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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-2301
BOSTON EDISON COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1278810
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, 02199
Massachusetts
(Address of principal executive offices) (Zip Code)
(617) 424-2000
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES [ x ] NO [ ]
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Outstanding at
Class of Common Stock March 29, 2001
Common Stock, $1 par value 100 shares
The Company meets the conditions set forth in General Instruction
I(1)(a) and (b) of Form 10-K as a wholly-owned subsidiary and is
therefore filing this Form with the reduced disclosure format.
Documents Incorporated Part in Form 10-K
by Reference
None Not Applicable
List of Exhibits begins on page 42 of this report.
Boston Edison Company
Form 10-K Annual Report
December 31, 2000
Part I Page
Item 1. Business 2
Item 2. Properties 7
Item 3. Legal Proceedings 8
Part II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters 8
Item 7. Management's Discussion and Analysis 9
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk 17
Item 8. Financial Statements and Supplementary Financial
Information 19
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 42
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on
Form 8-K 42
Part I
Item 1. Business
(a) General Development of Business
Boston Edison Company ("Boston Edison" or "the Company") is a
regulated public utility company incorporated in 1886 under
Massachusetts law and is a wholly owned subsidiary of NSTAR.
NSTAR is Massachusetts' largest investor-owned combined electric
and gas utility. NSTAR is an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including
more than one million electric customers in 81 communities and
244,000 gas customers in 51 communities. Boston Edison serves
approximately 681,000 electric customers in the city of Boston
and 39 surrounding communities. NSTAR was created through the
merger of BEC Energy (BEC) and Commonwealth Energy System
(COM/Energy) on August 25, 1999 as an exempt public utility
holding company. Its retail utility subsidiaries are Boston
Edison, Commonwealth Electric Company (ComElectric), Cambridge
Electric Light Company (Cambridge Electric) and NSTAR Gas Company
(NSTAR Gas) and its wholesale electric subsidiary is Canal
Electric Company (Canal Electric). Effective November 1, 2000,
NSTAR's three retail electric companies began to operate under
the brand name "NSTAR Electric." Reference in this report to
"NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric.
The electric industry has continued to change in response to
legislative, regulatory and marketplace demands for improved
customer service at lower prices. These demands have resulted in
an increasing trend in the industry to seek competitive
advantages and other benefits through business combinations.
NSTAR was created to operate in this new marketplace by combining
the resources of its utility subsidiaries, including Boston
Edison, and concentrating its activities in the transmission and
distribution of energy. The 1997 Massachusetts Electric
Restructuring Act (Restructuring Act) required all electric
utilities to divest their generating assets and leave the retail
power supply business, in exchange for the right to recover all
non-mitigable stranded costs associated with the creation of
customer choice and competition.
To complete its divestiture of generating assets, Boston Edison
sold Pilgrim Nuclear Generating Station (Pilgrim) in July 1999
for $81 million to Entergy Nuclear Generating Company (Entergy).
As part of the sale, Boston Edison, the first company in the
nation to successfully sell a nuclear facility, transferred
approximately $228 million in decommissioning funds to the
purchaser. Entergy, by contract, assumed all future liability
related to the ultimate decommissioning of the plant. The
difference between the total proceeds from the sale and the net
book value of the Pilgrim assets, plus the net amount to fully
fund the decommissioning trust, is included in Regulatory assets
on the accompanying Consolidated Balance Sheets as such amounts
are currently being collected from customers through the year
2010.
In 1998, Boston Edison completed the sale of all of its fossil
generating assets. The amount received above net book value on
the sale of these assets is being returned to retail customers
over approximately 11 years. Refer to the Generating Assets
Divestiture section in Item 7, "Management's Discussion and
Analysis" for more information.
Harbor Electric Energy Company (HEEC), a wholly owned subsidiary
of Boston Edison, provides distribution service and ongoing
support to its only customer, the Massachusetts Water Resources
Authority's wastewater treatment facility located on Deer Island
in Boston, Massachusetts. Boston Edison's other wholly owned
special-purpose subsidiary, BEC Funding LLC (BEC Funding), was
established to facilitate the sale, on July 29, 1999, of $725
million of notes to a special purpose trust created by two
Massachusetts state agencies. The trust then concurrently closed
on the sale of $725 million of electric rate reduction
certificates at a public offering. The certificates are secured
by a portion of the transition charge assessed on Boston Edison's
retail customers as permitted by the Restructuring Act and
authorized by the Commonwealth of Massachusetts Department of
Telecommunications and Energy (MDTE). These certificates are non-
recourse to Boston Edison.
(b) Financial Information about Industry Segments
Boston Edison operates as a regulated electric public utility;
therefore industry segment information is not applicable.
(c) Narrative Description of Business
Principal Products and Services
Boston Edison currently delivers electricity at retail to an area
of 590 square miles, including the city of Boston and 39
surrounding cities and towns. The population of the area served
with electricity at retail is approximately 1.5 million. In 2000,
Boston Edison served an average of approximately 681,000
customers. Boston Edison also supplies electricity at wholesale
for resale to municipal electric departments. Electric operating
revenues by class for the last three years consisted of the
following:
2000 1999 1998
Retail electric revenues:
Commercial 53% 51% 51%
Residential 30% 29% 27%
Industrial 9% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 7% 10% 12%
Sources and Availability of Electric Power Supply
Boston Edison entered into a six-month agreement effective
January 1, 2000 to transfer all of the unit output entitlements
in long-term power purchase contracts to Select Energy (Select),
a subsidiary of Northeast Utilities. In return, Select provided
full energy service requirements, including New England Power
Pool (NEPOOL) capability responsibilities, at Federal Energy
Regulatory Commission (FERC)-approved tariff rates to meet the
Company's standard offer and default service load requirements
through June 30, 2000. Subsequently, Boston Edison entered into
two similar six-month agreements to meet the Company's standard
offer and default service load requirements with agreements that
extended to December 31, 2000. Beginning January 1, 2001, NSTAR
Electric's existing portfolio of power purchase contracts has
been supplying the majority of Boston Edison's standard offer
(including wholesale) energy requirements, supplemented with long-
term and daily purchases.
In addition, Boston Edison will continue to buy power generated
by Pilgrim from Entergy on a declining basis through 2004.
Information relative to nuclear units that are no longer
operating in which Boston Edison has an equity ownership as of
December 31, 2000 was as follows:
Connecticut Yankee
Yankee Atomic
(dollars in thousands)
Year of Shutdown 1996 1992
Equity Ownership (%) 9.5 9.5
Equity Ownership Balance $7,041 $753
NEPOOL
During 1997, NEPOOL was restructured with changes effecting the
membership and governance provisions of the power pooling
agreement along with the transfer of operating responsibility of
the integrated transmission and generation system in New England
to Independent System Operator-New England (ISO-New England).
Previously, NEPOOL dispatched generating units for operation
based on the lowest operating costs of available generation and
transmission. Under the new structure, generators will be
required to provide ISO-New England with market prices at which
they will sell short-term energy supply. These prices formed the
basis for dispatch that began in the second quarter of 1999. As
noted in the Sources and Availability of Electric Power Supply
section above, NSTAR Electric has existing long-term power
purchase contracts that have been supplying the majority of
Boston Edison's standard offer (including wholesale) energy
requirements, supplemented with long-term and daily
purchases/sales in bilateral and spot markets. Therefore, the
change to NEPOOL's operations and pricing structure is expected
to have no material adverse impact on Boston Edison's costs for
purchased electric energy.
Boston Edison entered into a six-month agreement effective
January 1, 2001 through June 30, 2001 with a supplier to provide
full default service energy and ancillary service requirements at
contract rates substantially similar to MDTE-approved tariff
rates. A default service request for proposal, for default
service power supply beginning July 1, 2001 was issued in early
2001. In addition, NSTAR Electric is managing its ISO-New
England capability responsibilities, congestion and uplift costs
associated with default service and standard offer load
throughout 2001. Refer to Long-Term Power Contracts, Note J, of
the Notes to Consolidated Financial Statements for more
information.
Franchises
Through its charter, which is unlimited in time, Boston Edison
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 electric transmission and distribution lines are obtained
from municipal and other state authorities which, in granting
these locations, act as agents for the state. In some cases the
actions of these authorities is subject to appeal to the MDTE.
The rights to these locations are not limited in time, but are
not vested and are subject to the action of these authorities and
the legislature. Pursuant to the Restructuring Act enacted in
November 1997, the MDTE has defined the service territory of
Boston Edison based on the territory actually served on July 1,
1997, and following, to the extent possible, municipal
boundaries. The legislation further provided that, until
terminated by effect of law or otherwise, Boston Edison shall
have the exclusive obligation to provide distribution service to
all retail customers within such service territory. No other
entity shall provide distribution service within this territory
without the written consent of Boston Edison which consent must
be filed with the MDTE and the municipality so affected.
Regulation
Boston Edison and its wholly owned subsidiaries, HEEC and BEC
Funding, operate primarily under the authority of the MDTE, whose
jurisdiction includes supervision over retail rates for
distribution of electricity, financing and investing activities.
In addition, the FERC has jurisdiction over various phases of
Boston Edison's electric utility businesses including rates for
electricity sold at wholesale, facilities used for the
transmission or sale of that energy, certain issuances of short-
term debt and regulation of the system of accounts.
Retail Electric Rates
As a result of electric industry restructuring, Boston Edison has
unbundled its rates, provided customers with inflation adjusted
rates that are 15 percent lower than rates in effect prior to
March 1, 1998, the retail access date, and have afforded
customers the opportunity to purchase generation supply in the
competitive market. Unbundled delivery rates are composed of a
customer charge (to collect metering and billing costs), a
distribution charge (to collect the costs of delivering
electricity), a transition charge (to collect past costs for
investments in generating plants and costs related to power
contracts), a transmission charge (to collect the cost of moving
the electricity over high voltage lines from a generating plant),
an energy conservation charge (to collect costs for demand-side
management programs) and a renewable energy charge (to collect
the cost to support the development and promotion of renewable
energy projects). Electricity supply services provided by Boston
Edison include optional standard offer service and default
service.
Standard offer service is the electricity that is supplied to
eligible customers by the retail electric subsidiaries until a
competitive power supplier is chosen by the customer. It is
designed as a seven-year transitional service (from March 1,
1998) to give the customer time to learn about competitive power
suppliers. The price of standard offer service increases over
time. Default service is supplied by the local distribution
company when a customer is not eligible for standard offer
service or receiving power from a competitive power supplier.
The market price for default service will fluctuate based on the
average market price for power. Amounts collected through these
various charges are reconciled to actual expenditures on an on-
going basis.
Prior to the implementation of industry restructuring on March 1,
1998, Boston Edison had Fuel Charge rate schedules that generally
allowed for current recovery, from retail customers, of fuel used
in electric production, purchased power and transmission costs.
Competitive Conditions
The electric industry has continued to change in response to
legislative, regulatory and marketplace demands for improved
customer service at lower prices. These demands have resulted in
an increasing trend in the industry to seek competitive
advantages and other benefits through business combinations.
NSTAR was created to operate in this new marketplace by combining
the resources of its utility subsidiaries and concentrating its
activities in the transmission and distribution of energy.
Environmental Matters
Boston Edison is subject to numerous federal, state and local
standards with respect to the management of wastes and other
environmental considerations. These standards could require
modification of existing facilities or curtailment or termination
of operations at these facilities. They could also potentially
delay or discontinue construction of new facilities and increase
capital and operating costs by substantial amounts.
Noncompliance with certain standards can, in some cases, also
result in the imposition of monetary civil penalties.
Environmental-related capital expenditures for the years 2000 and
1999 were zero and $0.6 million, respectively, and reflect in
large measure, the Company's exit from the electric generation
business. Management believes that its operating facilities were
in substantial compliance with currently applicable statutory and
regulatory environmental requirements. Additional expenditures
could be required as changes in environmental requirements occur.
Number of Employees
As of December 31, 2000, Boston Edison had approximately 2,014
full-time employees, including approximately 1,442, or 72% of
employees, represented by three collective bargaining units
covered by separate contracts. In December 2000, the management
of NSTAR's utility subsidiaries and eight separate utility union
bargaining units reached an agreement to merge most of the
unionized workforce, effective January 1, 2001, into Local 369 of
the Utility Workers Union of America AFL-CIO. The new agreement
results in a single bargaining unit of 2,000 NSTAR Electric and
NSTAR Gas employees into one five-year contract expiring May 15,
2005 that will replace seven separate and widely diverse
agreements. Management believes it has satisfactory employee
relations.
Expenditures and Financings
The most recent estimates of plant expenditures, long-term debt
maturities and preferred stock redemption requirements for the
years 2001 through 2005 are as follows:
(in thousands) 2001 2002 2003 2004 2005
Capital expenditures $147,000 $103,000 $ 92,000 $120,000 $ 85,000
Long-term debt $ 37,100 $ 71,800 $220,000 $ 70,400 $ 70,1000
Preferred stock $ 50,000 - - - -
Management continuously reviews its plant expenditure and
financing programs. These programs and the estimates included in
this Form 10-K are subject to revision due to changes in
regulatory requirements, environmental standards, availability
and cost of capital, interest rates and other assumptions.
Plant expenditures in 2000 and 1999 were $110 million and $125
million, respectively, and consisted primarily of additions to
Boston Edison's distribution and transmission systems. The
majority of these expenditures were for system reliability and
control improvements, customer service enhancements and capacity
expansion to allow for long-range growth in the Boston Edison
service territory.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales
Boston Edison delivers electricity to retail and wholesale
customers in the Boston area. Boston Edison does not have any
foreign operations or export sales.
Item 2. Properties
Boston Edison's high-tension transmission lines are generally
located on land either owned or subject to easements in its
favor. Its low-tension distribution lines are located
principally on public property under permission granted by
municipal and other state authorities.
As of December 31, 2000, Boston Edison's transmission system
consisted of 376 miles of overhead circuits operating at 115, 230
and 345 kilovolts (kV) and 177 miles of underground circuits
operating at 115 and 345 kV. The substations supported by these
lines are 45 transmission or combined transmission and
distribution substations with transformer capacity of 11,053
megavolt amperes (MVA), 574 distribution substations with
transformer capacity of 932 MVA and 16 primary network units with
79 MVA capacity. In addition, high tension service was delivered
to 248 customers' substations. Primary and secondary overhead and
underground distribution systems cover approximately 10,800 and
5,980 circuit miles, respectively. HEEC, Boston Edison's
regulated subsidiary, has a distribution system that consists
principally of a 4.1 mile 115 kV submarine distribution line and
a substation which is located on Deer Island in Boston,
Massachusetts. HEEC provides the ongoing support required to
distribute electric energy to its one customer, the Massachusetts
Water Resources Authority, at this location.
Item 3. Legal Proceedings
Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving Boston Edison's restructuring
settlement agreement was appealed by certain parties to the
Massachusetts Supreme Judicial Court. One appeal remains
pending. However, there has to date been no briefing, hearing or
other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this
proceeding. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows or results of
operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE,
the Massachusetts Attorney General contested cost allocations
related to Boston Edison's wholesale customers since 1998.
Management is unable to determine the outcome of the MDTE
proceedings. However, if an unfavorable outcome were to occur,
there would be a material adverse impact on Boston Edison's
business operations, the consolidated financial position, results
of operations and cash flows in the near term.
In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group and authorized Boston
Edison to invest up to $45 million in non-utility activities.
Hearings were completed during 1999 and no further developments
have occurred at this time. Management is currently unable to
determine the timing and outcome of this proceeding. However, if
an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial
position, cash flows and results of operations for a reporting
period.
Other litigation
In the normal course of its business, Boston Edison and its
subsidiaries are also involved in certain other legal matters.
Management is unable to fully determine a range of reasonably
possible legal costs in excess of amounts accrued. Based on the
information currently available, management does not believe that
it is probable that any such additional costs will have a
material impact on its consolidated financial position. However,
it is reasonably possible that additional legal costs that may
result from a change in estimates could have a material impact on
the results of a reporting period.
Part II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters
The information required by this item is not applicable because
all of the common stock of Boston Edison is held solely by NSTAR,
its parent company.
Market information for the common stock of NSTAR is included in
Item 5 of NSTAR's Annual Report on Form 10-K for the year ended
December 31, 2000.
Item 7. Management's Discussion and Analysis
Boston Edison Company ("Boston Edison" or "the Company") is a
regulated public utility incorporated in 1886 under
Massachusetts' law and is a wholly owned subsidiary of NSTAR.
NSTAR is Massachusetts' largest investor-owned combined electric
and gas utility. NSTAR is an energy delivery company serving
approximately 1.3 million customers in Massachusetts including
more than one million electric customers in 81 communities and
244,000 gas customers in 51 communities. Boston Edison serves
approximately 681,000 electric customers in the city of Boston
and 39 surrounding communities. NSTAR was created through the
merger of BEC Energy (BEC) and Commonwealth Energy System
(COM/Energy) on August 25, 1999 as an exempt public utility
holding company. Its retail utility subsidiaries are Boston
Edison, Commonwealth Electric Company (ComElectric), Cambridge
Electric Light Company (Cambridge Electric) and NSTAR Gas Company
(NSTAR Gas) and its wholesale electric subsidiary is Canal
Electric Company (Canal Electric). Effective November 1, 2000,
NSTAR's three retail electric companies began to operate under
the brand name "NSTAR Electric." Reference in this report to
"NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric.
Merger of BEC Energy and Commonwealth Energy System
An integral part of the merger creating NSTAR is the rate plan of
the retail utility subsidiaries of BEC and COM/Energy, including
Boston Edison, that was approved by the Massachusetts Department
of Telecommunications and Energy (MDTE) on July 27, 1999.
Significant elements of the rate plan include a four-year
distribution rate freeze, recovery of the acquisition premium
(goodwill) over 40 years and recovery of transaction and
integration costs (costs to achieve) over 10 years. Refer to the
Retail Electric Rates section of this Discussion and Analysis for
more information.
The merger of BEC and COM/Energy was accounted for as an
acquisition of COM/Energy by BEC using the purchase method of
accounting. In accordance with Accounting Principles Board (APB)
No. 16 - Business Combinations, all goodwill has been recorded on
the books of the subsidiaries of COM/Energy. However, under the
merger rate plan approved by the MDTE, all of NSTAR's utility
subsidiaries share in the recovery of goodwill in their rates.
As a result, goodwill amortization expense is allocated to Boston
Edison from ComElectric, Cambridge Electric and NSTAR Gas through
an intercompany charge. The Company is currently recovering such
amount in its rates.
NSTAR recorded goodwill associated with the merger of BEC Energy
and COM/Energy of approximately $490 million, resulting in an
annual amortization of goodwill of approximately $12.2 million.
Boston Edison will be allocated $319 million of goodwill and
will expense this amount. Such amount is being recovered in
Boston Edison's rates and is treated as an intercompany charge
among the Company and its affiliated companies, ComElectric,
Cambridge Electric and NSTAR Gas. Costs to achieve are being
amortized based on the filed estimate of $111 million over 10
years. As of December 31, 2000, Boston Edison's portion of
goodwill and costs to achieve amortization are approximately
$8 million and $7 million, respectively. NSTAR's retail utility
subsidiaries will reconcile the ultimate costs to achieve with
that estimate, and any difference is expected to be recovered
over the remainder of the amortization period. A majority of
costs to achieve the merger have been for severance costs
associated with a voluntary separation program (VSP) in which
approximately 700 NSTAR Electric and Gas employees elected to
participate. The VSP was completed by the end of August 2000.
These amounts are expected to be offset by ongoing future cost
savings from streamlined operations and avoidance of costs that
would have otherwise been incurred by BEC and COM/Energy.
As a result of the merger, cost savings have been realized due to
reduced staffing levels and operating efficiencies.
Generating Assets Divestiture
To complete its divestiture of generating assets, Boston Edison
sold its Pilgrim Nuclear Generating Station (Pilgrim) in July
1999 for $81 million to Entergy Nuclear Generating Company
(Entergy). As part of the sale, Boston Edison, the first company
in the nation to successfully sell a nuclear facility,
transferred approximately $228 million in decommissioning funds
to Entergy. Entergy, by contract, assumed all future liability
related to the ultimate decommissioning of the plant. The
difference between the total proceeds from the sale and the net
book value of the Pilgrim assets, plus the net amount to fully
fund the decommissioning trust, is included in Regulatory assets
on the accompanying Consolidated Balance Sheets as such amounts
are currently being collected from customers through the year
2010.
In 1998, Boston Edison completed the sale of all of its fossil
generating assets. The amount received above net book value on
the sale of these assets is being returned to customers over
approximately 11 years.
Securitization of Boston Edison's Transition Charge
On July 27, 1999, BEC Funding LLC, a wholly owned special-purpose
subsidiary of Boston Edison, closed the sale of $725 million of
notes to a special purpose trust created by two Massachusetts
state agencies. The trust then concurrently closed the sale on
$725 million of electric rate reduction certificates as a public
offering. The certificates are secured by a portion of the
transition charge assessed on Boston Edison's retail customers as
permitted under the Massachusetts Electric Restructuring Act
(Restructuring Act) and authorized by the MDTE. These
certificates are non-recourse to Boston Edison.
Retail Electric Rates
As a result of the Restructuring Act, Boston Edison currently
provides its standard offer customers service at inflation-
adjusted rates that are 15% lower than rates in effect prior to
March 1, 1998, the retail access date.
All distribution customers must pay a transition charge as a
component of their rate. The purpose of the transition charge is
to allow for the collection of generation-related costs that
would not be collected in the competitive energy supply market.
The plant and regulatory asset balances that will be recovered
through the transition charge until 2009 were approved by the
MDTE.
The Restructuring Act requires electric distribution companies to
obtain and resell power to retail customers that choose not to
buy energy from a competitive energy supplier. This is through
either "standard offer service" or "default service." Standard
offer service will be available to eligible customers through
2004 at prices approved by the MDTE set at levels so as to
guarantee mandatory overall rate reductions provided by the
Restructuring Act. New retail customers in the Boston Edison
service territory and previously existing customers that are no
longer eligible for the standard offer service and have not
chosen to receive service from a competitive supplier are
provided "default service." The price of default service is
intended to reflect the average competitive market price for
power. NSTAR Electric has existing long-term power purchase
contracts. These long-term contracts will supply approximately
90% - 95% of its standard offer obligations. NSTAR Electric has
entered into six-month and shorter-term agreements to meet the
remaining standard offer service obligation and continues to
evaluate further proposals. In November 2000, NSTAR Electric
entered into power purchase agreements to meet all of its default
service supply obligation for the period January through June
2001. NSTAR Electric expects to continue periodic market
solicitations for default service power supply consistent with
provisions of the Restructuring Act and MDTE orders. The cost of
providing standard offer and default service, which includes
purchased power costs, is recovered from customers on a fully
reconciling basis.
Boston Edison's accumulated cost to provide default and standard
offer services is in excess of the revenues it has been allowed
to bill as of December 31, 2000. As a result, Boston Edison has
recorded, at December 31, 2000, a regulatory asset of
approximately $193.6 million that is reflected as a component of
Current assets on the accompanying Consolidated Balance Sheets.
At December 31, 1999, costs incurred in excess of revenues
collected amounted to $44.3 million and were reflected as a non-
current Regulatory asset.
Under applicable restructuring plans or settlements approved by
the MDTE, Boston Edison must, on an annual basis, file proposed
adjustments to its rates for the upcoming year along with a
proposed reconciliation of prior year revenues and costs for its
standard offer, default service, transmission and transition
charges. Boston Edison made such a filing with the MDTE in the
Fall of 1999. The MDTE subsequently approved proposed rate
adjustments effective January 1, 2000, and conducted further
hearings for the purpose of reconciling the prior year's costs
and revenues related to the Company's transition and transmission
charges and the charges for standard offer and default service.
The MDTE approved a settlement agreement that resolved the
majority of these issues, including all outstanding issues
related to Pilgrim, certain cost allocations and other related
issues that have been contested; however, the MDTE has not yet
rendered a final decision. In November 2000, Boston Edison made
a similar filing containing proposed rate adjustments for 2001,
including a reconciliation of costs and revenues through 1999.
The MDTE has approved rate adjustments effective January 1, 2001,
but it has not yet ruled on the reconciliation component of the
filings. Management is unable to determine the outcome of the
MDTE proceedings. However, if an unfavorable outcome were to
occur, there would be a material adverse impact on Boston
Edison's consolidated financial position, results of operations
and cash flows in the near term.
In addition to the annual rate filings referenced above, Boston
Edison has also made separate filings with the MDTE concerning
charges for standard offer and default service. Boston Edison
has filed with the MDTE a request for approval to increase its
standard offer service rate for 2001 based on a fuel adjustment
formula contained in its standard offer tariffs that reflects the
prices of natural gas and oil. On December 11, 2000, the MDTE
approved an increase in the standard offer rate of 1.321 cents
per kWh for the Company. The MDTE ruled that the fuel adjustments
did not have to meet the 15% rate reduction requirement under the
Restructuring Act. The MDTE will re-examine these rates in July
2001. On October 19, 2000, the MDTE approved Boston Edison's
request to increase the price of default service to 6.28 cents
per kWh, effective December 1, 2000. On November 9, 2000, the
Company filed a request with the MDTE for an additional increase
for default service to reflect market costs for the period
January 1, 2001 through June 30, 2001. On December 4, 2000, the
MDTE approved market-based default service rates covering this
period. These and future prices for default service are based
upon market solicitations for power supply for default service
consistent with provisions of the Restructuring Act and MDTE
orders.
Under its restructuring settlement agreement, Boston Edison's
distribution business was subject to an annual minimum and
maximum return on average common equity (ROE) through December
31, 2000. The ROE was subject to a floor of 6% and a ceiling of
11.75%. If the ROE was below 6%, Boston Edison was authorized to
add a surcharge to distribution rates in order to achieve the 6%
floor. If the ROE was above 11%, it was required to adjust
distribution rates by an amount necessary to reduce the
calculated ROE between 11% and 12.5% by 50%, and a return above
12.5% by 100%. No adjustment was made if the ROE was between 6%
and 11%. In addition, distribution rates continue to be subject
to adjustment for any changes in tax laws or accounting
principles that result in a change in costs of more than $1
million. No adjustments have been made to Boston Edison's
distribution rates due to either one of these mechanisms.
Results of Operations
2000 verses 1999
Net income was $146 million in 2000 compared to $160.3 million in
1999, a decrease of 9%.
Operating revenues
Operating revenues increased 8% from 1999 as follows:
(in thousands)
Retail revenues $ 145,743
Wholesale revenues (29,335)
Short-term sales and other revenues 8,621
Increase in operating revenues $ 125,029
=========
Retail revenues were $1,533.2 million in 2000 compared to
$1,387.5 million in 1999, an increase of $145.7 million or 11%.
This change reflects a 3.2% increase in retail kilowatt-hour
(kWh) electric sales. The increase in retail kWh sales is the
result of a strong local economy as indicated by a 2.2%
improvement in the overall Massachusetts employment rate, new
construction and customer growth. Additionally, Boston Edison
recognized incentive revenue entitlements for successfully
lowering transition charges, and will continue to earn these
entitlements as it lowers transition charges through 2009. The
incentive entitlements relate to 1998, 1999 and 2000, and will be
collected from customers in 2001. In addition, Boston Edison
increased standard offer and default service rates in January and
December 2000, which are fully reconciled to the costs incurred
and have no impact on net income.
Wholesale electric revenues were $73.2 million in 2000 compared
to $102.5 million in 1999, a decrease of $29.3 million or 29%.
This decrease in wholesale revenues primarily reflects the
absence of sales to Pilgrim contract customers due to the sale of
Pilgrim in July 1999.
Other revenues were $65.5 million in 2000 compared to $56.9
million in 1999, an increase of $8.6 million or 15%. This revenue
increase primarily reflects higher transmission revenues in 2000
compared to refunds credited to wholesale customers in 1999
resulting from a Federal Energy Regulatory Commission (FERC)-
approved settlement with transmission contract customers.
Operating expenses
Purchased power and fuel expense was $839.7 million in 2000
compared to $645.2 million in 1999, an increase of $194.5 million
or 30%. Purchased power expense increased $223 million reflecting
the increase in purchased power requirements due to the sale of
Pilgrim during 1999, an overall increase in the cost of wholesale
power and increased requirements resulting from increased kWh
sales. Boston Edison adjusts its electric rates to collect the
costs related to fuel and purchased power from customers on a
fully reconciling basis. Boston Edison's fuel and purchased
power expenses reflects a deferral of $145 million in 2000 and
$56 million in 1999 related to these rate recovery mechanisms.
Due to rate adjustment mechanisms, changes in the amount of fuel
and purchased power expense have no impact on earnings.
Offsetting these increases was the absence in the current period
of fuel expense related to Pilgrim, which decreased $9.4 million
due to the sale of the plant in July 1999.
Operations and maintenance expense was $205.7 million in 2000
compared to $271.4 million in 1999, a decrease of $65.7 million
or 24%. This change primarily reflects the absence of $36.3
million in nuclear power production expenses due to the sale of
the Pilgrim plant in July 1999. As a result of the merger,
operations and maintenance cost savings have been realized due to
reduced staffing levels and operating efficiencies. In addition,
Boston Edison experienced significantly lower costs for employee
pensions and benefits in 2000.
Depreciation and amortization expense was $169.3 million in 2000
compared to $176.7 million in 1999, a decrease of $7.4 million or
4%. This decrease primarily reflects the impact of the sale of
Pilgrim in July 1999. This decrease was partially offset by $7.2
million from the amortization of costs to achieve related to the
merger and $8 million from an affiliated company charge for
Boston Edison's portion of goodwill. These amounts are being
collected from Boston Edison's customers in accordance with the
rate plan that was approved by the MDTE on July 27, 1999.
Demand side management (DSM) and renewable energy programs
expense was $54.8 million in 2000 compared to $57.5 million in
1999, a decrease of $2.7 million or 5%. This decrease reflects
an 8.1% decrease in the energy conservation rate as of January 1,
2000. In accordance with restructuring legislation and the
settlement agreement, these costs are collected from customers on
a fully reconciling basis. Therefore, the change has no impact
on earnings.
Property and other taxes were $55.9 million in 2000 compared to
$68.8 million in 1999, a decrease of $12.9 million or 19%. The
decrease primarily reflects lower municipal property taxes
resulting from the divestiture of Pilgrim.
Income taxes from operations were $95.9 million in 2000 compared
to $91 million in 1999, an increase of $4.9 million or 5.4%.
This increase reflects higher pretax operating income in 2000.
Other income (expense), net
Other income, net of tax was $7.7 million in 2000 compared to
$19.8 million in 1999, a net decrease of $12.1 million or 61%.
Income tax benefits in 1999 were $13.9 million, which included
$20.8 million related to the recognition of previously deferred
investment tax credits associated with the Pilgrim station that
was sold in 1999, partially offset by miscellaneous non-operating
expense of $8.5 million. Interest income of $5 million in 2000
compared to $3.7 million in 1999, reflects an increase due to
interest received from a third party amounting to $4.4 million
related to the Pilgrim wholesale contract buyout and was
partially offset by a decrease in non-utility revenues.
Interest charges
Interest on long-term debt and transition property securitization
certificates was $98.3 million in 2000 compared to $91.6 million
in 1999, an increase of $6.7 million or 7.3%. The increase
reflects approximately $25.1 million of interest related to
transition property securitization certificates issued in July
1999. These increases were partially offset by approximately
$18.4 million in reductions related to the following retirements:
$65 million of 6.8% debentures, $34 million of 9.875% debentures
and $100 million of 6.05% debentures during 2000.
Other interest charges were $15.9 million in 2000 compared to
$6.2 million in 1999, an increase of $9.7 million or 156%. The
increase primarily reflects interest associated with the
reconciliation of the 1998 and 1999 transition charge true-up
filings with the MDTE in November 2000. In addition, interest on
short-term debt used to finance the above referenced long-term
debt retirements contributed toward this increase.
Other Matters
Environmental
Boston Edison is involved in approximately 16 state-regulated
properties where oil or other hazardous materials were previously
spilled or released. Boston Edison is required to clean up these
properties in accordance with specific state regulations. There
are uncertainties associated with these costs due to the
complexities of cleanup technology, regulatory requirements and
the particular characteristics of the different sites. Boston
Edison also continues to have potential liability as a
potentially responsible party (PRP) in the cleanup of five multi-
party hazardous waste sites in Massachusetts and other states
where it is alleged to have generated, transported or disposed of
hazardous waste at the sites. Boston Edison generally expects to
have only a small percentage of the total potential liability for
these sites. Through December 31, 2000, Boston Edison had
approximately $5 million accrued on its Consolidated Balance
Sheets related to these cleanup liabilities. Management is unable
to fully determine a range of reasonably possible cleanup costs
in excess of the accrued amount. Based on preliminary assessments
of the specific site circumstances, management does not believe
that it is probable that any such additional costs will have a
material impact on Boston Edison's consolidated financial
position. However, it is reasonably possible that additional
provisions for cleanup costs that may result from a change in
estimates could have a material impact on the results of
operations for a reporting period in the near term.
Estimates related to environmental remediation costs are reviewed
and adjusted periodically as further investigation and assignment
of responsibility occurs. Boston Edison is unable to estimate its
ultimate liability for future environmental remediation costs.
However, in view of Boston Edison's current assessment of its
environmental responsibilities, existing legal requirements and
regulatory policies, management does not believe that these
matters will have a material adverse effect on Boston Edison's
financial position or results of operations for a reporting
period.
Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving Boston Edison's electric
restructuring settlement agreement was appealed by certain
parties to the Massachusetts Supreme Judicial Court. One appeal
remains pending. However, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this
proceeding. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows or results of
operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE,
the Massachusetts Attorney General contested cost allocations
related to Boston Edison's wholesale customers since 1998.
Management is currently unable to determine the timing and
outcome of this proceeding. However, if an unfavorable outcome
were to occur, there could be a material adverse impact on the
Company's business operations, its consolidated financial
position, cash flows or results of operations for a reporting
period.
In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group (BETG) and authorized
Boston Edison to invest up to $45 million in non-utility
activities. Hearings were completed during 1999 and no further
developments have occurred as of this time. Management is
currently unable to determine the timing and outcome of this
proceeding. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows or results of
operations for a reporting period.
Other litigation
In the normal course of its business, Boston Edison and its
subsidiaries are also involved in certain other legal matters.
Management is unable to fully determine a range of reasonably
possible legal costs in excess of amounts accrued. Based on the
information currently available, it does not believe that it is
probable that any such additional costs will have a material
impact on its consolidated financial position. However, it is
reasonably possible that additional legal costs that may result
from a change in estimates could have a material impact on the
results of a reporting period.
Number of employees
As of December 31, 2000, Boston Edison had approximately 2,014
full-time employees, including approximately 1,442 or 72% of
employees represented by three collective bargaining units
covered by separate contracts. In December 2000, the management
of NSTAR's utility subsidiaries and eight separate utility union
bargaining units reached an agreement to merge most of the
unionized workforce, effective January 1, 2001, into Local 369 of
the Utility Workers Union of America AFL-CIO. The new agreement
results in a single bargaining unit of 2,000 NSTAR Electric and
NSTAR Gas employees into one five-year contract expiring May 15,
2005 that will replace seven separate and widely diverse
agreements. Management believes it has satisfactory employee
relations.
Interest rate risk
Boston Edison is exposed to changes in interest rates primarily
based on levels of short-term debt outstanding. Carrying amounts,
fair values of mandatory redeemable cumulative preferred stock
and indebtedness (excluding notes payable) and the weighted
average cost as of December 31, 2000 and 1999, were as follows:
(in thousands) Weighted
Carrying Fair Average
2000 Amount Value Interest Rate
Mandatory redeemable
cumulative preferred stock $ 49,519 $ 50,890 8.00%
Long-term indebtedness $1,198,857 $1,198,695 7.58%
1999
Mandatory redeemable
cumulative preferred stock $ 49,279 $ 52,250 8.00%
Long-term indebtedness $1,476,431 $1,500,340 7.07%
New accounting principles
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133) and
as amended by Statements of Financial Accounting Standards Nos.
137 and 138, collectively referred to as SFAS 133. SFAS 133
established accounting and reporting standards requiring that
every derivative instrument (including certain derivative
instruments embedded in other contracts possibly including fixed-
price fuel supply and power contracts) be recorded on the
Consolidated Balance Sheets as either an asset or liability
measured at its fair value. SFAS 133 is effective for fiscal
years beginning after June 15, 2000.
Boston Edison has begun to adopt SFAS 133 as of January 1, 2001.
The impact of this adoption has been assessed by the management
of the Company. As a part of this assessment, the Company formed
an implementation team in 2000 consisting of key individuals from
various operational and financial areas of the organization. The
primary role of this team was to inventory and determine the
impact of potential contractual arrangements for SFAS 133
application. The implementation team has performed extensive
reviews of critical operating areas of Boston Edison and has
documented its procedures in applying the requirements of SFAS
133 to Boston Edison's contractual arrangements in effect on
January 1, 2001. Based on Boston Edison's assessment to date,
the adoption of SFAS 133 will not have a material adverse effect
on its results of operations, cash flows, or financial position
as of January 1, 2001.
Safe harbor cautionary statement
Management occasionally makes forward-looking statements such as
forecasts and projections of expected future performance or
statements of its plans and objectives. These forward-looking
statements may be contained in filings with the Securities and
Exchange Commission, press releases and oral statements. Actual
results could potentially differ materially from these
statements. Therefore, no assurances can be given that the
outcomes stated in such forward-looking statements and estimates
will be achieved.
The preceding sections include certain forward-looking statements
about operating results and environmental and legal issues.
The impact of continued cost control procedures on operating
results could differ from current expectations. The effects of
changes in economic conditions, tax rates, interest rates,
technology, prices and availability of operating supplies could
materially affect the projected operating results.
The impacts of various environmental, legal issues, and
regulatory matters could differ from current expectations. New
regulations or changes to existing regulations could impose
additional operating requirements or liabilities other than
expected. The effects of changes in specific hazardous waste
site conditions and cleanup technology could affect the estimated
cleanup liabilities. The impacts of changes in available
information and circumstances regarding legal issues could affect
the estimated litigation costs.
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk
Although the Company has material commodity purchase contracts
and financial instruments (debt), these instruments are not
subject to market risk. The Company has a standard offer service
mechanism which allows for the recovery of fuel costs from
customers. The fuel adjustment mechanism allows the Company to
pass all costs related to the purchase of commodities to the
customer, thereby insulating the Company from market risk.
Similarly, any change in the fair market value of the Company's
prudently incurred debt obligations realized by the Company would
be borne by customers through future rates.
Report of Independent Accountants
To the Stockholder and Directors of Boston Edison Company:
In our opinion, the consolidated financial statements listed in
the index appearing under Item 14(a)(1) on page 42, present
fairly, in all material respects, the financial position of
Boston Edison Company and its subsidiaries at December 31, 2000
and 1999, and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 2000 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our
opinion, the financial statement schedule listed in the index
appearing under Item 14 (a)(2) on page 42, presents fairly, in
all material respects, the information set forth therein when
read in conjunction with the related consolidated financial
statements. These financial statements and the financial
statement schedule are the responsibility of the Company's
management; our responsibility is to express an opinion on these
financial statements and the financial statement schedule based
on our audits. We conducted our audits of these statements in
accordance with auditing standards generally accepted in the
United States of America, which 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, assessing
the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable
basis for our opinion.
PricewaterhouseCoopers LLP
Boston, Massachusetts
January 26, 2001
Item 8. Financial Statements and Supplementary Financial
Information
Boston Edison Company
Consolidated Statements of Income
(in thousands)
Years ended December 31,
2000 1999 1998
Operating revenues $1,671,846 $1,546,817 $1,622,972
Operating expenses:
Purchased power and fuel 839,715 645,175 567,806
Operations and maintenance 205,734 271,358 373,410
Depreciation and amortization 169,333 176,705 195,610
Demand side management and
renewable energy programs 54,836 57,467 51,839
Taxes-property and other 55,905 68,826 84,091
Income taxes 95,852 91,029 100,492
Total operating expenses 1,421,375 1,310,560 1,373,248
Operating income 250,471 236,257 249,724
Other income (expense), net 7,699 19,803 (2,941)
Operating and other income 258,170 256,060 246,783
Interest charges:
Long-term debt 52,804 71,150 82,951
Transition property
securitization certificates 45,505 20,408 -
Other 15,902 6,199 8,163
Allowance for borrowed funds
used during construction (2,069) (2,011) (1,668)
Total interest charges 112,142 95,746 89,446
Net income $ 146,028 $ 160,314 $ 157,337
========= ======== ========
Per share data is not relevant because Boston Edison Company's
common stock is wholly owned by NSTAR.
The accompanying notes are an integral part of the consolidated
financial statements.
Boston Edison Company
Consolidated Statements of Comprehensive Income
(in thousands)
Years ended December 31,
2000 1999 1998
Net income $ 146,028 $160,314 $ 157,337
Comprehensive (loss) income, net:
Additional minimum non-qualified
pension liability (117) - -
Comprehensive income $ 145,911 $160,314 $ 157,337
======== ======== ========
Boston Edison Company
Consolidated Statements of Retained Earnings
(in thousands)
Years ended December 31,
2000 1999 1998
Balance at the beginning of the year $ 1,462 $ 297,347 $ 328,802
Add:
Net income 146,028 160,314 157,337
Dividends transferred from paid in
capital (a) 226,541 - -
Subtotal 374,031 457,661 486,139
Deduct:
Dividends declared:
Dividends to common shareholders - - 22,802
Dividends to Parent 15,000 450,000 141,000
Preferred stock 5,960 5,960 8,765
Transfer of BETG to BEC Energy - - 8,392
Subtotal 20,960 455,960 180,959
Deduct:
Provision for preferred stock
redemption and issuance costs 239 239 7,833
Balance at the end of year $ 352,832 $ 1,462 $ 297,347
======== ======= ========
(a) The Company's Board of Directors has determined and voted
that a portion of the dividends declared on June 24, 1999 and
July 22, 1999, which were paid out of retained earnings to its
sole shareholder, was a partial distribution of a return of
capital. As a result, the Company has appropriately transferred
the portion of its dividends deemed return of capital against
Premium on Common Stock.
The accompanying notes are an integral part of the consolidated
financial statements.
Boston Edison Company
Consolidated Balance Sheets
(in thousands)
December 31,
Assets 2000 1999
Utility plant in service,
at original cost $2,522,682 $2,494,720
Less: accumulated
depreciation 825,367 $1,697,315 848,544 $1,646,176
Construction work in progress 39,820 53,647
Net utility plant 1,737,135 1,699,823
Equity investments 15,512 19,880
Other investments 9,599 10,939
Current assets:
Cash and cash equivalents 12,125 117,537
Restricted cash 3,625 3,625
Accounts receivable-customers,
net of allowance of $22,415
and $19,380 in 2000 and
1999, respectively 200,479 234,841
Accounts receivable-affiliates 54,392 84,327
Regulatory assets 193,641 -
Accrued unbilled revenues 66,879 16,138
Fuel, materials and
supplies, at average cost 15,621 16,226
Prepaid pension expense
and other 155,808 702,570 133,397 606,091
Deferred debits:
Regulatory assets 780,974 866,135
Other 46,250 38,133
Total assets $3,292,040 $3,241,001
========= =========
Capitalization and Liabilities
Common equity $ 834,836 $ 717,823
Accumulated other
comprehensive loss, net (117) -
Cumulative preferred stock
of subsidiary 43,000 92,279
Long-term debt 577,618 613,283
Transition property
securitization certificates 584,130 646,559
Current liabilities:
Long-term debt and
preferred stock, due
within one year $ 50,186 $ 165,667
Transition property
securitization
certificates, due
within one year 36,443 50,922
Notes payable 96,500 -
Accounts payable:
Affiliates 116,610 3,902
Other 115,783 99,738
Accrued interest 24,269 15,460
Dividends payable 993 993
Other 112,416 553,200 218,224 554,906
Deferred credits
Accumulated deferred
income taxes 590,640 484,629
Accumulated deferred
investment tax credits 20,346 21,336
Power contracts 25,868 45,123
Other 62,519 65,063
Commitments and contingencies
Total capitalization and
liabilities $3,292,040 $3,241,001
========= =========
The accompanying notes are an integral part of the consolidated
financial statements.
Boston Edison Company
Consolidated Statements of Cash Flows
(in thousands)
Years ended December 31,
2000 1999 1998
Operating activities:
Net income $ 146,028 $ 160,314 $ 157,337
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 161,371 188,078 229,668
Deferred income taxes and
investment tax credits 86,962 99,504 (152,798)
Power contract buyout - (65,781) -
Allowance for borrowed funds used
during construction (2,069) (2,011) (1,668)
Net changes in:
Accounts receivable and accrued
unbilled revenues 13,556 (50,736) 29,666
Fuel, materials and supplies 605 (1,387) 29,834
Accounts payable 128,753 (49,084) 9,834
Other current assets and liabilities (341,985) (77,628) (25,525)
Other, net (6,545) 27,828 (7,517)
Net cash provided by operating activities 186,676 229,097 268,831
Investing activities:
Plant expenditures (excluding AFUDC) (110,437) (125,419) (117,803)
Costs of nuclear divestiture, net - (87,248) -
Proceeds from sale of fossil assets - - 533,633
Nuclear fuel expenditures - (16,118) (26,182)
Investments 4,368 (6,301) (33,600)
Net cash (used in) provided by investing
activities (106,069) (235,086) 356,048
Financing activities:
Issuances:
Long-term debt - 725,000 -
Redemptions:
Preferred stock - - (71,519)
Long-term debt (251,559) (203,214) (201,600)
Net change in notes payable 96,500 - (101,878)
Dividends paid (30,960) (480,960) (171,322)
Net cash (used in) provided by financing
activities (186,019) 40,826 (546,319)
Net (decrease) increase in cash and cash
equivalents (105,412) 34,837 78,560
Cash and cash equivalents at the
beginning of the year 117,537 82,700 4,140
Cash and cash equivalents at the end of
the year $ 12,125 $ 117,537 $ 82,700
======== ======== ========
Supplemental disclosures of cash flow
information:
Interest, net of amounts capitalized $ 105,735 $ 76,926 $ 89,531
Income taxes (refunded) paid $ (47,312) $ 87 $ 79,900
The accompanying notes are an integral part of the consolidated
financial statements.
Notes to Consolidated Financial Statements
Note A. Summary of Significant Accounting Policies
1. Nature of Operations
Boston Edison Company ("Boston Edison" or "the Company") is a
regulated public utility incorporated in 1886 under Massachusetts
law and is a wholly owned subsidiary of NSTAR. NSTAR is
Massachusetts' largest investor-owned combined electric and gas
utility. NSTAR is an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including
more than one million electric customers in 81 communities and
244,000 gas customers in 51 communities. NSTAR was created
through the merger of BEC Energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25, 1999 as an exempt public
utility holding company. Its retail utility subsidiaries are
Boston Edison, Commonwealth Electric Company (ComElectric),
Cambridge Electric Light Company (Cambridge Electric), and NSTAR
Gas Company (NSTAR Gas) and its wholesale electric subsidiary is
Canal Electric Company (Canal Electric). Effective November 1,
2000, NSTAR's three retail electric companies began to operate
under the brand name "NSTAR Electric." Reference in this report
to "NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric.
Boston Edison currently supplies electricity at retail to an area
of 590 square miles, including the city of Boston and 39
surrounding cities and towns. The population of the area served
with electricity at retail is approximately 1.5 million. In
2000, Boston Edison served an average of approximately 681,000
customers. Boston Edison also supplies electricity at wholesale
for resale to other utilities and municipal electrical
departments.
2. Basis of Consolidation and Accounting
The accompanying consolidated financial statements for each
period presented include the activities of Boston Edison's wholly
owned subsidiaries, Harbor Electric Energy Company (HEEC) and BEC
Funding LLC (BEC Funding). All significant intercompany
transactions have been eliminated. Certain reclassifications have
been made to the prior year data to conform with the current
presentation.
Boston Edison follows accounting policies prescribed by the
Federal Energy Regulatory Commission (FERC) and the Massachusetts
Department of Telecommunications and Energy (MDTE). In addition,
Boston Edison is subject to the accounting and reporting
requirements of the Securities and Exchange Commission (SEC). The
accompanying consolidated financial statements conform with
Generally Accepted Accounting Principles (GAAP). As a rate-
regulated company, Boston Edison has been subject to Statement of
Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" (SFAS 71). The
application of SFAS 71 results in differences in the timing of
recognition of certain expenses from that of other businesses and
industries. The distribution business remains subject to rate-
regulation and continues to meet the criteria for application of
SFAS 71. Refer to Note B to these Consolidated Financial
Statements for more information on the accounting implications of
the electric utility industry restructuring in Massachusetts.
The preparation of financial statements in conformity with GAAP
requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosures of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
these estimates.
The Company's Board of Directors has determined and voted that a
portion of the dividends declared on June 24, 1999 and July 22,
1999, which were paid out of retained earnings to its sole
shareholder, was a partial distribution of a return of capital.
As a result, the Company has appropriately transferred the
portion of its dividends deemed return of capital against Premium
on Common Stock.
3. Revenues
Rate-regulated utility revenues are based on authorized rates
approved by the MDTE and the FERC. Estimates of retail base
(transmission, distribution and transition) revenues for
electricity used by customers but not yet billed are accrued at
the end of each accounting period. Revenues of the Company's non-
utility subsidiaries are recognized when services are rendered or
when the energy is delivered.
4. Utility Plant
Utility plant is stated at original cost of construction. The
costs of replacements of property units are capitalized.
Maintenance and repairs and replacements of minor items are
expensed as incurred. The original cost of property retired, net
of salvage value, and the related costs of removal are charged to
accumulated depreciation. Non-utility property is stated at cost
or its net realizable value.
5. Depreciation
Depreciation of utility plant is computed on a straight-line
basis using composite rates based on the estimated useful lives
of the various classes of property. Excluding the effect of the
adjustment discussed below, the overall composite depreciation
rates were 3.17%, 3.31% and 3.28% in 2000, 1999 and 1998,
respectively.
6. Costs Associated with Issuance and Redemption of Debt and
Preferred Stock
Consistent with the recovery in electric rates, discounts,
redemption premiums and related costs associated with the
issuance and redemption of long-term debt and preferred stock are
deferred. The costs related to long-term debt are recognized as
an addition to interest expense over the life of the original or
replacement debt. Consistent with an accounting order received
from the FERC, costs related to preferred stock issuances and
redemptions are reflected as a direct reduction to retained
earnings upon redemption or over the average life of the
replacement preferred stock series as applicable.
7. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant
construction. In accordance with regulatory accounting, AFUDC is
included as a cost of utility plant and a reduction of current
interest charges. Although AFUDC is not a current source of cash
income, the costs are recovered from customers over the service
life of the related plant in the form of increased revenues
collected as a result of higher depreciation expense. Average
AFUDC rates in 2000, 1999 and 1998 were 6.00%, 5.82% and 5.88%,
respectively, and represented only the cost of short-term debt.
8. Cash and Cash Equivalents
Cash and cash equivalents are comprised of liquid securities with
maturities of 90 days or less when purchased.
9. Restricted Cash
Restricted cash represents funds held in reserve for a special-
purpose trust on behalf of Boston Edison's wholly owned
subsidiary, BEC Funding LLC. If BEC Funding should have
insufficient funds to pay for extraordinary expenses, Boston
Edison would be required to make additional contributions or
loans.
10. Regulatory Assets
Regulatory assets represent costs incurred that are expected to
be collected from customers through future charges in accordance
with agreements with regulators. These costs are expensed when
the corresponding revenues are received in order to appropriately
match revenues and expenses.
Regulatory assets consisted of the following:
(in thousands)
2000 1999
Generation-related regulatory
assets, net $ 559,121 $ 613,946
Purchased power costs - 44,325
Costs to achieve 71,823 56,666
Power contracts 25,868 45,123
Income taxes, net 64,775 65,867
Postretirement benefits costs 12,040 12,822
Redemption premiums 14,403 16,008
Other 32,944 11,378
780,974 866,135
Current assets
Purchased power costs 193,641 -
Total regulatory assets $ 974,615 $ 866,135
======== ========
The current purchased power costs shown in the table above as of
December 31, 2000 is based on a recent MDTE approval of standard
offer and default service rates. It is anticipated that this
amount will be collected from customers during 2001.
11. Equity Method of Accounting
Boston Edison uses the equity method of accounting for
investments in corporate joint ventures in which it does not have
a controlling interest. Under this method, it records as income
or loss the proportionate share of the net earnings or losses of
the joint ventures with a corresponding increase or decrease in
the carrying value of the investment. The investment is reduced
as cash dividends are received.
12. Related Party Transactions
The accompanying Consolidated Balance Sheets include receivables
of $13.7 million and $10 million as of December 31, 2000 and
1999, respectively, from NSTAR Communications, Inc., an
affiliate. The receivables are for construction and construction
management services provided by Boston Edison and its
contractors. Additionally, the December 31, 2000 Consolidated
Balance Sheet also includes a $28.6 million receivable from
affiliate NSTAR Services Corporation, a $22.8 million payable to
ComElectric and Cambridge Electric relating to purchased power.
Boston Edison's goodwill amortization expense allocation from its
affiliated companies, ComElectric, Cambridge Electric and NSTAR
Gas was $8 million for 2000 as compared to $2.6 million for 1999.
The December 31, 1999 Consolidated Balance Sheet also includes a
$67 million receivable from NSTAR. This represents Boston
Edison's share of consolidated federal income tax benefits.
13. Amortization of Goodwill and Costs to Achieve
The merger of BEC and COM/Energy was accounted for as an
acquisition of COM/Energy by BEC using the purchase method of
accounting. In accordance with Accounting Principles Board (APB)
No. 16 - Business Combinations, all goodwill was recorded on the
books of the subsidiaries of COM/Energy. However, under the
merger rate plan approved by the MDTE, all of NSTAR's utility
subsidiaries share in the recovery of goodwill in their rates.
As a result, goodwill amortization expense has been allocated to
Boston Edison from ComElectric, Cambridge Electric and NSTAR Gas
through an intercompany charge. The Company is currently
recovering such amount in its rates.
Goodwill and costs to achieve related to the merger discussed in
Note B are being amortized by NSTAR over 40 years and 10 years,
respectively.
Note B. Electric Utility Industry Restructuring
1. Merger of BEC Energy and Commonwealth Energy System
NSTAR recorded goodwill associated with the merger of BEC Energy
and COM/Energy of approximately $490 million and the original
estimate of transaction and integration costs to achieve the
merger was $111 million. Boston Edison's share of goodwill and
costs to achieve are approximately $319 million and $72 million,
respectively. For NSTAR, goodwill is being amortized over 40
years and will amount to approximately $12.2 million annually,
while the cost to achieve is being amortized over 10 years and
will initially be approximately $11.1 million annually. As of
December 31, 2000, Boston Edison's portion of goodwill and costs
to achieve amortization are approximately $8 million and $7
million, respectively. Goodwill is being recovered in Boston
Edison's rates and is treated as an intercompany charge among the
Company and its affiliated companies, ComElectric, Cambridge
Electric and NSTAR Gas. The ultimate amortization of the cost to
achieve will reflect the total actual costs.
2. Accounting Implications
Under the traditional revenue requirements model, electric rates
are based on the cost of providing electric service. Under this
model, Boston Edison has been subject to certain accounting
standards that are not applicable to other businesses and
industries in general. The application of SFAS 71 requires
companies to defer the recognition of certain costs when incurred
if future rate recovery of these costs is expected.
The implementation of electric utility industry restructuring has
certain accounting implications. The highlights of these include:
a.) Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation
business are recovered through the transition charge. This
recovery occurs over a twelve-year period that began on March 1,
1998, the retail access date in Massachusetts.
b.) Depreciation
The composite depreciation rate for distribution utility plant
increased from 2.88% to 2.98% as of the retail access date.
c.) Purchased power and fuel charge
The fuel and purchased power charge ceased as of the retail
access date. The net remaining over-collection of fuel and
purchased power costs were returned to customers through March
31, 2000. These over-recovered costs are included as an offset to
the settlement recovery mechanisms and were included in
Regulatory assets on the accompanying Consolidated Balance Sheet
for 1999.
d.) Standard offer and default service charge
Customers of Boston Edison as of March 1, 1998 have the option of
continuing to buy power at standard offer prices through 2004.
The standard offer charge began at 2.8 cents/kWh at the retail
access date, increased to 3.2 cents/kWh on June 1, 1998, to 3.69
cents/kWh on January 1, 1999, to 4.5 cents/kWh on January 1, 2000
and 4.894 cents/kWh on January 1, 2001. In addition to the
annual rate filings referenced above, the Company has also made
separate filings with the MDTE concerning charges for standard
offer and default service. The Company has filed with the MDTE a
request for approval to increase its standard offer service rates
for 2001 based on a fuel adjustment formula contained in its
standard offer tariffs that reflects the prices of natural gas
and oil. On December 11, 2000, the MDTE approved an increase of
1.321 cents/kWh in addition to the standard offer rate of 4.894
cents/kWh for Boston Edison, which resulted in a standard offer
service rate of 6.215 cents/kWh. The MDTE ruled that the fuel
adjustment did not have to meet the 15% rate reduction
requirements under the Restructuring Act. The MDTE will
reexamine these rates in July 2001. The cost of providing
standard offer service includes fuel and purchased power costs.
Default service is the electricity that is supplied by the local
distribution company when a customer is not receiving power from
either standard offer service or a third-party supplier. The
market price for default service will fluctuate based on the
average market price for power. Amounts collected through
standard offer and default service rates are recovered on a fully
reconciling basis.
e.) Distribution and transmission charges
An integral part of the merger is the rate plan of the retail
utility subsidiaries of NSTAR that was approved by the MDTE on
July 27, 1999. Significant elements of the rate plan include a
four-year distribution rate freeze, recovery of the acquisition
premium (goodwill) over 40 years and recovery of transaction and
integration costs (costs to achieve) over 10 years.
Distribution rates were subject to a minimum and maximum return
on average common equity (ROE) from its distribution business
through December 31, 2000. The ROE was subject to a floor of 6%
and a ceiling of 11.75%. If the ROE is below 6%, Boston Edison is
authorized to add a surcharge to distribution rates in order to
achieve the 6% floor. If the ROE was above 11%, it was required
to adjust distribution rates by an amount necessary to reduce the
calculated ROE between 11% and 12.5% by 50%, and a return above
12.5% by 100%. No adjustment was made if the ROE was between 6%
and 11%. In addition, distribution rates continue to be subject
to adjustment for any changes in tax laws or accounting
principles that result in a change in costs of more than $1
million. No adjustments have been made to Boston Edison's
distribution rates due to either one of these rate mechanisms.
The cost of providing transmission service to distribution
customers is recovered on a fully reconciling basis.
f.) Generating Assets Divestiture
On July 13, 1999, Boston Edison completed the sale of the Pilgrim
Nuclear Generating Station to Entergy Nuclear Generating Company
(Entergy), a subsidiary of Entergy Corporation, for $81 million.
In addition to the amount received from Entergy, Boston Edison
received a total of approximately $233 million from the Pilgrim
contract customers, including $103 million from ComElectric, to
terminate their contracts. Approximately $5 million remains to be
collected under these termination agreements at December 31,
2000. This compares to $80 million at December 31, 1999. As part
of the sale, Boston Edison, the first company in the nation to
successfully sell a nuclear facility, transferred its
decommissioning trust fund to Entergy. In order to provide
Entergy with a fully funded decommissioning trust fund, Boston
Edison contributed approximately $271 million to the fund at the
time of the sale. As a result of a favorable IRS tax ruling,
Boston Edison received $43 million from Entergy reflecting a
reduction in the required decommissioning funding. The difference
between the total proceeds received and the net book value of the
Pilgrim assets sold plus the net amount to fully fund the
decommissioning trust is included in Regulatory assets on the
accompanying Consolidated Balance Sheets as such amounts are
currently being collected from customers through the year 2010
under Boston Edison's settlement agreement. The final amounts to
be collected from customers related to Pilgrim are subject to
regulatory review.
Completion of the sale of Boston Edison's fossil generating
assets took place in May 1998. Boston Edison received proceeds
from the sale of $674 million, including $121 million for a six-
month transitional power purchase contract. The amount received
above net book value on the sale of these assets is being
returned to Boston Edison's customers over the settlement period.
On July 27, 1999 BEC Funding closed the sale of $725 million of
notes to a special purpose trust created by two Massachusetts
state agencies. The trust then concurrently closed the sale of
$725 million of electric rate reduction certificates to the
public. The certificates are secured by a portion of the
transition charge assessed on Boston Edison's retail customers as
permitted under the Restructuring Act and authorized by the MDTE.
These certificates are non-recourse to Boston Edison.
Note C. Income Taxes
Income taxes are accounted for in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income
Taxes (SFAS 109). SFAS 109 requires the recognition of deferred
tax assets and liabilities for the future tax effects of
temporary differences between the carrying amounts and the tax
basis of assets and liabilities. In accordance with SFAS 109, net
regulatory assets of $64.8 million and $65.9 million and
corresponding net increases in accumulated deferred income taxes
were recorded as of December 31, 2000 and 1999, respectively. The
regulatory assets represent the additional future revenues to be
collected from customers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
December 31,
(in thousands) 2000 1999
Deferred tax liabilities:
Plant-related $ 428,813 $ 336,835
Other 322,503 311,153
751,316 647,988
Deferred tax assets:
Plant-related 15,262 14,218
Investment tax credits 12,150 13,490
Other 133,264 135,651
160,676 163,359
Net accumulated deferred income $ 590,640 $ 484,629
taxes ======= =======
Previously deferred investment tax credits are amortized over the
estimated remaining lives of the property giving rise to the
credits.
Components of income tax expense were as follows:
years ended December 31,
(in thousands) 2000 1999 1998
Current income tax expense (benefit) $ 8,890 $(29,306) $242,411
Deferred income tax expense (benefit) 87,953 122,584 (137,992)
Investment tax credit amortization (991) (2,249) (3,927)
Income taxes charged to operations 95,852 91,029 100,492
Tax benefit on other expense, net 5,046 (22,465) (17,853)
Total income tax expense $100,898 $ 68,564 $ 82,639
======= ======= =======
The effective income tax rates reflected in the consolidated
financial statements and the reasons for their differences from
the statutory federal income tax rate were as follows:
2000 1999 1998
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of
federal income tax benefit 4.4 4.3 4.6
Investment tax credit amortization (0.4) (10.1) (6.2)
Other 1.8 0.8 1.0
Effective tax rate 40.8% 30.0% 34.4%
===== ===== ====
Income tax expense is reflected net of $20.8 million in 1999 and
$10.9 million in 1998, representing investment tax credits
recognized as a result of generation asset divestitures.
Excluding this shareholder benefit, the effective tax rate would
have been approximately 39% in each year.
Note D. Pensions and Other Postretirement Benefits
1. Pensions
The Company participates in a defined benefit funded retirement
plan that covers substantially all employees. The Company also
maintains unfunded supplemental retirement plans for certain
management employees of Boston Edison. Effective January 1,
2000, the defined benefit plan was amended to reflect the impact
of the transition of all NSTAR union locals to the pension
benefits provided under the Local 369 formula. This amendment is
reflected in the December 31, 2000 benefit obligation.
Effective January 1, 2000, the COM/Energy defined benefit plan
merged into the Company's plan and was subsequently renamed as
"The NSTAR Pension Plan." The defined benefit plan was also
amended to provide management employees lump sum benefits under a
final average pay pension equity formula. Prior to January 1,
2000, these pension benefits were provided under a traditional
final average pay formula. This amendment is reflected in the
December 31, 1999 benefit obligation.
The changes in the benefit obligation and plan assets were as
follows:
December 31,
(in thousands) 2000 1999
Change in benefit obligation:
Benefit obligation, beginning of the year $ 389,597 $ 497,988
Merger with COM/Energy Plan 410,487 -
Service cost 14,636 13,137
Interest cost 59,798 31,658
Plan participants' contributions 81 170
Plan amendments (4,387) (6,616)
Actuarial loss/(gain) 59,815 (51,648)
Curtailment loss - 8,156
Special termination benefit - 8,158
Settlement payments (77,256) (92,484)
Benefits paid (48,413) (18,922)
Benefit obligation, end of the year $ 804,358 $ 389,597
======== =========
(in thousands)
Change in plan assets: 2000 1999
Fair value of plan assets, beginning of
the year $ 536,216 $ 474,552
Merger with COM/Energy Plan 419,282 -
Actual (loss)/return on plan assets, net (28,041) 114,724
Employer contribution 44,338 58,176
Plan participants' contributions 81 170
Settlement payments (77,256) (92,484)
Benefits paid (48,413) (18,922)
Fair value of plan assets, end of the year $ 846,207 $ 536,216
======== =========
The plans' funded status was as follows:
December 31,
(in thousands) 2000 1999
Funded status $ 41,849 $146,619
Unrecognized actuarial net loss/(gain) 104,817 (32,625)
Unrecognized transition obligation 2,182 2,783
Unrecognized prior service (benefit)/cost (3,340) 6,341
Net amount recognized $145,508 $123,118
======== ========
Amounts recognized in the Consolidated Balance Sheets consisted
of:
2000 1999
(in thousands)
Prepaid retirement cost $ 149,890 $125,664
Accrued supplemental retirement liability (13,306) (8,232)
Intangible asset 7,285 5,686
Accumulated other comprehensive income 1,639 -
Net amount recognized $ 145,508 $123,118
======= =======
The projected benefit obligation, accumulated benefit obligation
and fair value of plan assets for the supplemental retirement
plan with accumulated benefit obligations in excess of plan
assets were $14,067,000, $13,306,000 and $0, respectively, as of
December 31, 2000, and $10,325,000, $8,232,000 and $0,
respectively, as of December 31, 1999.
Weighted average assumptions were as follows:
2000 1999 1998
Discount rate at the end of the year 7.50% 8.00% 6.50%
Expected return on plan assets for
the year (net of investment expenses) 9.30% 9.00% 9.00%
Rate of compensation increase at the
end of the year 4.00% 4.00% 4.00%
Components of net periodic benefit cost were as follows:
(in thousands) 2000 1999 1998
Service cost $ 14,636 $ 13,137 $13,645
Interest cost 59,798 31,658 31,981
Expected return on plan assets (85,884) (41,295) (39,140)
Amortization of prior service cost 448 1,610 1,847
Amortization of transition obligation 601 664 860
Recognized actuarial loss - 3,754 808
Net periodic benefit (income)/cost $(10,401) $ 9,528 $10,001
======= ======= ======
As a result of merger-related separation agreements and nuclear
divestiture, amounts recognized for curtailment, settlement and
special termination benefit costs were $9,555,000, $930,000 and
$8,158,000, respectively, for 1999. In addition, $9,623,000 was
recognized as a result of pension settlements in 2000. The
majority of these charges will be recovered from customers and is
a component of Regulatory assets on the accompanying Consolidated
Balance Sheets. The amounts resulting from the merger-related
separation agreements and generation divestitures are recoverable
under the Boston Edison settlement agreement.
Boston Edison also provides defined contribution 401(k) plans for
substantially all employees. Matching contributions (which are
equal to 50% of the employees' deferral up to 8% of compensation)
included in the accompanying Consolidated Statements of Income
amounted to $4 million in 2000 and $8 million in both 1999 and
1998.
2. Other Postretirement Benefits
In addition to pension benefits, Boston Edison also provides
health care and other benefits to retired employees who meet
certain age and years of service eligibility requirements. These
benefits include health and life insurance coverage and
reimbursement of certain Medicare premiums. Under certain
circumstances, eligible employees are required to make
contributions for postretirement benefits. Effective January 1,
2001, amendments were added to reflect negotiated changes to
Local 369 as well as the impact of the transition of primarily
all NSTAR union locals to the benefits provided under the Local
369 formula. These amendments are reflected in the December 31,
2000 benefit obligation. Effective January 1, 2000, an amendment
was added to include certain new managed care features. This
amendment is reflected in the December 31, 1999 benefit
obligation.
The changes in benefit obligation and plan assets were as
follows:
(in thousands) 2000 1999
Change in benefit obligation:
Benefit obligation, beginning of the year $ 221,415 $ 258,756
Service cost 2,100 4,043
Interest cost 17,816 17,848
Plan participants' contributions 754 -
Plan amendments 5,419 (12,271)
Actuarial loss/(gain) 22,129 (26,154)
Curtailment loss - 1,408
Settlement payments - (5,810)
Benefits paid (14,024) (16,405)
Benefit obligation, end of the year $ 255,609 $ 221,415
======== ========
Change in plan assets:
Fair value of plan assets, beginning of
the year $ 119,838 $ 113,818
Actual (loss)/return on plan assets (12,276) 18,355
Employer contribution 53,407 9,880
Plan participants' contributions 754 -
Settlement payments - (5,810)
Benefits paid (14,024) (16,405)
Fair value of plan assets, end of the
year $ 147,699 $ 119,838
======== ========
The plans' funded status and amounts recognized in the
accompanying Consolidated Balance Sheets were as follows:
(in thousands) 2000 1999
Funded status $(107,910) $(101,577)
Unrecognized actuarial net loss/(gain) 36,907 (8,732)
Unrecognized transition obligation 67,400 73,016
Unrecognized prior service cost ( 13,378) (20,363)
Net amount recognized $ (16,981) $ (57,656)
======= =======
Weighted average assumptions were as follows:
2000 1999 1998
Discount rate at the end of the year 7.50% 8.00% 6.50%
Expected return on plan assets
for the year 9.00% 9.00% 9.00%
For measurement purposes an 11% weighted annual rate of increase
in per capita cost of covered medical claims was assumed for
2001. This rate is assumed to decrease gradually to 5% in 2012
and remain at that level thereafter. Dental claims and Medicare
premiums are assumed to increase at a weighted annual rate of 4%
and 5%, respectively.
A 1% change in the assumed health care cost trend rate would have
the following effects:
One-Percentage-Point
(in thousands) Increase Decrease
Effect on total of service and interest
costs components for 2000 $ 2,805 $ (2,102)
Effect on December 31, 2000
postretirement benefit obligation $34,270 $(26,703)
Components of net periodic benefit cost were as follows:
(in thousands) 2000 1999 1998
Service cost $ 2,100 $ 4,043 $ 3,892
Interest cost 17,816 17,848 16,895
Expected return on plan assets (11,234) (10,107) (8,563)
Amortization of prior service cost (1,566) (683) (942)
Amortization of transition obligation 5,616 6,162 8,474
Recognized actuarial loss - 957 662
Net periodic benefit cost $ 12,732 $ 18,220 $20,418
======= ====== =======
As a result of merger-related separation packages and nuclear
divestiture, amounts recognized for curtailment and settlement
costs were $8,114,000 and $172,000, respectively, for 1999. As a
result of the nuclear divestiture, amounts recognized for
curtailment and special termination benefit costs were
$21,187,000 and $79,000, respectively, for 1998. The amounts
resulting from the merger-related separation packages are
recoverable as part of the approved rate plans of the retail
utility subsidiaries of NSTAR. The amounts resulting from the
nuclear divestiture are recoverable under the Boston Edison
settlement agreement.
Note E. Capital Stock
(dollars in thousands, except per share amounts) 2000 1999
Common equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 100
shares issued and outstanding $ - $ -
Premium on common stock 475,721 716,361
Retained earnings 352,832 1,462
Total common equity $ 828,553 $ 717,823
======= =======
Cumulative Preferred Stock
Par value $100 per share, 2,890,000 shares authorized; issued and
outstanding:
Non-mandatory redeemable series:
Current Shares Redemption December 31,
Series Outstanding Price/Share 2000 1999
4.25% 180,000 $103.625 $18,000 $18,000
4.78% 250,000 $102.80 25,000 25,000
Total non-mandatory redeemable 43,000 43,000
series
Mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
8.00% 500,000 $100.00 50,000 50,000
Less redemption and issuance costs 481 721
Total mandatory redeemableseries 49,519 49,279
92,519 92,279
Less amount due within one year 49,519 -
Total cumulative preferred stock $43,000 $92,279
====== ======
1. Common Shares
Common shares issuances and repurchases in 1998 through 2000 were
as follows:
Common Shares
Number of
(in thousands) Shares Par Value Premium
Balance at December 31, 1997 48,515 $ 48,515 $ 696,137
Dividends to BEC Energy (48,515) (48,515) 48,516
Stock incentive plan (2,109)
Balance at December 31,1998 - - 742,544
Reclassification of
retained earnings at merger (25,000)
Stock incentive plan (1,183)
Balance at December 31,1999 - - 716,361
Reclassification of return
of capital dividends (a) (226,541)
Return of capital dividends (10,000)
Merger of COM/Energy's
pension plan 6,283
Stock incentive plan (4,099)
Balance at December 31, 2000 - $ - $ 482,004
======= ======= ========
(a) The Company's Board of Directors has determined and voted
that a portion of the dividends declared on June 24, 1999 and
July 22, 1999, which were paid out of retained earnings to its
sole shareholder, was a partial distribution of a return of
capital. As a result, the Company has appropriately transferred
the portion of its dividends deemed return of capital against
Premium on Common Stock.
2. Cumulative Mandatory Redeemable Preferred Stock
Boston Edison is not able to redeem any part of the 500,000
shares of 8% series cumulative preferred stock prior to December
2001. The entire series is subject to mandatory redemption in
December 2001 at $100 per share plus accrued dividends.
Boston Edison is not able to redeem any part of the 500,000
shares of 8% series cumulative preferred stock prior to December
2001. The entire series is subject to mandatory redemption in
December 2001 at $100 per share plus accrued dividends.
Note F. Indebtedness
December 31,
(in thousands) 2000 1999
Long-term debt
Debentures:
6.80%, due February 2000 $ - $ 65,000
6.05%, due August 2000 - 100,000
6.80%, due March 2003 150,000 150,000
7.80%, due May 2010 125,000 125,000
9.875%, due June 2020 - 34,035
9.375%, due August 2021 24,270 24,270
8.25%, due September 2022 60,000 60,000
7.80%, due March 2023 181,000 181,000
Sewage facility revenue bonds, due 23,014 24,645
through 2015 Massachusetts
Industrial Finance Agency (MIFA) bonds:
5.75%, due February 2014 15,000 15,000
Transition Property Securitization
Certificates:
5.99%, due March 2003 4,073 80,981
6.45%, due September 2005 170,610 170,610
6.62%, due March 2007 103,390 103,390
6.91%, due September 2009 170,876 170,876
7.03%, due March 2012 171,624 171,624
1,198,857 1,476,431
Amounts due within one year (37,109) (216,589)
Total long-term debt $ 1,161,748 $ 1,259,842
=========== ===========
1. Long-term Debt
The 9.375% series due 2021 are first redeemable in August 2001 at
104.612%, the 8.25% series due 2022 are first redeemable in
September 2002 at 103.780% and the 7.80% series due 2023 are
first redeemable in March 2003 at 103.730%. None of the other
series are redeemable prior to maturity. There is no sinking
fund requirement for any series of debentures.
Sewage facility revenue bonds were issued by HEEC. The bonds are
tax-exempt, subject to annual mandatory sinking fund redemption
requirements and mature through 2015. Scheduled redemptions of
$1.6 million were made in 2000 and 1999. The weighted average
interest rate of the bonds was 7.3%. A portion of the proceeds
from the bonds is in a reserve with the trustee. If HEEC should
have insufficient funds to pay for extraordinary expenses, Boston
Edison would be required to make additional capital contributions
or loans to the subsidiary up to a maximum of $1 million.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable
beginning in February 2004 at a redemption price of 102%. The
redemption price decreases to 101% in February 2005 and to par in
February 2006.
Boston Edison's Financing Application with the MDTE was approved
in October 2000 for authorization to issue from time to time up
to $500 million of debt securities through 2002. Proceeds from
such issuances covered under this approved financing will be used
for repayment or refinancing of certain outstanding equity
securities, long-term indebtedness, and for other corporate
purposes. On February 20, 2001, Boston Edison filed a
registration statement on Form S-3 with the SEC, using a shelf
registration process, to issue up to $500 million in debt
securities. The registration statement was declared effective by
the SEC on February 28, 2001. When issued, Boston Edison will
use the proceeds to pay at maturity long-term debt and equity
securities, refinance short-term debt and for other corporate
purposes.
The aggregate principal amounts of Boston Edison's long-term debt
(including securitization certificates and HEEC sinking fund
requirements) due through 2005 are approximately $63.1 million in
2001, $71.8 million in 2002, $219.7 million in 2003, $70.4
million in 2004 and $70.1 in 2005.
In 1999, BEC Funding issued notes in the principal amount of $725
million to a special purpose trust created by two Massachusetts
state agencies in exchange for the net proceeds from the sale of
$725 million of Rate Reduction certificates issued by the trust
on July 29, 1999.
2. Short-term Debt
Boston Edison has regulatory approval from the FERC to issue up
to $350 million of short-term debt. Boston Edison also has a
$200 million revolving credit agreement with a group of banks
effective through December 31, 2001. In addition, the Company
has a $100 million line of credit. Both of these arrangements
serve as back-up to Boston Edison's $300 million commercial paper
program. As of December 31, 2000, there was $97 million
outstanding under its commercial paper program. There was no
amount outstanding under this program as of December 31, 1999.
Under the terms of this agreement, Boston Edison is required to
maintain a common equity ratio of not less than 30% at all times.
Commitment fees must be paid on the total agreement amount. The
Company was in compliance with these requirements for 2000 and
1999.
Information regarding consolidated short-term borrowings was as
follows:
(dollars in thousands) 2000 1999 1998
Maximum short-term borrowings $191,000 $221,000 $219,000
Weighted average amount
outstanding $ 96,500 $ 2,860 $ 51,483
Weighted average interest rates
excluding commitment fees 6.61% 5.20% 5.81%
Note G. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the
fair value of each class of securities for which it is
practicable to estimate the value:
Cash and cash equivalents
The carrying amount of $12 million and $118 million, for the
years 2000 and 1999, respectively, approximates fair value due to
the short-term nature of these securities.
Mandatory redeemable cumulative preferred stock
The fair values of these securities are based upon the quoted
market prices of similar issues. Carrying amounts and fair values
were as follows:
2000 1999
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Mandatory redeemable
cumulative preferred stock $ 49,519 $ 50,890 $ 49,279 $ 52,250
Long-term unsecured debt $1,198,857 $1,198,695 $1,476,431 $1,500,340
Note H. Segment and Related Information
Statement of Financial Accounting Standards No. 131, Disclosures
about Segments of an Enterprise and Related Information, requires
the disclosure of certain financial and descriptive information
by operating segments. Boston Edison operates primarily as a
regulated electric public utility for which separate segment
information is not applicable.
Note I. Commitments and Contingencies
1. Contractual Commitments
At December 31, 2000, Boston Edison had estimated contractual
obligations for plant and equipment of approximately $104
million.
Boston Edison also has leases for certain facilities and
equipment. The estimated minimum rental commitments under both
transmission agreements and non-cancelable leases for the years
after 2000 are as follows:
(in thousands)
2001 $ 17,007
2002 16,579
2003 12,991
2004 12,291
2005 12,300
Years thereafter 55,502
Total $126,670
========
The total expense for both lease rentals and transmission
agreements was $45.3 million in 2000, $38.7 million in 1999 and
$29.4 million in 1998, net of capitalized expenses of $1.7
million in 2000, $1.5 million in 1999 and $1.3 million in 1998.
2. Equity Investments
Boston Edison has an equity investment of approximately 11% in
two companies that own and operate transmission facilities to
import electricity from the Hydro-Quebec system in Canada. As an
equity participant, Boston Edison is required to guarantee, in
addition to its own share, the total obligations of those
participants who do not meet certain credit criteria. At
December 31, 2000, Boston Edison's portion of these guarantees
was $8 million.
Boston Edison has a 9.5% equity investment of approximately $1
million in Yankee Atomic Electric Company (Yankee Atomic). In
1992, the board of directors of Yankee Atomic voted to
discontinue operations of the Yankee Atomic nuclear generating
station permanently and decommission the facility. Yankee Atomic
received approval from the FERC to continue to collect its
investment and decommissioning costs through July 9, 2000, the
expiration date of the unit's power contracts. Also, as of that
date, the equity owners of the unit completed the recovery of
closure (decommissioning) costs and net unrecovered assets.
Subsequently, Yankee Atomic initiated a stock buy-back program,
approved by the SEC, to redeem 95% of the outstanding stock of
Yankee Atomic. Through December 31, 2000, 50% of the 95% of
shares outstanding, or 72,866 shares, were redeemed. Boston
Edison's reduction of its equity ownership resulting from the buy-
back of 6,922 shares was approximately $692,000.
Boston Edison also has a 9.5% equity investment in Connecticut
Yankee Atomic Power Company (CYAPC) of approximately $7 million.
In December 1996, the board of directors of CYAPC, which owns and
operates the Connecticut Yankee nuclear electric generating unit
(Connecticut Yankee), unanimously voted to retire the unit.
Boston Edison's share of Connecticut Yankee's remaining
investment and estimated costs of decommissioning is
approximately $26 million as of December 31, 2000. This estimate
is recorded on the accompanying Consolidated Balance Sheets as a
Power contract liability and an offsetting Regulatory asset.
In December 1996, CYAPC filed for rate relief at the FERC seeking
to recover certain post-operating costs, including
decommissioning. In August 1998, the FERC Administrative Law
Judge (ALJ) released an initial decision regarding CYAPC's
filing. This decision called for the disallowance of the common
equity return on the CYAPC investment subsequent to the shutdown.
The decision also stated that decommissioning collections should
continue to be based on a previously approved estimate, with an
adjustment for inflation, until a more reliable estimate is
developed. In October 1998, both CYAPC and Northeast Utilities,
a 49% equity investor in CYAPC, filed briefs on exceptions to the
ALJ decision. The case is still pending before the FERC. If the
initial decision is upheld by the FERC, CYAPC could be required
to write off a portion of its investment in the generating unit
and refund a portion of the previously collected return on
investment to ratepayers. Management is currently unable to
determine the ultimate outcome of this proceeding. However, the
estimate of the effect of the ALJ's initial decision does not
have a material impact on the Company's consolidated financial
position or results of operations.
3. Environmental Matters
Boston Edison is involved in approximately 16 state-regulated
properties where oil or other hazardous materials were previously
spilled or released. Boston Edison is required to clean up these
properties in accordance with specific state regulations. There
are uncertainties associated with these costs due to the
complexities of cleanup technology, regulatory requirements and
the particular characteristics of the different sites. Boston
Edison also continues to have potential liability as a
potentially responsible party in the cleanup of five multi-party
hazardous waste sites in Massachusetts and other states where it
is alleged to have generated, transported or disposed of
hazardous waste at the sites. Boston Edison generally expects to
have only a small percentage of the total potential liability for
these sites. Approximately $5 million is included in the
Consolidated Balance Sheets as of December 31, 2000 related to
these cleanup liabilities. Management is unable to fully
determine a range of reasonably possible cleanup costs in excess
of the accrued amount. Based on its assessments of the specific
site circumstances, management does not believe that it is
probable that any such additional costs will have a material
impact on the Company's consolidated financial position. However,
it is reasonably possible that additional provisions for cleanup
costs that may result from a change in estimates could have a
material impact on the results of operations for a reporting
period in the near term.
Estimates related to environmental remediation costs are reviewed
and adjusted periodically as further investigation and assignment
of responsibility occurs. Boston Edison is unable to estimate its
ultimate liability for future environmental remediation costs.
However, in view of Boston Edison's current assessment of its
environmental responsibilities, existing legal requirements and
regulatory policies, management does not believe that these
matters will have a material adverse effect on Boston Edison's
financial position or results of operations for a reporting
period.
4. Legal Proceedings
Industry and corporate restructuring legal proceedings
The MDTE order approving Boston Edison's restructuring settlement
agreement was appealed by certain parties to the SJC. One appeal
remains pending. However, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this
proceeding. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows or results of
operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE,
the Massachusetts Attorney General contested cost allocations
related to Boston Edison's wholesale customers since 1998.
Management is unable to determine the timing and the outcome of
this proceeding. However, if an unfavorable outcome were to
occur, there would be a material adverse impact on Boston
Edison's consolidated financial position, results of operations
and cash flows for a reporting period.
In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with the 1993 order that permitted the
formation of Boston Energy Technology Group and authorized
Boston Edison to invest up to $45 million in non-utility
activities. Hearings were completed during 1999 and no further
developments have occurred as of this time. Management is
currently unable to determine the timing and the outcome of
this proceeding. However, if an unfavorable outcome were to
occur, there could be a material adverse impact on business
operations, the consolidated financial position, cash flows
and results of operations for a reporting period.
Other litigation
In the normal course of its business, Boston Edison is also
involved in certain other legal matters. Management is unable to
fully determine a range of reasonably possible legal costs in
excess of amounts accrued. Based on the information currently
available, it does not believe that it is probable that any such
additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that
additional legal costs that may result from a change in estimates
could have a material impact on the results of a reporting
period.
Note J. Long-Term Power Contracts
Long-Term Contracts for the Purchase of Electricity
Boston Edison entered into a six-month agreement effective
January 1, 2000 to transfer all of the unit output entitlements
in long-term power purchase contracts to Select Energy (Select),
a subsidiary of Northeast Utilities. In return, Select provided
full energy service requirements to Boston Edison, including
NEPOOL capability responsibilities, at FERC approved tariff rates
to meet its standard offer and default service load requirements
through June 30, 2000. Subsequently, Boston Edison entered into
two similar six-month agreements to meet the Company's standard
offer and default service load requirements that extended to
December 31, 2000. Boston Edison entered into a six-month
agreement effective January 1, 2001 through June 30, 2001 with a
supplier to provide full default service energy and ancillary
service requirements. A default service request for proposal,
applicable for default service power supply beginning July 1,
2001, was issued in early 2001. NSTAR Electric's existing
portfolio of power purchase contracts is supplying the majority
of Boston Edison's standard offer (including wholesale) energy
requirements, supplemented with long-term and daily
purchases/sales in the bilateral and spot markets. In addition,
NSTAR is managing its NEPOOL capability responsibilities,
congestion and uplift costs associated with default service and
standard offer load throughout 2001.
Information relating to the contracts as of December 31, 2000 was
as follows:
proportionate share (in thousands)
Units of Capacity Charge
Capacity 2000 2000 Obligation
Contract Purchased Capacity Total Through Contract
Generating Unit Date % MW Cost Cost Expiration Date
Canal Unit 1 2002 25.0 141 $ 8,717 $34,259 $ 17,728
Mass Bay Transportation
Authority - 1 2005 100.0 34 720 865 3,366
Ocean State Power
Unit 1 2010 23.5 72 11,360 20,689 194,226
Ocean State Power
Unit 2 2011 23.5 72 12,470 21,528 204,365
Northeast Energy
Associates (a) (a) 219 - 131,236 -
Entergy (Pilgrim) 2004 78.0 673 (b) 163,383 (b)
MassPower 2013 44.3 117 39,258 55,465 669,624
Mass Bay Transportation
Authority - 2 2019 100.0 34 357 505 41,732
Total $ 2,882 $427,930 $1,131,041
====== ======= =========
(a) Boston Edison purchases 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. Energy is paid for based on a price per kWh
actually received. Boston Edison does not pay a proportionate
share of the unit's capital and fixed operating costs.
(b) Boston Edison pays for this energy based on a price per kWh
actually received. Boston Edison does not pay a proportionate
share of the unit's capital and fixed operating costs.
Boston Edison's total capacity and energy costs associated with
these contracts in 2000, 1999 and 1998 were approximately $428
million, $315 million and $239 million, respectively. Boston
Edison's capacity charge obligation under these contracts for the
years after 2000 is as follows:
Capacity
(in thousands) Charge
Obligation
2001 $ 91,326
2002 90,654
2003 85,342
2004 85,117
2005 86,531
Years thereafter 692,071
Total $1,131,041
=========
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements: Page
Consolidated Statements of Income for the years ended
December 31, 2000, 1999 and 1998 19
Consolidated Statements of Comprehensive Income for
the years ended December 31, 2000, 1999 and 1998 20
Consolidated Statements of Retained Earnings for the
years ended December 31, 2000, 1999 and 1998 20
Consolidated Balance Sheets as of December 31, 2000
and 1999 21
Consolidated Statements of Cash Flows for the years
ended December 31, 2000, 1999 and 1998 22
Report of Independent Accountants 18
Notes to Consolidated Financial Statements 23
2. Financial Statement Schedules:
Schedule II Valuation and Qualifying Accounts - For
the Years Ended December 31, 2000, 1999 and 1998 51
3. Exhibits:
Refer to the exhibits listing beginning on the
following page 42
(b) Reports on Form 8-K
None
Incorporated herein by reference:
Exhibit SEC Docket
Exhibit 3 Articles of Incorporation and
By-Laws
3.1 Restated Articles of 3.1 1-2301
Organization Form 10-Q
for the
quarter
ended June
30, 1994.
3.2 Boston Edison Company Bylaws 3.1 1-2301
April 19, 1977, as amended Form 10-Q
January 22, 1987, January 28, for the
1988, May 24, 1988 and quarter
November 22, 1989 ended June
30, 1994.
Exhibit 4 Instruments Defining the
Rights of Security Holders,
Including Indentures
4.1 Medium-Term Notes Series A - 4.1 1-2301
Indenture dated September 1, Form 10-Q
1988, between Boston Edison for the
Company and Bank of Montreal quarter
Trust Company ended
September
10, 1988.
4.1.1 First Supplemental Indenture 4.1 1-2301
dated June 1, 1990 to Form 8-K
Indenture dated September 1, dated June
1988 with Bank of Montreal 28, 1990.
Trust Company - 9 7/8%
debentures due June 1, 2020
4.2 Indentures of Trust and 4.1.26 1-2301
Agreement among the City of Form 10-K
Boston, Massachusetts (acting for the
by and through its Industrial year ended
Development Financing December
Authority) and Harbor 31, 1991.
Electric Energy Company and
Shawmut Bank, N.A., as
Trustees dated November 1,
1991.
4.3 Votes of the Pricing 4.1.27 1-2301
Committee of the Board of Form 10-K
Directors of Boston Edison for the
Company taken August 5, 1991 year ended
re 9 3/8% debentures due December
August 15, 2021. 31, 1991.
4.4 Revolving Credit Agreement 4.1.24 1-2301
dated February 12, 1993. Form 10-K
for the
year ended
December
31, 1992.
4.4.1 First Amendment to Revolving 4.1.10 1-2301
Credit Agreement dated May Form 10-K
19, 1995 for the
year ended
December
31, 1995.
4.4.2 Second Amendment to Revolving 4.1.4.2 1-2301
Credit Agreement dated July Form 10-K
1, 1997 for the
year ended
December
31, 1997.
4.5 Votes of the Pricing 4.1.25 1-2301
Committee of the Board of Form 10-K
Directors of Boston Edison for the
Company taken September 10, year ended
1992 re 8 1/4% debentures due December
September 15, 2022. 31, 1992.
4.6 Votes of the Pricing 4.1.27 1-2301
Committee of the Board of Form 10-K
Directors of Boston Edison for the
Company taken March 5, 1993 year ended
re 6.80% debentures due March December
15,2003, 7.80% debentures due 31, 1992.
March 15, 2023
4.7 Votes of the Pricing 4.1.5 1-2301
Committee of the Board of Form 10-K
Directors of Boston Edison for the
Company taken May 18, 1995 re year ended
7.80% debentures due May 15, December
2010. 31, 1995.
4.8 Debt Securities issued under Form S-3 -
an Indenture between Boston Registration
Edison Company and The Bank Statement,
of New York (as successor to filed
Bank of Montreal Trust Company) February
3, 1993,
File No.
33-57840.
4.9 Debt Securities to be issued Form S-3 -
on a delayed or continuous Registration
basis under an Indenture Statement,
between Boston Edison Company dated
and The Bank of New York (as February
successor to Bank of Montreal 20, 2001,
Trust Company) File No.
333-55890.
Management agrees to furnish to the Securities and Exchange
Commission, upon request, a copy of any other agreements or
instruments of the Registrant defining the rights of holders of
any long-term debt whose authorization does not exceed 10% of
total assets.
Exhibit 10 Material Contracts
10.1 Boston Edison Company 10.11 1-2301
Deferred Fee Plan dated Form 10-K
January 14, 1993 for the
year ended
December
31, 1992.
10.2 Deferred Compensation Trust 10.10 1-2301
between Boston Edison Company Form 10-K
and State Street Bank and for the
Trust Company dated February year ended
2, 1993. December
31, 1993.
10.2.1 Amendment No. 1 to Deferred 10.5.1 1-2301
Compensation Trust dated Form 10-K
March 31, 1994 for the
year ended
December
31, 1994.
10.3 Employment Agreement 10.18 1-2301
applicable to Ronald A. Form 10-K
Ledgett dated April 30, for the
1987 year ended
December
31, 1994.
10.4 Boston Edison Company 10.12 1-2301
Restructuring Settlement Form 10-K
Agreement dated July 1997 for the
year ended
December
31, 1997.
10.5 Boston Edison Company and 10.1 1-2301
Sithe Energies, Inc. Purchase Form 10-Q
and Sale and Transition for the
Agreements dated December 10, quarter
1997. ended March
31, 1998.
10.6 Boston Edison Company 10.11 1-2301
Directors' Deferred Fee Plan Form 10-K
Restatement effective October for the
1, 1998. year ended
December
31, 1999.
10.7 Boston Edison Company and 10.12 1-2301
Entergy Nuclear Generation Form 10-K
Company Purchase and Sale for the
Agreement dated November 18, year ended
1998. December
31, 1999.
10.8 NSTAR Excess Benefit Plan 10.1 1-14768
effective August 25, 1999. (NSTAR)
Form 10-K/A
for the
year ended
December
31, 1999.
10.9 NSTAR Supplemental Executive 10.2 1-14768
Retirement Plan effective (NSTAR)
August 25, 1999. Form 10-K/A
for the
year ended
December
31, 1999.
10.10 Special Supplemental 10.3 1-14768
Executive Retirement (NSTAR)
Agreement between Boston Form 10-K/A
Edison Company and Thomas J. for the
May dated March 13, 1999, year ended
regarding Key Executive December
Benefit Plan and Supplemental 31, 1999.
Executive Retirement Plan.
10.11 Key Executive Benefit Plan 10.4 1-14768
Agreement dated as of October (NSTAR)
1, 1983 between Boston Edison Form 10-K/A
Company and Thomas J. May. for the
year ended
December
31, 1999.
10.12 Key Executive Benefit Plan 10.5 1-14768
Agreement dated September 1, (NSTAR)
1989 between Boston Edison Form 10-K/A
Company and Ronald A. for the
Ledgett. year ended
December
31, 1999.
10.13 Change in Control Agreement 10.9 1-14768
between NSTAR and Thomas J. (NSTAR)
May dated May 11, 1999. Form 10-K/A
for the
year ended
December
31, 1999.
10.14 Change in Control Agreement 10.10 1-14768
between NSTAR and Russell D. (NSTAR)
Wright dated May 11, 1999. Form 10-K/A
for the
year ended
December
31, 1999.
10.15 NSTAR Deferred Compensation 10.12 1-14768
Plan (Restated Effective (NSTAR)
August 25, 1999). Form 10-K/A
for the
year ended
December
31, 1999.
10.16 NSTAR 1997 Share Incentive 10.14 1-14768
Plan, as amended. (NSTAR)
Form 10-K/A
for the
year ended
December
31, 1999.
10.17 Waiver and Employment NSTAR Form
Agreement among Commonwealth 10-Q for
Energy System and certain of the quarter
its Subsidiaries, Deborah A. ended
McLaughlin and NSTAR, dated September
September 21, 2000 30, 2000,
File No. 1-
14768.
10.18 Change in Control Agreement NSTAR Form
between James J. Judge and 10-Q for
NSTAR, dated August 28, 2000 the quarter
ended
September
30, 2000,
File No. 1-
14768
10.19 Change in Control Agreement NSTAR Form
between Deborah A. McLaughlin 10-Q for
and NSTAR, dated September the quarter
21, 2000 ended
September
30, 2000,
File No. 1-
14768
10.20 Master Trust Agreement NSTAR Form
between NSTAR and State 10-Q for
Street Bank and Trust Company the quarter
(Rabbi Trust), dated August ended
25, 1999 September
30, 2000,
File No. 1-
14768
Filed herewith:
Exhibit 12 Statement to Computation of
Ratios
12.1 Computation of Ratio of 1-2301
Earnings to Fixed Charges for Form 10-K
the Year Ended December 31, for the
2000 year ended
December
31, 2000.
12.2 Computation of Ratio of 1-2301
Earnings to Fixed Charges and Form 10-K
Preferred Stock Dividend for the
Requirements for the Year year ended
Ended December 31, 2000 December
31, 2000.
Incorporated herein by reference:
Exhibit 21 Subsidiaries of the
Registrant
21.1 Harbor Electric Energy I-2301
Company (incorporated in Form 10-K
Massachusetts), a wholly for the
owned subsidiary of Boston year ended
Edison Company December
31, 1999
Filed herewith:
Exhibit 23 Consent of Independent
Accountants
23.1 Consent of Independent 1-2301
Accountants to incorporate by Form 10-K
reference their opinion for the
included with this Form year ended
10-K in the Form S-3 December
Registration Statements filed 31, 2000.
by Boston Edison Company on
February 1, 1993 (File No. 33-
57840) and February 20, 2001
(File No. 333-55890).
Incorporated herein by reference:
Exhibit 99 Additional Exhibits
99.1 Settlement Agreement between 28.1 1-2301
Boston Edison Company and Form 8-K
Commonwealth Electric dated
Company, Montaup Electric December
Company the Municipal Light 21, 1989
Department of the Town of
Reading, Massachusetts, dated
January 5, 1990.
99.2 Settlement Agreement Between 28.2 1-2301
Boston Edison Company and Form 10-Q
City of Holyoke Gas and for the
Electric Department et. Al., quarter
dated April 24, 1990. ended March
31, 1990
99.3 Information required by SEC 1-2301
Form 11-K for certain Form 10-K/A
employee benefit plans for Amendments
the years ended December 31, to Form 10-
1997, 1996 and 1995. K for the
years ended
December
31, 1997,
1996 and
1995 dated
June 25,
1998, June
26, 1997
and June
27, 1996
respectively.
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998
Balance at Provisions Deductions Balance
Beginning Charged to Accounts At End
Description Of Year Operations Recoveries Written Off Of Year
Year Ended December 31, 2000
Allowance for
DoubtfulAccounts $19,380 $11,954 $ 471 $(9,390) $22,415
Year Ended December 31, 1999
Allowance for
Doubtful Accounts $ 9,071 $22,649 $ 4,356 $(16,696) $19,380
Year Ended December 31,1998
Allowance for
Doubtful Accounts $10,233 $ 9,555 $ 4,242 $(14,959) $9,071
FORM 10-K DECEMBER 31, 2000
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
(Registrant)
By: /s/THOMAS J. MAY
Thomas J. May,
Chairman of the Board
and Chief Executive Officer
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 and on the
dates indicated.
Principal Executive Officers:
/s/THOMAS J. MAY March 29, 2001
Thomas J. May,
Chairman of the Board and
Chief Executive Officer
/s/RUSSELL D. WRIGHT March 29, 2001
Russell D. Wright,
President and Chief Operating Officer
Principal Financial Officer:
/s/JAMES J. JUDGE March 29, 2001
James J. Judge,
Senior Vice President, Treasurer and
Chief Financial Officer
/s/ROBERT J. WEAFER,JR. March 29, 2001
Robert J. Weafer, Jr.,
Vice President, Controller and
Chief Accounting Officer
A majority of the Board of Directors
/s/THOMAS J. MAY March 29, 2001
Thomas J. May, Director
/s/RUSSELL D. WRIGHT March 29, 2001
Russell D. Wright, Director
/s/JAMES J. JUDGE March 29, 2001
James J. Judge, Director