General 44,444 10,238(B) 2,889 2 51,795
Harbor Electric
Energy Company 462 910 0 0 1,372
-----------------------------------------------------------------
Total electric 1,015,371 120,053 39,306 1,873(D) 1,097,991
Accumulated
amortization
of nuclear
fuel (F) 163,694 19,869 0 (3,426)(E) 180,137
-----------------------------------------------------------------
Total $1,179,065 $139,922 $39,306(C) $(1,553) $1,278,128
=================================================================
<FN>
(A) Excludes $4,675 of nuclear decommissioning costs.
(B) Includes $6,179 of amortization of leasehold improvements, computer software and load management program costs.
(C) Includes $8,974 of removal costs.
(D) Represents salvage value of property retired.
(E) Payments to the Department of Energy for post-April 1983 nuclear fuel disposal.
(F) For information regarding the amortization policy for nuclear fuel, see Note A, part 4, to the consolidated financial
statements included in Item 8.
</TABLE>
S-6
<PAGE> 72
<TABLE>
Boston Edison Company Schedule VII
Guarantees of Securities of Other Issuers
December 31, 1993
(in thousands)
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F Column G
- ------------------------------------------------------------------------------------------------------------------------------
Amount in
Total amount treasury of
guaranteed Amount issuer of Nature of
Name of issuer and owned by securities Nature of default
of securities Title of issue outstanding Company guaranteed guarantee by issuer
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Yankee Atomic
Electric Company: $40 Million Amortizing
Term Loan - expires
1997 $ 1,300 none none guarantee of none
principal
and interest
New England Hydro
Finance Company, Inc.: (1) Series A Note - due 2001 $10,000 none none guarantee of none
Series B Note - due 2007 6,300 principal
Series C Note - due 2015 5,700 and interest
-------
Total $22,000
=======
<FN>
(1) As part of Hydro-Quebec Phase II, the Company and other
New England electric utilities became equity owners in New
England Hydro-Transmission Electric Company, Inc. and New England
Hydro-Transmission Corporation, the parent companies and guarantors
of New England Hydro Finance Company, Inc. The Company and other
equity participants agreed to guarantee severally their proportionate
share of the borrowings outstanding of these companies pursuant
to the Note and Guarantee Agreement dated April 15, 1991. The
Company and other equity participants also guarantee their
proportionate share of the total obligations of the participants
who do not meet certain credit criteria.
</TABLE>
S-7
<PAGE> 73
<TABLE>
Boston Edison Company Schedule IX
Short-Term Borrowings
Year ended December 31,
(in thousands)
<CAPTION>
- ------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E Column F
- ------------------------------------------------------------------------------------------------
Weighted
Maximum Average average
Category of December 31 amount amount interest
aggregate Balance weighted outstanding outstanding rate
short-term at end average during the during the during the
borrowings of period interest rate period period period
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1993 (1) $204,151 3.5% $320,000 $220,149 3.4%
1992 (1) $275,500 3.8% $314,998 $233,286 4.1%
1991 (1) $210,300 6.1% $324,400 $221,481 6.4%
</TABLE>
<TABLE>
(1) Borrowings under: Year ended December 31,
--------------------------------------
<CAPTION>
1993 1992 1991
-------- -------- --------
<S> <C> <C> <C>
Lines of credit $106,501 $162,500 $ 89,000
Commercial paper 97,650 113,000 121,300
-------- -------- --------
Total $204,151 $275,500 $210,300
======== ======== ========
</TABLE>
For information regarding the Company's borrowing arrangements, see Note F,
part 6, to the consolidated financial statements included in Item 8.
S-8
<PAGE> 74
<TABLE>
Boston Edison Company Schedule X
Supplementary Income Statement Information
Year ended December 31,
(in thousands)
<CAPTION>
Column A Column B
- ------------------------------------------- ----------------------------
Charged to costs
Item and expenses
- ------------------------------------------- ----------------------------
1993 1992 1991
----------------------------
<S> <C> <C> <C>
Maintenance and repairs* $94,826 $87,113 $102,215
============================
Taxes other than payroll and income taxes:
Municipal property $77,238 $63,430 $ 51,486
============================
<FN>
* Amounts are net of capitalized expenses.
</TABLE>
For amortization of deferred cost of cancelled nuclear unit and
amortization of deferred nuclear outage costs, see the consolidated
statements of income included in Item 8.
S-9
<PAGE> 1
Exhibit 4.1.28
Pricing Committee Meeting
Boston, August 18, 1993
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, August 18, 1993, at five minutes past twelve o'clock
p.m., local time, the Chairman presiding.
Present: Messrs. Reznicek and 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, Messrs. Peters, Alpert, Frigard and Conway
and Ms. O'Neil.
Absent: None.
Messrs. Reznicek and Peters presented management's proposal
to sell $100,000,000 principal amount of debentures. Mr.
Reznicek summarized the votes being presented for action by the
directors. 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 on January 28, 1993, the Company issue and
sell $100,000,000 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 6.05% Debentures due August 15, 2000 (the
"Debentures").
Voted: That the Debentures be issued with the following
terms:
Maturity Date: August 15, 2000
Interest Rate: 6.05%
Interest Payment Date: February 15 and August 15 of
each year commencing February 15, 1994
Price to the Public: 99.935%
Proceeds to the Company: 99.31%
Redemption Provisions: No call
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 executive or senior vice president,
the treasurer or any assistant treasurer of the
Company be, and each of them acting
65
<PAGE> 2
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
executive or 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. 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 executive or senior
vice president, the treasurer or any assistant
treasurer be, and each of them is, hereby authorized
to file with the Trustee 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.
66
<PAGE> 3
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:
Theodora S. Convisser
Clerk
67
<PAGE> 1
Exhibit 10.8.1
Directors Retirement Benefit
(1993 Plan)
At its April 6, 1993 meeting, the Executive Committee voted
to recommend to the Board of Directors that the Company's
retirement benefit for outside directors be amended as follows:
Vesting: The benefit will vest upon the earlier of (1)
the completion of ten years of service on the
Board; (2) service on the Board until
retirement at the annual meeting of
stockholders following a director's
seventieth birthday; or (3) death while
serving on the Board.
Annual Amount: The annual amount of the benefit will be
equal to the cash component of the annual
Board retainer plus two annual Committee
member retainers, as those retainers are in
effect at the time of a director's retirement
or death (currently $10,000 + $2,750 + $2,750
or $15,500). The annual amount will be paid
in quarterly installments.
Duration of Benefit: A director while living will receive the annual
amount for a period of years equal to his or her
service on the Board.
Survivor Benefit: Should a director die prior to full receipt
of the benefit, his or her survivors will
continue to receive the benefit for a period
of time equal to the lesser of (1) the full
years-of-service term to which the director
would have been entitled if living or (2) a
period of ten years from the commencement of
payment of the benefit. Survivors may elect
to receive the benefit in the form of a lump
sum. The lump sum will be equal to the
present value of the remaining benefit,
calculated with reference to the Pension
Benefit Guarantee Corporation rate as in
effect at the time of the director's death.
Commencement of
Benefit: Payment of the benefit to a qualified
director will commence at the quarterly
payment date following the director's
departure from the Board and attainment of
age 65. Should a qualified director die
prior to the commencement of the benefit,
payment of the benefit to his or her
survivors as described above will commence at
the next quarterly payment date following the
director's death.
Applicability: The amended director retirement benefit as
proposed herein will take effect for all
retirements from the Board occurring in 1993
and thereafter.
68
<PAGE> 2
Service of
Less than a Year: Service of less than a year will be
calculated with reference to the applicable
fraction for determining both vesting and
benefit duration. Thus, for example, if a
director has service equal to six years and
nine months when he retires at age 70, he
will receive the annual amount for 6 3/4
years.
69
<PAGE> 1
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 and 33-
57840) and on Form S-8 (File Nos. 33-00810, 33-7558, 33-38434, 33-48424,
33-48425, 33-59662 and 33-59682) of our report dated January 25, 1994 on our
audits of the consolidated financial statements and financial statement
schedules of Boston Edison Company as of December 31, 1993 and 1992 and for
each of the three years in the period ended December 31, 1993, which report is
included in this Annual Report on Form 10-K.
Boston, Massachusetts COOPERS & LYBRAND
March 30, 1994
70
