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7
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, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 1-2301
BOSTON EDISON COMPANY
(Exact name of registrant as specified in its charter)
Massachusetts 04-1278810
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
(Address of principal executive offices) (Zip Code)
(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 28, 2002
Common Stock, $1 par 100 shares
value
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 51 of this report.
Boston Edison Company
Form 10-K Annual Report
December 31, 2001
Part I Page
Item 1. Business 2
Item 2. Properties 8
Item 3. Legal Proceedings 8
Part II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters 9
Item 7. Management's Discussion and Analysis 10
Item 7A. Quantitative and Qualitative Disclosures About 24
Market Risk
Item 8. Financial Statements and Supplementary Financial 26
Information
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 50
Part IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 51
Part I
Item 1. Business
(a) General Development of Business
Boston Edison Company ("Boston Edison" or "the Company") is a
regulated public utility incorporated in 1886 under Massachusetts
law and is a subsidiary of NSTAR. NSTAR is an energy delivery
company serving approximately 1.3 million customers in
Massachusetts, including approximately 1.1 million electric
customers in 81 communities and 246,000 gas customers in 51
communities. Boston Edison serves approximately 681,000 electric
customers in the city of Boston and 39 surrounding communities.
NSTAR's retail utility subsidiaries are Boston Edison,
Commonwealth Electric Company (ComElectric), Cambridge Electric
Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR
Gas). Its wholesale electric subsidiary is Canal Electric
Company (Canal). NSTAR's three retail electric companies operate
under the brand name "NSTAR Electric." Reference in this report
to "NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric. NSTAR has a service company that
provides management and support services to substantially all
NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR
Electric & Gas).
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 encouraged
the utility industry to seek efficiencies and other benefits
through business combinations. NSTAR is prepared to operate in
this changing marketplace by combining the resources of its
utility subsidiaries, including Boston Edison, and concentrating
its activities in the transmission and distribution of energy.
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
consolidated 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 1997 Massachusetts Electric
Restructuring Act (Restructuring Act) and authorized by the
Commonwealth of Massachusetts Department of Telecommunications
and Energy (MDTE). These certificates are non-recourse to Boston
Edison.
NSTAR Electric has committed resources to implement a System
Improvement Program to better serve its customers by focusing on
improving customer service and system reliability. This
comprehensive, non-recurring System Improvement Program was
implemented to upgrade NSTAR Electric's distribution system,
primarily within the Boston Edison service territory and is
expected to be completed during 2002. The cost of this non-
recurring program is expected to be $65 million. Approximately
$11 million will be included in operations and maintenance
expense in 2002 and $54 million will be invested in delivery
assets during the year. A combination of unusually severe
storms, record heat and extreme customer load in the Boston area
led to prolonged and wide-spread outages in the summer of 2001
that underscored the need to address system upgrades and improve
maintenance. The program includes non-recurring costs to
eliminate the backlog of critical maintenance activities and
complete non-routine systems enhancements. This program will
also serve to allow NSTAR Electric to meet the growing load in
its service territory, as evidenced by the fact that NSTAR's
extraordinary peak demand electric load reached an all-time level
on August 9, 2001 of 4,527 megawatts (MW) and surpassed the prior
year's peak load by 12% and the previous all-time peak load by
8.5%.
An integral part of the merger creating NSTAR is the rate plan of
the retail utility subsidiaries of BEC and COM/Energy that was
approved by the Massachusetts Department of Telecommunication 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 "New Accounting Principles" section in Item 7,
Management's Discussion and Analysis for more information.
In 1998, Boston Edison completed the sale of all of its fossil
generating assets and in 1999, sold its Pilgrim Nuclear
Generating Station. Refer to the "Generating Assets Divestiture"
section in Item 7, Management's Discussion and Analysis for more
information.
(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 1.6 million. In 2001,
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 of customers for the last three years consisted
of the following:
2001 2000 1999
Retail electric revenues:
Commercial 57% 53% 51%
Residential 31% 30% 29%
Industrial 9% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 2% 7% 10%
Sources and Availability of Electric Power Supply
NSTAR Electric, including the Company, has existing long-term
power purchase agreements that are expected to supply
approximately 90%-95% of its standard offer service obligations.
NSTAR Electric has entered into a series of short-term power
purchase agreements to meet its entire default service supply
obligations and its remaining unmet standard offer supply
obligations through December 31, 2002. NSTAR Electric expects to
continue to make periodic market solicitations for default
service and standard offer power supply consistent with
provisions of the Restructuring Act and MDTE orders.
NSTAR Electric entered into six-month agreements effective
January 1, 2001 through June 30, 2001 and July 1, 2001 through
December 31, 2001 with suppliers to provide full default service
energy and ancillary service requirements at contract rates
substantially similar to MDTE-approved tariff rates. NSTAR
Electric's existing portfolio of power purchase contracts
supplied the majority of its standard offer (including wholesale)
energy requirements in 2001, supplemented with long-term and
daily purchases/sales in the bilateral and spot markets. In
addition, NSTAR Electric managed its Independent System Operator-
New England Power capability responsibilities, congestion and
uplift costs associated with default service and standard offer
load throughout 2001. For further information refer to Note I of
the Consolidated Financial Statements in Item 8.
In July 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 the buyer, Boston Edison
received a total of approximately $233 million from the Pilgrim
contract customers, including $103 million from ComElectric, to
terminate their contracts. As part of the sale, Boston Edison,
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
Internal Revenue Service 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 under Boston Edison's settlement agreement.
In addition, Boston Edison continues 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, 2001 was as follows:
Connecticut Yankee
Yankee Atomic
(dollars in thousands)
Year of Shutdown 1996 1992
Equity Ownership 9.5% 9.5%
Equity Ownership Balance $6,470 $82
New England Power Pool (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.
Franchises
Through its charter, which is unlimited in time, Boston Edison
has the right to engage in the business of producing and selling
electricity, 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
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 Federal Energy Regulatory Commission (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. Customers
have the option of continuing to buy power from the retail
electric distribution businesses at standard offer prices through
2004. 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 standard offer service. The
market price for standard offer and default service will
fluctuate based on the average market price for power. Amounts
collected through standard offer and default service are
recovered on a fully reconciling basis.
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 pressures 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 in 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.
Employees and Employee Relations
All NSTAR employees, including those of Boston Edison, are
employees of NSTAR Electric & Gas. As of December 31, 2001,
NSTAR had approximately 3,300 full-time employees, including
approximately 2,300 or 70% of who are represented by two
collective bargaining units covered by separate contracts.
Effective in May 2001, all employees are employed by NSTAR
Electric & Gas. As of 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 approximately 2,000 NSTAR
Electric & Gas employees with a five-year contract expiring May
15, 2005 that replaced seven separate and widely diverse
agreements. On March 24, 2002, Local 12004, United Steelworkers
of America, AFL-CIO-CLC ratified a new four-year contract that
expires on March 31, 2006.
Management believes it has satisfactory employee relations with a
significant majority of its employees.
Capital Expenditures and Financings
The most recent estimates of plant expenditures and long-term
debt maturities for the years 2002 through 2006 are as follows:
(in thousands) 2002 2003 2004 2005 2006
Capital $191,00 $141,00 $123,00 $107,000 $ 93,000
expenditures(a)
Long-term debt $ 41,60 $219,70 $ 70,40 $ 70,100 $ 70,300
(a) Includes plant expenditures and costs related to a non-
recurring System Improvement Program
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 2001 and 2000 were $138.6 million and
$110.4 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
Substantially all of Boston Edison's fossil generating assets
were sold as of December 30, 1998. The Pilgrim Nuclear
Generating Station was sold in July 1999. Other Boston Edison
properties included an integrated system of distribution lines
and substations that are located primarily in the Boston area as
well as the outlying communities.
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, 2001, primary and secondary overhead and
underground distribution systems cover approximately 10,900 and
5,900 circuit miles, respectively. In addition, Boston Edison's
transmission system consisted of 117 substations and
approximately 711,000 active customer meters. 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 the Boston Edison 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 and the results
of operations for a reporting period.
The 1999 MDTE order approving the rate plan associated with the
merger of BEC and COM/Energy was appealed by certain parties to
the Massachusetts Supreme Judicial Court. The appeals of the
Massachusetts Attorney General (AG) and a separate group that
consists of The Energy Consortium and Harvard University remain
pending. In October 2001, the MDTE certified the record of the
case to the court; however, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
If an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated
financial position, cash flows and the results of operations for
a reporting period.
Regulatory proceedings
In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the AG
contested cost allocations related to Boston Edison's wholesale
customers. On June 1, 2001, the MDTE approved Boston Edison's
revenue-credit approach for wholesale sales to be consistent with
Boston Edison's restructuring settlement. The reconciliation of
wholesale revenues and costs, along with other reconciliation
issues, were addressed in Boston Edison's 2000 filing covering
the reconciliation of costs through December 31, 2000. On
November 16, 2001, the MDTE approved a Settlement Agreement
between Boston Edison and the AG resolving all outstanding issues
in this filing. This settlement agreement did not have a
material effect on Boston Edison's consolidated financial
position or results of operations.
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, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities. On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million. BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002. Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs. Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets. This charge had no
material adverse effect on Boston Edison's consolidated financial
position or results of operations.
Other legal matters
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 changes in estimates could have a material impact on the
results for 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 BEC
Energy, Boston Edison's parent company, and all of BEC Energy's
common shares are held by NSTAR.
Market information for the common shares of NSTAR is included in
Item 5 of NSTAR's Annual Report on Form 10-K for the year ended
December 31, 2001.
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 subsidiary of NSTAR. NSTAR is Massachusetts'
largest investor-owned combined electric and gas utility and is
an exempt public utility holding company. NSTAR is an energy
delivery company serving approximately 1.3 million customers in
Massachusetts, including approximately 1.1 million electric
customers in 81 communities and 246,000 gas customers in 51
communities. Boston Edison serves approximately 681,000 electric
customers in the city of Boston and 39 surrounding communities.
NSTAR's retail utility subsidiaries are Boston Edison,
Commonwealth Electric Company (ComElectric), Cambridge Electric
Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR
Gas). Its wholesale electric subsidiary is Canal Electric
Company (Canal). NSTAR's three retail electric companies operate
under the brand name "NSTAR Electric." Reference in this report
to "NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric. NSTAR has a service company that
provides management and support services to substantially all
NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR
Electric & Gas).
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
consolidated 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 1997 Massachusetts Electric
Restructuring Act (Restructuring Act) and authorized by the
Commonwealth of Massachusetts Department of Telecommunications
and Energy (MDTE). These certificates are non-recourse to Boston
Edison.
NSTAR Electric has committed resources to implement a System
Improvement Program to better serve its customers by focusing on
improving customer service and system reliability. This
comprehensive, non-recurring System Improvement Program was
implemented to upgrade NSTAR Electric's distribution system and
is expected to be completed by 2002. The cost of this non-
recurring program is expected to be $65 million and primarily is
associated with improvement to Boston Edison's electric systems.
Approximately $11 million will be included in operations and
maintenance expense in 2002 and $54 million will be invested in
delivery assets during the year. A combination of unusually
severe storms, record heat and extreme customer load in the
Boston area led to prolonged and wide-spread outages in the
summer of 2001 that underscored the need to address system
upgrades and improve maintenance. The program includes non-
recurring costs to eliminate the backlog of critical maintenance
activities and complete non-routine systems enhancements. This
program will also serve to allow NSTAR Electric to meet the
growing load in its service territory, as evidenced by the fact
that NSTAR's peak demand electric load reached an all-time level
on August 9, 2001 of 4,527 megawatts (MW) and surpassed the prior
year's peak load by 12% and the previous all-time peak load by
8.5%.
Cautionary Statement
This Management's Discussion and Analysis contains some forward-
looking statements such as forecasts and projections of expected
future performance or statements of management's plans and
objectives. These forward-looking statements may be contained in
filings with the Securities and Exchange Commission (SEC) and in
press releases and oral statements. You can identify these
statements by the fact that they do not relate strictly to
historical or current facts. They use words such as
"anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe" and other words and terms of similar meaning in
connection with any discussion of future operating or financial
performance. These statements are based on the current
expectations, estimates or projections of management and are not
guarantees of future performance. Some or all of these forward-
looking statements may not turn out to be what the Company
expected. Actual results could potentially differ materially
from these statements. Therefore, no assurance can be given that
the outcomes stated in such forward-looking statements and
estimates will be achieved.
The impact of continued cost control procedures on operating
results could differ from current expectations. Boston Edison's
revenues from its electric sales are weather-sensitive,
particularly sales to residential and commercial customers.
Accordingly, Boston Edison's sales in any given period reflect,
in addition to other factors, the impact of weather, with warmer
temperatures generally resulting in increased electric sales.
Boston Edison anticipates that these sensitivities to seasonal
and other weather conditions will continue to impact its sales
forecasts in future periods. The effects of changes in weather,
economic conditions, tax rates, interest rates, technology,
prices and availability of operating supplies could materially
affect the projected operating results.
Boston Edison undertakes no obligation to publicly update forward-
looking statements, whether as a result of new information,
future events, or otherwise. You are advised, however, to
consult any further disclosures Boston Edison makes in its Forms
10-Q and 8-K to the SEC. Also note that Boston Edison provides
in the next paragraph a cautionary discussion of risks and other
uncertainties relative to its business. These are factors that
could cause its actual result to differ materially from expected
and historical results. Other factors in addition to those
listed here could also adversely affect Boston Edison.
Boston Edison's forward-looking information depends in large
measure on prevailing governmental policies and regulatory
actions, including those of the Massachusetts Department of
Telecommunications and Energy (MDTE) and the Federal Energy
Regulatory Commission (FERC), with respect to allowed rates of
return, rate structure, financings, purchased power, acquisition
and disposition of assets, operation and construction of
facilities, changes in tax laws and policies and changes in and
compliance with environmental and safety laws and policies.
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 the specific cleanup technology could affect
the estimated cleanup liabilities. The impacts of changes in
available information and circumstances regarding legal issues
could affect any estimated litigation costs.
Accounting Policies
The accompanying consolidated financial statements for each
period presented include the activities of Boston Edison's wholly
owned subsidiaries, HEEC and 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 FERC
and the MDTE. In addition, Boston Edison is subject to the
accounting and reporting requirements of the 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 (SFAS) 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.
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.
Goodwill
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 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
"New Accounting Principles" section of this Management's
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
these amounts 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 was allocated $319 million of goodwill and is
expensing this amount. This 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. For
the year ended December 31, 2001, 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 employees elected to participate. The
VSP was completed by the end of August 2000. These amounts are
expected to be offset by ongoing cost savings from streamlined
operations and avoidance of costs that would have otherwise been
incurred by BEC and COM/Energy. Refer to the "New Accounting
Principles" in this section for further information related to
goodwill.
Generating Assets Divestiture
In July 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 the buyer, Boston Edison
received a total of approximately $233 million from the Pilgrim
contract customers, including $103 million from ComElectric, to
terminate their contracts. As part of the sale, Boston Edison
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 these
amounts are currently being collected from customers under Boston
Edison's settlement agreement.
Securitization of Boston Edison's Transition Charge
On July 27, 1999, BEC Funding LLC, a wholly owned consolidated
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 1997 Massachusetts Electric
Restructuring Act (Restructuring Act) and authorized by the MDTE.
These certificates are non-recourse to Boston Edison.
Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric,
including Boston Edison, filed with the MDTE proposed service
quality plans for each company, which replaced the service
quality plan that had previously been filed as a part of the
NSTAR merger rate plan and includes guidelines that had been
established by the MDTE as a result of its generic investigation
of service quality issues. The service quality plans established
performance benchmarks effective January 1, 2002 for certain
identified measures of service quality relating to customer
service and billing performance, customer satisfaction, and
reliability and safety performance. The companies are required
to report annually concerning their performance as to each
measure and are subject to maximum penalties of up to two percent
of transmission and distribution revenues should performance fail
to meet the applicable benchmarks. On October 29, 2001, NSTAR
Electric also filed with the MDTE a report concerning their
performance on the identified service quality measures for the
two twelve-month periods ended August 31, 2000 and 2001. This
report included a calculation of penalties in accordance with
MDTE guidelines whereby penalties were calculated totaling
approximately $3.9 million relating primarily to Boston Edison's
electric system reliability performance for the summer of 2001.
NSTAR disputes the legal applicability of penalties for these
performance periods; however, NSTAR proposed in settlement of
this matter to provide credits to Boston Edison customers
totaling $3.9 million, offset in part by other payments to Boston
Edison customers, which totaled approximately $1 million,
relating to summer 2001 electric service outages. On March 22,
2002, following hearings on the matter, the MDTE issued an order
imposing a service quality penalty of approximately $3.2 million
to be refunded to customers as a credit to their bills in 2002.
Also on October 29, 2001, NSTAR Electric, including Boston
Edison, filed with the MDTE a comprehensive report regarding
electric system performance issues encountered during the summer
of 2001. The filing included detailed analyses of factors
affecting performance, as well as, the companies' plans to
address issues identified. The MDTE also requested similar
filings from other Massachusetts electric distribution companies
and has held public hearings and will hold adjudicatory hearings
concerning each such filing. On January 30, 2002, the AG and the
Massachusetts Division of Energy Resources (DOER) filed comments
urging the MDTE to assess the maximum penalties allowed pursuant
to the established service quality benchmarks and to require an
independent management audit as a result of alleged service
quality deficiencies. On February 6, 2002, NSTAR Electric filed
its brief arguing against the AG's and DOER's positions. On
March 22, 2002, following a number of public hearings throughout
the NSTAR Electric service area, the MDTE issued an order finding
that NSTAR Electric had made progress in addressing the issues
which initiated the investigation and requiring that NSTAR
Electric submit further updated reports on specific issues on a
quarterly and annual basis. Boston Edison is unable to estimate
its ultimate liability for future costs or penalties as a result
of any further filings relating to this investigation. However,
in view of Boston Edison's current assessment of its electric
distribution system performance responsibilities, existing legal
requirements and regulatory policies, management believes it
would not have a material effect on Boston Edison's consolidated
financial position, cash flows or results of operations for a
reporting period.
Retail Electric Rates
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 recovery 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 2016 were approved by the
MDTE. This schedule is subject to adjustment by the MDTE.
The 1997 Restructuring Act requires electric distribution
companies to obtain and resell power to retail customers who
choose not to buy energy from a competitive energy supplier
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 other customers who are no longer eligible
for 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. As of December 31, 2001,
Boston Edison had approximately 19% of its load requirements
provided by competitive suppliers.
Boston Edison's accumulated cost to provide default and standard
offer service was in excess of the revenues it was allowed to
bill. As a result, Boston Edison reflected a regulatory asset of
approximately $193.6 million at December 31, 2000 that is
reflected as a component of Regulatory assets on the accompanying
Consolidated Balance Sheets. Boston Edison was permitted by the
MDTE to increase its rates charged to customers to collect this
shortfall. As a result of new rates for standard offer and
default service that became effective January 1 and July 1, 2001,
and the reduction in power supply costs in 2001, resulted in a
slight net over-collection of $2.5 million as of December 31,
2001.
In December 2000, the MDTE approved a standard offer fuel index
of 1.321 cents per kilowatt-hour (kWh) that was added to Boston
Edison's standard offer service rates for the first-half of 2001.
In June 2001, the MDTE approved an additional increase of 1.23
cents per kWh effective July 1, 2001 based on a fuel adjustment
formula contained in its standard offer tariffs to reflect the
prices of natural gas and oil. In December 2001, the MDTE
approved a decrease in this fuel index of 1.125 cents to 1.426
cents per kWh for the first quarter of 2002 based on a decrease
in the cost of fuel. The MDTE has ruled that these fuel index
adjustments are excluded from the 15% rate reduction requirement
under the Restructuring Act.
Boston Edison must, on an annual basis, file a forecast of its
rates for the upcoming year along with any reconciliation of
prior year revenues and costs for standard offer, default
service, transmission and transition charges. The MDTE will, in
the ordinary course, approve rates for the coming year before the
current year-end to allow the new rates to become effective the
first of January. Subsequently, the estimates for the prior year
are reconciled to the actual amounts for that year. The MDTE
reviews these costs and approves the amounts subject to any
required adjustments.
In December 2001, Boston Edison made a filing containing proposed
rate adjustments for 2002, including a preliminary reconciliation
of costs and revenues through 2001. The MDTE subsequently
approved the tariffs effective January 1, 2002. The filings were
updated in February 2002 to include final costs for 2001. The
MDTE has approved the reconciliation of costs and revenues for
Boston Edison through 2000 in its approval on November 16, 2001
of a Settlement Agreement between Boston Edison and the AG
resolving all outstanding issues in Boston Edison's prior
reconciliation filings. As a part of this settlement, Boston
Edison agreed to reduce the costs sought to be collected through
the transition charge by approximately $2.9 million as compared
to the amounts that were originally sought. This settlement did
not have a material adverse effect on NSTAR's consolidated
financial position or results of operations for the period ended
December 31, 2001.
In addition to the annual rate filings referenced above, NSTAR
Electric has also made interim filings with the MDTE concerning
charges for a standard offer fuel adjustment and for (market-
based) default service rates. NSTAR Electric has existing long-
term power purchase agreements that are expected to supply
approximately 90%-95% of its standard offer service obligations.
NSTAR Electric has entered into a series of power purchase
agreements to meet its entire default service supply obligations
and its remaining unmet standard offer supply obligations through
December 31, 2002. NSTAR Electric expects to continue to make
periodic market solicitations for default service and standard
offer power supply consistent with provisions of the
Restructuring Act and MDTE orders. At December 31, 2001,
approximately 31% of Boston Edison's customers were on default
service.
Other Legal Matters
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 changes in estimates could have a material impact on the
results for a reporting period.
Other Matters
The September 11, 2001 terrorist attack that occurred in New York
City and in Washington, D.C., resulted in a tremendous loss of
life and property. This unfortunate incident has had
unprecedented pervasive negative impacts on several U.S.
industries and on the U.S. economy in general. While Boston
Edison was not directly impacted by the event, the Company
believes that it could be impacted indirectly in the near future.
The indirect impacts may include lower revenues due to the
negative impact on certain of Boston Edison's commercial and
industrial customers and higher costs related to items such as
insurance and security.
Results of Operations
The following section of Management's Discussion and Analysis
compares the results of operations for each of the three fiscal
years ended December 31, 2001 and should be read in conjunction
with the consolidated financial statements and the accompanying
notes included elsewhere in this report.
2001 versus 2000
Net income was $150.4 million in 2001 compared to $146 million in
2000, an increase of 3%.
Operating revenues
Operating revenues for 2001 increased 18.6% from 2000 as follows:
(in thousands)
Retail revenues $292,795
Wholesale revenues 6,834
Short-term sales and other revenues 11,227
Increase in operating revenues $310,856
========
Despite virtually no change in energy sales in 2001, retail
revenues were $1,826 million in 2001 compared to $1,533.2 million
in 2000, an increase of $292.8 million, or 19%. The change in
retail revenues includes higher rates implemented in January and
July 2001 for standard offer and default services, which
increased retail revenues by $178.6 million and $209 million,
respectively, the absence in 2001 of a $23.7 million fuel charge
refund to customers in 2000, and increases in net distribution
revenues of $6.6 million and transmission revenues of $24.1
million. These revenue increases were partially offset by lower
transition revenues of $69.8 million due to a decline in rates.
The increase in Boston Edison's retail revenues related to
standard offer and default services are fully reconciled to the
costs incurred and have no impact on net income.
Boston Edison forecasts its electric sales based on normal
weather conditions. Forecasted results may differ from those
projected due to actual weather conditions above or below these
normal weather levels.
Weather conditions greatly impact the change in electric sales
and revenues in Boston Edison's service area. Boston Edison's
revenues from its electric sales are weather-sensitive,
particularly sales to residential and commercial customers.
Accordingly, Boston Edison's sales in any given period reflect,
in addition to other factors, the impact of weather, with warmer
temperatures generally resulting in increased electric sales.
Boston Edison anticipates that these sensitivities to seasonal
and other weather conditions will continue to impact its sales
forecasts in future periods. The summer period of 2001 was
significantly warmer than the same period in 2000, resulting in a
39.8% increase in cooling degree days from the prior year and a
21.2% increase from the 30-year average. Below is comparative
information on cooling and heating degree days in 2001 and 2000
and the number of degree days in a "normal" year as represented
by a 30-year average.
30-Year
2001 2000 Average
Cooling degree days 822 588 678
Percentage change from prior year 39.8% (34.0)%
Percentage change from 30-year 21.2% (13.3)%
average
Heating degree days 5,637 6,147 5,939
Percentage change from prior year (8.3)% 11.7%
Percentage change from 30-year (5.1)% 3.5%
average
Wholesale electric revenues were $80 million in 2001 compared to
$73.2 million in 2000, an increase of $6.8 million, or 9%. This
increase in wholesale revenues reflects increased kWh sales of
2.9%, primarily as the result of increased demand from a public
transit authority and municipal contracts. In 2002, wholesale
electric sales are forecasted to decrease due to the expiration
of contracts with several municipalities. The expiration of
these contracts is not expected to impact Boston Edison's
consolidated earnings.
Other revenues were $76.7 million in 2001 compared to $65.5
million in 2000, an increase of $11.2 million, or 17%. This
change reflects higher New England Power Pool related
transmission revenues, partially offset by the absence of a $1.6
million transmission refund relating to Local Network Services
transmission revenues as recognized in 2000 due to a FERC-
approved settlement with transmission contract customers.
Operating expenses
Purchased power was $1,159.7 million in 2001 compared to $839.7
million in 2000, an increase of $320 million or 38%. The
increase in purchased power expense reflects the impact of the
recognition of previously deferred standard offer and default
service supply costs resulting from collection of these costs in
2001. Boston Edison adjusts its electric rates to collect the
costs related to purchased power from customers on a fully
reconciling basis. Due to the rate adjustment mechanisms,
changes in the amount of purchased power expense have no impact
on earnings. Also impacting this increase were higher purchased
power requirements due to a slight increase in retail sales,
partially offset by lower costs that reflect the prices of
natural gas and oil.
Operations and maintenance expense was $203.3 million in 2001
compared to $205.7 million in 2000, a decrease of $2.4 million or
1.2%. This slight decrease reflects the full integration of NSTAR
Electric & Gas and includes the re-alignment of costs allocated
to NSTAR subsidiaries and other merger-related operating
efficiencies. This decrease was partially offset by higher
electric distribution weather-related maintenance costs related
to a major late-winter storm in March and severe summer weather
during 2001, higher bad debt expense primarily due to the
increased revenues and higher costs related to pension and
postretirement benefits.
In 2002, consolidated operations and maintenance expense for
NSTAR is forecasted to increase significantly to support the
utility System Improvement Program of approximately $11 million.
It is anticipated that a significant portion of these costs will
be incurred by Boston Edison. NSTAR has forecasted that pension
cost will increase by approximately $20 million for 2002 as
compared to 2001. Accordingly, Boston Edison will be allocated
approximately 60% of this cost. This is due to the downturn in
equity markets, which have reduced the value of NSTAR's pension
investments and the impact of lower interest rates. This
expected level of expense could vary due to external factors
beyond the Company's control.
Depreciation and amortization expense was $167.9 million in 2001
compared to $169.3 million in 2000, a decrease of $1.4 million or
0.8%. The decline in amortization expense is directly
attributable to the lower level of amortization expense
associated with software-related costs, partially offset by a
higher level of depreciable plant-in-service in the current year.
Demand side management (DSM) and renewable energy programs
expense was $47.6 million in 2001 compared to $54.8 million in
2000, a decrease of $7.2 million, or 13%, primarily due to the
timing of DSM expense. These costs are in accordance with
program guidelines established by regulators and are collected
from customers on a fully reconciling basis. In addition, Boston
Edison earns incentive amounts in return for increased customer
participation.
Property and other taxes were $69.8 million in 2001 compared to
$55.9 million in 2000, an increase of $13.9 million, or 25%. The
increase was due to the fact that during 2000, Boston Edison was
reimbursed for the majority of its payments, in lieu of property
taxes to the Town of Plymouth by Entergy Nuclear Generating
Company (Entergy). Entergy purchased Pilgrim Station in 1999.
Income taxes from operations were $94.0 million in 2001 compared
to $95.9 million in 2000, a decrease of $1.9 million, or 2%,
reflecting the reversal of a previously recorded income tax
reserve.
Other income, net
Other income, net was $7.9 million in 2001 compared to $7.7
million in 2000, a net decrease of $0.2 million or 2.6%. The
decrease reflects the result of a one-time income item recognized
in 2000 related to $4.4 million received from a third party
related to the Pilgrim wholesale contract buyout. Offsetting
this gain in 2000 was the allocation from NSTAR Electric & Gas of
$2.7 million of income associated with the receipt of equity
securities in connection with demutualization of two insurance
companies in 2001 and a favorable settlement associated with a
property tax reserve.
Interest charges
Interest on long-term debt and transition property securitization
certificates was $87.5 million in 2001 compared to $98.3 million
in 2000, a decrease of $10.8 million or 11%. Approximately $4.0
million of the decrease is related to securitization certificate
interest reflecting the scheduled partial retirement of this
debt. The decrease also reflects approximately $6.4 million in
reductions related to the following retirements: $65 million of
6.8% debentures, $34 million of 9.875% debentures, $100 million
of 6.05% debentures during 2000 and $24.3 million of 9.375%
debentures in August 2001.
Other interest charges were $11.5 million in 2001 compared to
$15.9 million in 2000, a decrease of $4.4 million or 27.7%. This
decrease is primarily due to a reconciliation adjustment of
regulatory deferrals in conjunction with a MDTE reconciliation
that resulted in the recognition of interest expense in 2000, and
lower interest borrowing rates, offset by higher average short-
term borrowing levels from banks. The increase in borrowing is
primarily the result of financing long-term debt and preferred
stock retirements with short-term borrowings and other working
capital requirements.
Other Matters
Environmental
Boston Edison is involved in approximately 15 state-regulated
properties ("Massachusetts Contingency Plan, or "MCP sites")
where oil or other hazardous materials were previously spilled or
released. Boston Edison is required to clean up or otherwise
remediate these properties in accordance with specific state
regulations. There are uncertainties associated with the
remediation costs due to the final selection of the specific
cleanup technology and the particular characteristics of the
different sites. In addition to the MCP sites, Boston Edison also
faces possible 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.
Approximately $4.8 million and $5 million are included as
liabilities in the accompanying Consolidated Balance Sheets at
December 31, 2001 and 2000, respectively, related to the non-
recoverable portion of these cleanup liabilities. 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 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 an 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 and as either additional sites are
identified or Boston Edison's responsibilities for such sites are
resolved. 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 the Boston Edison 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.
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 the results of
operations for a reporting period.
The 1999 MDTE order approving the rate plan associated with the
merger of BEC and COM/Energy was appealed by certain parties to
the Massachusetts Supreme Judicial Court. The appeals of the AG
and a separate group that consists of The Energy Consortium and
Harvard University remain pending. In October 2001, the MDTE
certified the record of the case to the court; however, there has
to date been no briefing, hearing or other action taken with
respect to this proceeding. If an unfavorable outcome were to
occur, there could be a material adverse impact on business
operations, the consolidated financial position, cash flows and
the results of operations for a reporting period.
Regulatory Proceedings
In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the AG
contested cost allocations related to Boston Edison's wholesale
customers. On June 1, 2001, the MDTE approved Boston Edison's
revenue-credit approach for wholesale sales to be consistent with
Boston Edison's restructuring settlement. The reconciliation of
wholesale revenues and costs, along with other reconciliation
issues, were addressed in Boston Edison's 2000 filing covering
the reconciliation of costs through December 31, 2000. On
November 16, 2001, the MDTE approved a Settlement Agreement
between Boston Edison and the AG resolving all outstanding issues
in this filing. This settlement agreement did not have a
material effect on NSTAR's consolidated financial position or
results of operations.
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, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities. On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million. BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002. Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current ratepayers in the form of a credit to Boston
Edison's transition costs. Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets. This charge had no
material adverse effect on Boston Edison's consolidated financial
position or results of operations.
Employees and Employee Relations
All NSTAR employees, including those of Boston Edison, are
employees of NSTAR Electric & Gas. As of December 31, 2001,
NSTAR had approximately 3,300 full-time employees, including
approximately 2,300 or 70% of who are represented by two
collective bargaining units covered by separate contracts.
Effective in May 2001, all employees are employed by NSTAR
Electric & Gas. As of 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 approximately 2,000 NSTAR
Electric & Gas employees with a five-year contract expiring May
15, 2005 that replaced seven separate and widely diverse
agreements. On March 24, 2002, Local 12004, United
Steelworkers of America, AFL-CIO-CLC ratified a new four-year
contract that expires on March 31, 2006.
Management believes it has satisfactory employee relations with a
significant majority of its employees.
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, 2001 and 2000, were as follows:
(in thousands) Weighted
Carrying Fair Average
2001 Amount Value Interest Rate
Long-term indebtedness $1,107,346 $1,153,380 7.15%
(including current
indebtedness)
2000
Mandatory redeemable cumulative
preferred stock $ 49,519 $ 50,890 8.00%
Long-term indebtedness $1,198,857 $1,198,695 7.16%
(including current indebtedness)
The mandatory redeemable cumulative preferred stock was redeemed
in total on December 3, 2001.
New Accounting Principles
In June 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standard (SFAS) No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). This
Statement, which is effective for Boston Edison in the first
quarter of 2002, establishes accounting and reporting standards
for acquired goodwill and other indefinite lived intangible
assets. It prohibits entities from continuing amortization of
these assets. Instead, goodwill and other intangible assets will
be subject to review for impairment. However, in accordance with
paragraph (d)8 of SFAS 142 and revised paragraph 30 of SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation,"
the utility subsidiaries of NSTAR plan to continue amortization
of this asset over its estimated regulatory recovery period
including the portion allocated to Boston Edison. Boston Edison
has determined that its unique regulatory rate structure,
resulting from the rate plan approved by the MDTE on July 27,
1999 in connection with the formation of NSTAR, requires
continued amortization of goodwill. A significant element of
this rate plan includes recovery of the acquisition premium over
40 years and provides for the reasonable assurance of the
existence of a regulatory asset.
Also, in accordance with SFAS 142, NSTAR will transfer to Boston
Edison, a reporting unit, $319 million of goodwill as a component
of common equity, effective January 1, 2002. This allocation of
goodwill represents the level of anticipated recovery from Boston
Edison's customers. Therefore, Boston Edison's adjusted common
equity as of December 31, 2001 including this adjustment would be
as follows:
(in thousands)
Total Common Equity as of December 31, 2001 $ 956,945
Goodwill transferred 319,048
Adjusted Common Equity as of January 1,2002 $1,275,993
==========
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143). This Statement, which
is effective for fiscal years beginning after June 15, 2002,
establishes accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development
and/or the normal operation of a long-lived asset, except for
certain obligations of lessees. This standard requires entities
to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When the
liability is initially recorded, the entity capitalizes the cost
by increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value
each period, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement.
Management is currently assessing the impact of SFAS 143 in light
of its regulatory and accounting requirements. However, based on
Boston Edison's assessment to date, the adoption of SFAS 143 is
not expected to have a material effect on the Company's results
of operations, cash flows, or financial position.
As of January 1, 2001, Boston Edison adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133), as amended by SFAS Nos. 137 and 138, and collectively
referred to as SFAS 133. SFAS 133 established accounting and
reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in 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.
The management of NSTAR has assessed the impact of the adoption
of SFAS 133. As part of this assessment, NSTAR 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 performed extensive reviews
of critical operating areas of Boston Edison and documented its
procedures in applying the requirements of SFAS 133 to Boston
Edison's contractual arrangements in effect on January 1, 2001.
NSTAR continues its assessment on any impact that potentially may
result from FASB revisions and clarifications, including, but not
limited to, FASB Derivative Implementation Group Issue C15, to
SFAS 133. Based on NSTAR's assessment, the adoption of SFAS 133
has not had a material effect on the Company's results of
operations, cash flows, or financial position.
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. Customers have the option of continuing to buy power
from the retail electric distribution businesses at standard
offer prices through 2004. 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 standard
offer service. The market prices for standard offer and default
service will fluctuate based on the average market price for
power. Amounts collected through standard offer and default
service are recovered on a fully reconciling basis.
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 51, present
fairly, in all material respects, the financial position of
Boston Edison Company and its subsidiaries at December 31, 2001
and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 2001 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 51, 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
/s/ PRICEWATERHOUSECOOPERS LLP
Boston, Massachusetts
January 31, 2002, (except as to Note B(2), as to which the date
is March 22, 2002)
Item 8. Financial Statements and Supplementary Financial
Information
Boston Edison Company
Consolidated Statements of Income
(in thousands)
Years ended December 31,
2001 2000 1999
Operating revenues $1,982,701 $1,671,846 $1,546,817
Operating expenses:
Purchased power and fuel 1,159,706 839,715 645,175
Operations and maintenance 203,320 205,734 271,358
Depreciation and amortization 167,905 169,333 176,705
Demand side management and
renewable energy programs 47,639 54,836 57,467
Taxes-property and other 69,777 55,905 68,826
Income taxes 93,967 95,852 91,029
Total operating expenses 1,742,314 1,421,375 1,310,560
Operating income 240,387 250,471 236,257
Other income, net 7,930 7,699 19,803
Operating and other income 248,317 258,170 256,060
Interest charges:
Long-term debt 45,994 52,804 71,150
Transition property securitization
certificates 41,475 45,505 20,408
Short-term and other 11,467 15,902 6,199
Allowance for borrowed funds used
during construction (972) (2,069) (2,011)
Total interest charges 97,964 112,142 95,746
Net income $ 150,353 $ 146,028 $ 160,314
========== ========== ==========
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 (Loss)
(in thousands)
Years ended December 31,
2001 2000 1999
Net income $ 150,353 $ 146,028 $ 160,314
Other comprehensive (loss) income, net:
Non-qualified benefit obligations 117 (117) -
Comprehensive income $ 150,470 $ 145,911 $ 160,314
========= ========= =========
Boston Edison Company
Consolidated Statements of Retained Earnings
(in thousands)
Years ended December 31,
2001 2000 1999
Balance at the beginning of the year $ 352,832 $ 1,462 $ 297,347
Add:
Net income 150,353 146,028 160,314
Dividends transferred from paid in - 226,541 -
capital (a)
Subtotal 503,185 374,031 457,661
Deduct:
Dividends declared:
Dividends to Parent 68,927 15,000 450,000
Preferred stock 5,627 5,960 5,960
Subtotal 74,554 20,960 455,960
Provision for preferred stock redemption and
issuance costs 481 239 239
Balance at the end of year $ 428,150 $ 352,832 $ 1,462
========= ========= ========
(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 the
Company's sole shareholder, was a partial distribution of a
return of capital. As a result, the Company has 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 2001 2000
Utility plant in service, at
original cost $2,641,759 $2,522,682
Less: accumulated depreciation 875,158 $1,766,601 825,367 $1,697,315
Construction work in progress 38,818 39,820
Net utility plant 1,805,419 1,737,135
Equity investments 13,589 15,512
Other investments 22 9,599
Current assets:
Cash and cash equivalents 13,549 12,125
Restricted cash 3,625 3,625
Accounts receivable - customers,
net of allowance of $24,691 and
$22,415 in 2001 and 2000, 264,633 200,479
respectively
Accounts receivable - affiliates 169,920 54,392
Accrued unbilled revenues 29,081 66,879
Fuel, materials and supplies, at
average cost 15,461 15,621
Other 24,170 520,439 5,918 359,039
Deferred debits:
Regulatory assets 768,776 974,615
Prepaid pension expense 218,713 149,890
Other 27,763 46,250
Total assets $3,354,721 $3,292,040
========= ==========
Capitalization and Liabilities
Common equity $ 956,945 $ 834,836
Accumulated other comprehensive
loss, net - (117)
Cumulative non-mandatory redeemable
preferred stock of subsidiary 43,000 43,000
Long-term debt 551,803 577,618
Transition property
securitization certificates 513,904 584,130
Current liabilities:
Long-term debt and preferred
stock $ 667 $ 50,186
Transition property
securitization certificates 40,972 36,443
Notes payable 191,500 96,500
Deferred taxes - 43,638
Accounts payable:
Affiliates 243,163 116,610
Other 91,522 115,783
Accrued interest 10,738 11,454
Dividends payable 327 993
Other 66,771 645,660 125,231 596,838
Deferred credits
Accumulated deferred income taxes 559,516 547,002
Accumulated deferred investment
tax credits 19,249 20,346
Power contracts 22,697 25,868
Other 41,947 62,519
Commitments and contingencies
Total capitalization and liabilities $3,354,721 $3,292,040
========== ==========
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,
2001 2000 1999
Operating activities:
Net income $ 150,353 $ 146,028 $ 160,314
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization 167,905 161,371 188,078
Deferred income taxes and (51,242) 86,962 99,504
investment tax credits
Power contract buyout - - (65,781)
Allowance for borrowed funds used (972) (2,069) (2,011)
during construction
Net changes in:
Accounts receivable and accrued (26,356) 13,556 (50,736)
unbilled revenues
Fuel, materials and supplies 160 605 (1,387)
Accounts payable 102,292 128,753 (49,084)
Other current assets and liabilities (194,582) (363,521) (77,628)
Other, net 58,727 14,991 27,828
Net cash provided by operating activities 206,285 186,676 229,097
Investing activities:
Plant expenditures (excluding AFUDC) (138,565) (110,437) (125,419)
Costs of nuclear divestiture and fuel - - (103,366)
expenditures, net
Investments 11,500 4,368 (6,301)
Net cash used in investing activities (127,065) (106,069) (235,086)
Financing activities:
Capital contribution 43,937 - -
Long-term debt - - 725,000
Redemptions:
Preferred stock (50,000) - -
Long-term debt (91,513) (251,559) (203,214)
Net change in notes payable 95,000 96,500 -
Dividends paid (75,220) (30,960) (480,960)
Net cash (used in) provided by financing (77,796) (186,019) 40,826
activities
Net increase (decrease) in cash and cash 1,424 (105,412) 34,837
equivalents
Cash and cash equivalents at the 12,125 117,537 82,700
Cash and cash equivalents at the end of $ 13,549 $ 12,125 $ 117,537
the year
========== ========== ==========
Supplemental disclosures of cash flow
information:
Interest, net of amounts capitalized $ 91,007 $ 105,735 $ 76,926
Income taxes (refunded) paid $ 164,194 $ (47,312) $ 87
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 subsidiary of NSTAR. NSTAR is Massachusetts'
largest investor-owned combined electric and gas utility and is
an exempt public utility holding company. NSTAR is an energy
delivery company serving approximately 1.3 million customers in
Massachusetts, including approximately 1.1 million electric
customers in 81 communities and 246,000 gas customers in 51
communities. Boston Edison serves approximately 681,000 electric
customers in the city of Boston and 39 surrounding communities.
NSTAR's retail utility subsidiaries are Boston Edison,
Commonwealth Electric Company (ComElectric), Cambridge Electric
Light Company (Cambridge Electric) and NSTAR Gas Company (NSTAR
Gas). Its wholesale electric subsidiary is Canal Electric
Company (Canal). NSTAR's three retail electric companies operate
under the brand name "NSTAR Electric." Reference in this report
to "NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric. NSTAR has a service company that
provides management and support services to substantially all
NSTAR subsidiaries - NSTAR Electric & Gas Corporation (NSTAR
Electric & Gas).
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 1.6 million. In
2001, 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 (SFAS) 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.
In 2000, 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 FERC and the MDTE. 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.
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. The overall composite
depreciation rates were 2.87%, 2.99% and 3.31% in 2001, 2000 and
1999, 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 2001, 2000 and 1999 were 4.14%, 6.00% and 5.82%,
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. These funds are available to pay
the principal and interest on the transition property
securitization certificates.
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)
2001 2000
Generation-related regulatory $ 559,712 $ 559,121
assets, net
Purchased power costs (2,498) 193,641
Costs to achieve 79,227 71,823
Power contracts 22,697 25,868
Income taxes, net 62,070 64,775
Postretirement benefits costs 7,217 12,040
Redemption premiums 12,853 14,403
Other 27,498 32,944
Total regulatory assets $ 768,776 $ 974,615
========= =========
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. Boston Edison participates in
several corporate joint ventures in which it has investments,
principally its 11.1% equity investment in two companies that own
and operate transmission facilities to import electricity from
the Hydro-Quebec System in Canada, and its equity investments
both of 9.5% in two regional nuclear generating facilities that
are currently being decommissioned.
12. Related Party Transactions
The accompanying Consolidated Balance Sheets include an Accounts
payable of $277,400 and an Accounts receivable of $13.7 million
as of December 31, 2001 and 2000, respectively, from NSTAR
Communications, Inc., an affiliate. These balances represent the
construction and construction management services provided by
Boston Edison and its contractors. Additionally, the December
31, 2001 Consolidated Balance Sheet includes a net payable of
$45.4 million to NSTAR Electric & Gas, for management and support
services. The December 31, 2001 Consolidated Balance Sheet also
includes a $3.9 million receivable from affiliate BETG associated
with the MDTE ruling in the BETG proceeding. Boston Edison's
goodwill amortization expense allocation from its affiliated
companies, ComElectric, Cambridge Electric and NSTAR Gas was $8
million for 2001.
13. Amortization of Goodwill and Costs to Achieve
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. 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.
Boston Edison's share of goodwill and costs to achieve are
approximately $319 million and $72 million, respectively. Total
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, 2001,
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. Refer to the following Item 14
"New Accounting Principles" for a further discussion of goodwill.
14. New Accounting Principles
In June 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standard (SFAS) No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). This
Statement, which is effective for Boston Edison in the first
quarter of 2002, establishes accounting and reporting standards
for acquired goodwill and other indefinite lived intangible
assets. It prohibits entities from continuing amortization of
these assets. Instead, goodwill and other intangible assets will
be subject to review for impairment. However, in accordance with
paragraph (d)8 of SFAS 142 and revised paragraph 30 of SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation,"
the utility subsidiaries of NSTAR plan to continue amortization
of this asset over its estimated regulatory recovery period
including the portion allocated to Boston Edison. Boston Edison has
determined that its unique regulatory rate structure, resulting
from the rate plan approved by the MDTE on July 27, 1999 in
connection with the formation of NSTAR, requires continued
amortization of goodwill. A significant element of this rate
plan includes recovery of the acquisition premium over 40 years
and provides for the reasonable assurance of the existence of a
regulatory asset.
Also, in accordance with SFAS 142, NSTAR will transfer to Boston
Edison, a reporting unit, $319 million of goodwill as a component
of common equity, effective January 1, 2002. This allocation of
goodwill represents the level of anticipated recovery from Boston
Edison's customers. Therefore, Boston Edison's adjusted common
equity as of December 31, 2001 including this adjustment would be
as follows:
(in thousands)
Total Common Equity as of December 31, 2001 $ 956,945
Goodwill transferred 319,048
Adjusted Common Equity as of January 1, 2002 $1,275,993
==========
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143). This Statement, which
is effective for fiscal years beginning after June 15, 2002,
establishes accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal
obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development
and/or the normal operation of a long-lived asset, except for
certain obligations of lessees. This standard requires entities
to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When the
liability is initially recorded, the entity capitalizes the cost
by increasing the carrying amount of the related long-lived
asset. Over time, the liability is accreted to its present value
each period, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the
liability, an entity either settles the obligation for its
recorded amount or incurs a gain or loss upon settlement.
Management is currently assessing the impact of SFAS 143 in light
of its regulatory and accounting requirements. However, based on
Boston Edison's assessment to date, the adoption of SFAS 143 is
not expected to have a material effect on the Company's results
of operations, cash flows, or financial position.
As of January 1, 2001, Boston Edison adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133), as amended by SFAS Nos. 137 and 138, and collectively
referred to as SFAS 133. SFAS 133 established accounting and
reporting standards requiring that every derivative instrument
(including certain derivative instruments embedded in 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.
The management of NSTAR has assessed the impact of the adoption
of SFAS 133. As part of this assessment, NSTAR 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 performed extensive reviews
of critical operating areas of Boston Edison and documented its
procedures in applying the requirements of SFAS 133 to Boston
Edison's contractual arrangements in effect on January 1, 2001.
NSTAR continues its assessment on any impact that potentially may
result from FASB revisions and clarifications, including, but not
limited to, FASB Derivative Implementation Group Issue C15, to
SFAS 133. Based on NSTAR's assessment, the adoption of SFAS 133
has not had a material effect on the Company's results of
operations, cash flows, or financial position.
Note B. Electric Utility Industry Restructuring
1. Accounting Implications
Under the traditional revenue requirements model, electric rates
are based on the cost of providing electric service. Under this
traditional model, Boston Edison is 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 through 2016 and is subject to adjustment by the
MDTE.
b.) Standard offer and default service charge
Customers have the option of continuing to buy power from Boston
Edison at standard offer prices through 2004. In December 2000,
the MDTE approved a standard offer fuel index of 1.321 cents per
kilowatt-hour (kWh) that was added to Boston Edison's standard
offer service rates for the first-half of 2001. In June 2001,
the MDTE approved an additional increase of 1.23 cents per kWh
effective July 1, 2001 based on a fuel adjustment formula
contained in its standard offer tariffs to reflect the prices of
natural gas and oil. In December 2001, the MDTE approved a
decrease in this fuel index of 1.125 cents to 1.426 cents per kWh
for the first quarter of 2002 based on a decrease in the cost of
fuel. The MDTE has ruled that these fuel index adjustments are
excluded from the 15% rate reduction requirement under the
Restructuring Act.
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.
c.) 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.
The cost of providing transmission service to distribution
customers is recovered on a fully reconciling basis plus an
approved return.
2. Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric,
including Boston Edison, filed with the MDTE proposed service
quality plans for each company, which replaced the service
quality plan that had previously been filed as a part of the
NSTAR merger rate plan and includes guidelines that had been
established by the MDTE as a result of its generic investigation
of service quality issues. The service quality plans established
performance benchmarks effective January 1, 2002 for certain
identified measures of service quality relating to customer
service and billing performance, customer satisfaction, and
reliability and safety performance. The companies are required
to report annually concerning their performance as to each
measure and are subject to maximum penalties of up to two percent
of transmission and distribution revenues should performance fail
to meet the applicable benchmarks. On October 29, 2001, NSTAR
Electric also filed with the MDTE a report concerning their
performance on the identified service quality measures for the
two twelve-month periods ended August 31, 2000 and 2001. This
report included a calculation of penalties in accordance with
MDTE guidelines whereby penalties were calculated totaling
approximately $3.9 million relating primarily to Boston Edison's
electric system reliability performance for the summer of 2001.
NSTAR disputes the legal applicability of penalties for these
performance periods; however, NSTAR proposed in settlement of
this matter to provide credits to Boston Edison customers
totaling $3.9 million, offset in part by other payments to Boston
Edison customers, which totaled approximately $1 million,
relating to summer 2001 electric service outages. On March 22,
2002, following hearings on the matter, the MDTE issued an order
imposing a service quality penalty of approximately $3.2 million
to be refunded to customers as a credit to their bills in 2002.
Also on October 29, 2001, NSTAR Electric, including Boston
Edison, filed with the MDTE a comprehensive report regarding
electric system performance issues encountered during the summer
of 2001. The filing included detailed analyses of factors
affecting performance, as well as, the companies' plans to
address issues identified. The MDTE also requested similar
filings from other Massachusetts electric distribution companies
and has held public hearings and will hold adjudicatory hearings
concerning each such filing. On January 30, 2002, the AG and the
Massachusetts Division of Energy Resources (DOER) filed comments
urging the MDTE to assess the maximum penalties allowed pursuant
to the established service quality benchmarks and to require an
independent management audit as a result of alleged service
quality deficiencies. On February 6, 2002, NSTAR Electric filed
its brief arguing against the AG's and DOER's positions. On
March 22, 2002, following a number of public hearings throughout
the NSTAR Electric service area, the MDTE issued an order finding
that NSTAR Electric had made progress in addressing the issues
which initiated the investigation and requiring that NSTAR
Electric submit further updated reports on specific issues on a
quarterly and annual basis. Boston Edison is unable to estimate
its ultimate liability for future costs or penalties as a result
of any further filings relating to this investigation. However,
in view of Boston Edison's current assessment of its electric
distribution system performance responsibilities, existing legal
requirements and regulatory policies, management believes it
would not have a material effect on Boston Edison's consolidated
financial position, cash flows or results of operations for a
reporting period.
Note C. Income Taxes
Income taxes are accounted for in accordance with SFAS 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 $62.1 million and $64.8
million and corresponding net increases in accumulated deferred
income taxes were recorded as of December 31, 2001 and 2000,
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) 2001 2000
Deferred tax liabilities:
Plant-related $ 211,506 $ 202,475
Transition costs 233,465 291,222
Other 154,148 257,619
599,119 751,316
Deferred tax assets:
Investment tax credits 12,423 12,150
Other 29,015 148,526
41,438 160,676
Net accumulated deferred $ 557,681 $ 590,640
income 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) 2001 2000 1999
Current income tax expense (benefit) $ 144,779 $ 8,890 $(29,306)
Deferred income tax (benefit)expense (49,715) 87,953 122,584
Investment tax credit amortization (1,097) (991) (2,249)
Income taxes charged to operations 93,967 95,852 91,029
Current tax expense (benefit)on other
income (deductions), net 3,607 5,046 (22,465)
Total income tax expense $ 97,574 $100,898 $ 68,564
======== ======= =======
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:
2001 2000 1999
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of
federal income tax benefit 4.4 4.4 4.3
Investment tax credit amortization (0.4) (0.4) (10.1)
Other 0.4 1.8 0.8
Effective tax rate 39.4% 40.8% 30.0%
===== ===== =====
Income tax expense is reflected net of $20.8 million in 1999
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%.
Note D. Pension and Other Postretirement Benefits
1. Pension
Effective January 1, 2000, the pension plans of BEC and
COM/Energy were combined under NSTAR to form the NSTAR Pension
Plan (the Plan). Since the merger date and following the
renaming of the plans, Boston Edison has remained the sponsor of
the Plan.
The Company participates with other subsidiaries of NSTAR in the
noncontributory Plan, with certain limited contributory features,
that covers substantially all employees of NSTAR Electric & Gas.
Effective January 1, 2000, the defined benefit plan was 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. It is the Company's policy to fund
the Plan in amounts determined to meet the funding standards
established by the Employee Retirement Income Security Act of
1974
The Company also maintains unfunded supplemental retirement plans
for certain management employees of NSTAR Electric & Gas.
Consistent with the transfer of all Boston Edison employees to
NSTAR Electric & Gas, the liability for its supplemental
retirement plan has also been transferred accordingly effective
December 31, 2001.
The changes in the benefit obligation and plan assets were as
follows:
December 31,
(in thousands) 2001 2000
Change in benefit obligation:
Benefit obligation, beginning of the year $ 804,358 $ 800,084
Transfer of obligation to affiliate company (14,067) -
Service cost 13,727 14,636
Interest cost 56,418 59,798
Plan participants' contributions 71 81
Plan amendments - (4,387)
Actuarial loss 14,091 59,815
Settlement payments (16,573) (77,256)
Benefits paid (47,508 (48,413)
)
Benefit obligation, end of the year $ 810,517 $ 804,358
========= =========
Change in plan assets: 2001 2000
Fair value of plan assets, beginning of the $ 846,207 $ 955,498
year
Actual loss on plan assets, net (52,493) (28,041)
Employer contribution 61,000 44,338
Plan participants' contributions 71 81
Settlement payments (16,573) (77,256)
Benefits paid (47,508) (48,413)
Fair value of plan assets, end of the year $ 790,704 $ 846,207
========= =========
The plan's funded status was as follows:
December 31,
(in thousands) 2001 2000
Funded status $ (33,598) $ 41,849
Liability transfer to affiliate company 13,785
Unrecognized actuarial net loss 246,708 104,817
Unrecognized transition obligation 1,581 2,182
Unrecognized prior service cost (9,762) (3,340)
Net amount recognized $ 218,714 $ 145,508
========= =========
Amounts recognized in the Consolidated Balance Sheets consisted
of:
2001 2000
(in thousands)
Prepaid retirement cost $ 218,714 $ 149,890
Accrued supplemental retirement liability - (13,306)
Intangible asset - 7,285
Accumulated other comprehensive income - 1,639
Net amount recognized $ 218,714 $ 145,508
========= =========
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 $0, $0 and $0, respectively, as of December 31, 2001,
and $14,067,000, $13,306,000 and $0, respectively, as of December
31, 2000.
Weighted average assumptions were as follows:
2001 2000 1999
Discount rate at the end of the year 7.25% 7.50% 8.00%
Expected return on plan assets for the year
(net of investment expenses) 9.40% 9.30% 9.00%
Rate of compensation increase at the end of
the year 4.00% 4.00% 4.00%
Components of net periodic benefit (income)/cost were as follows:
>C>
(in thousands) 2001 2000 1999
Service cost $ 14,027 $ 14,636 $ 13,137
Interest cost 57,050 59,798 31,658
Expected return on plan assets (78,397) (85,884) (41,295)
Amortization of prior service cost (118) 448 1,610
Amortization of transition obligation 601 601 664
Recognized actuarial loss 775 - 3,754
Net periodic benefit (income)/cost $(6,062) $(10,401) $ 9,528
========= ========= ========
Certain postretirement health care benefits are eligible to
certain active NSTAR Electric & Gas employees and certain retired
non-union employees in conjunction with the NSTAR postretirement
plan. Pursuant to the Internal Revenue Code, the Company has the
benefits through a 401(h) subaccount of the Pension Plan, subject
to certain conditions and limitations. Assets in the trust
beyond those in the 401(h) subaccount must be used to pay pension
benefits and cannot be used to pay postretirement health care
benefits. Assets included in the 401(h) subaccount must only be
used for postretirement health care benefits.
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 are a component of Regulatory assets
on the accompanying Consolidated Balance Sheets. The previous
amounts resulting from the merger-related separation agreements
and generation divestitures are recoverable as part of the
approved rate plans of the Boston Edison settlement agreement.
The Company, as the sponsor of the plan, allocated net expenses
and were reimbursed by its affiliated companies of $1,159,000 and
$2,644,000 in 2001 and 2000, respectively.
2. Savings Plan
Boston Edison also participates in a defined contribution 401(k)
plan for substantially all employees NSTAR Electric & Gas.
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 2001,
$4 million in 2000 and $8 million in 1999. The plan was amended,
effective April 1, 2001, to allow participants the ability to
reallocate their investments in NSTAR shares to other investment
options.
3. 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. On January 1, 2000,
other postretirement benefit plans of Boston Edison and
COM/Energy were combined under NSTAR. On December 1, 2001, the
investments previously held by those plans were combined into two
voluntary employees' beneficiary association (VEBA) trusts. The
COM/Energy Post-Retirement Benefits Plans merged with and were
consolidated into the Group Welfare Benefits Plan for Retirees of
Boston Edison, which was then renamed the Group Welfare Benefits
Plan for Retirees of NSTAR and was transferred to NSTAR in 2001.
To fund postretirement benefits, Boston Edison makes
contributions to various VEBA trusts that were established
pursuant to section 501(c)(9) of the Internal Revenue Code.
The funded status of the Plan for 2001 cannot be presented
separately for the Company since the Company participates in the
Plan trusts with other subsidiaries of NSTAR. Plan assets are
available to provide benefits for all Plan participants who are
former employees of the Company and of other subsidiaries of
NSTAR.
The net periodic postretirement benefit cost allocated to the
Company was $14,096,000 and $12,732,000 in 2001 and 2000,
respectively. The accrued benefit cost in the Company's
statement of financial position was $0 and $16,982,000 at
December 31, 2001 and 2000, respectively.
As a result of the Company participating in a single NSTAR
sponsored plan effective January 1, 2000 where the assets are
held in the two VEBA trusts for the exclusive benefit of Plan
participants, the Company no longer reflects any plan assets or
liabilities.
For 2000, the changes in benefit obligation and plan assets were
as follows:
(in thousands) 2000
Change in benefit obligation:
Benefit obligation, beginning of the year $ 221,415
Service cost 2,100
Interest cost 17,816
Plan participants' contributions 754
Plan amendments 5,419
Actuarial loss/(gain) 22,129
Curtailment loss -
Settlement payments -
Benefits paid (14,024)
Benefit obligation, end of the year $ 255,609
=========
Change in plan assets:
Fair value of plan assets, beginning of the year 119,838
Actual (loss)/return on plan assets (12,276)
Employer contribution 53,407
Plan participants' contributions 754
Settlement payments -
Benefits paid (14,024)
Fair value of plan assets, end of the year $ 147,699
=========
The plans' funded status and amount recognized in the
accompanying Consolidated Balance Sheets were as follows:
(in thousands) 2000
Funded status $(107,910)
Unrecognized actuarial net loss/(gain) 36,907
Unrecognized transition obligation 67,400
Unrecognized prior service cost (13,378)
Net amount recognized $ (16,981)
=========
Weighted average assumptions were as follows:
2000 1999
Discount rate at the end of the year 7.50% 8.00%
Expected return on plan assets for the year 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.
Components of net periodic benefit cost were as follows:
(in thousands) 2000 1999
Service cost $ 2,100 $ 4,043
Interest cost 17,816 17,848
Expected return on plan assets (11,234) (10,107)
Amortization of prior service cost (1,566) (683)
Amortization of transition obligation 5,616 6,162
Recognized actuarial loss - 957
Net periodic benefit cost $ 12,732 $ 18,220
======== ========
Note E. Capital Stock
(dollars in thousands, except per share 2001 2000
amounts)
Common equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 100
shares issued and outstanding $ - $ -
Premium on common stock 528,795 482,004
Retained earnings 428,150 352,832
Total common equity $ 956,945 $ 834,836
======== ========
Cumulative Preferred Stock
(in thousands, except per share amounts)
Par value $100 per share, 2,660,000 shares authorized and 430,000
issued and outstanding:
Non-mandatory redeemable series:
Current Shares Redemption December 31,
Series Outstanding Price/Share
2001 2000
4.25% 180,000 $103.625 $18,000 $18,000
4.78% 250,000 $102.80 25,000 25,000
Total non-mandatory redeemable series 43,000 43,000
Mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
8.00% 500,000 $100.00 - 50,000
Less redemption and issuance costs - 481
Total mandatory redeemable series - 49,519
43,000 92,519
Less amount due within one year - 49,519
Total cumulative preferred stock $43,000 $43,000
======= =======
The 8% series was redeemed in total on December 3, 2001, plus
accrued dividends from November 1, 2001 to December 1, 2001.
1. Common Shares
Common shares issuances and repurchases in 1999 through 2001 were
as follows:
Common Shares
Number of
(in thousands) Shares Par Value Premium
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
Capital Contribution 43,937
Benefits and other 2,854
Balance at December 31, 2001 - $ - $ 528,795
======= ========= =========
(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.
Note F. Indebtedness
December 31,
(in thousands) 2001 2000
Long-term debt
Debentures:
6.80%, due March 2003 $ 150,000 $ 150,000
7.80%, due May 2010 125,000 125,000
9.375%, due August 2021 - 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 21,470 23,014
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
6.45%, due through September 2005 108,986 170,610
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
1,107,346 1,198,857
Amounts due within one year (41,6 39) (37,109)
Total long-term debt $ 1,065,707 $ 1,161,748
=========== ===========
1. Long-term Debt
The 9.375% series due 2021 was redeemed 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 2001 and 2000. The weighted average
interest rate of the bonds was 7.4%. 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 has approval from the MDTE to issue from time to
time up to $500 million of debt securities through 2002. In
connection with this, 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 SEC declared the registration statement
effective 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. No issuance of debt securities were made during 2001
under this authorization.
The aggregate principal amounts of Boston Edison's long-term debt
(including securitization certificates and HEEC sinking fund
requirements) due in the five years subsequent to 2001 are
approximately $41.6 million in 2002, $219.7 million in 2003,
$70.4 million in 2004, $70.1 in 2005 and $70.3 in 2006.
Boston Edison has no covenant requirements under its long-term
debt arrangements.
2. Short-term Debt
Boston Edison has approval from the FERC to issue up to $350
million of short-term debt. Boston Edison has a $300 million
revolving credit agreement with a group of banks effective
through December 2002. At December 31, 2001 and 2000, there were
no amounts outstanding under this revolving credit agreement.
This arrangement serves as back-up to Boston Edison's $300
million commercial paper program that, at December 31, 2001 and
2000, had outstanding $191.5 million and $96.5 million,
respectively. Under the terms of this agreement, Boston Edison
is required to maintain a common equity ratio of not less than
30% at all times. Interest rates on the outstanding borrowings
generally are money market rates and averaged 4.14% and 6.61% in
2001 and 2000, respectively. Commitment fees must be paid on the
total agreement amount. Separately, Boston Edison, effective
July 20, 2001, has an additional $50 million line of credit with
no outstanding amounts at December 31, 2001.
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:
1. Cash and Cash Equivalents
The carrying amount of $14 million and $12 million, for 2001 and
2000, respectively, approximates fair value due to the short-term
nature of these securities.
2. Mandatory Redeemable Cumulative Preferred Stock and Unsecured
Debt (Excluding Notes Payable)
The fair values of these securities are based upon the quoted
market prices of similar issues. Carrying amounts and fair values
as of December 31, 2001 and 2000 were as follows:
2001 2000
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Mandatory redeemable cumulative preferred
stock - - $ 49,519 $ 50,890
Long-term unsecured debt $1,107,346 $1,153,380 $1,198,857 $1,198,695
(including current maturities)
Note H. Commitments and Contingencies
1. Contractual Commitments
Boston Edison also has leases for certain facilities and
equipment. The estimated minimum rental commitments under non-
cancelable capital and operating leases for the years after 2001
are as follows:
(in thousands)
2002 $ 14,244
2003 11,634
2004 10,978
2005 10,870
2006 10,126
Years thereafter 43,936
Total $ 101,788
=========
The total expense for both lease rentals and transmission
agreements was $57.1 million in 2001, $45.3 million in 2000 and
$38.7 million in 1999, net of capitalized expenses of $2.3
million in 2001, $1.7 million in 2000 and $1.5 million in 1999.
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 obligations of those participants
who do not meet certain credit criteria. At December 31, 2001,
Boston Edison's portion of these guarantees was $10.9 million.
New England Hydro-Transmission Electric Company, Inc. (NEH) and
New England Hydro-Transmission Corporation (NHH) have agreed to
use their best efforts to limit their equity investment to 40% of
their total capital during the time NEH and NHH have outstanding
debt in their capital structure. In order to meet its best
efforts obligation pursuant to the Equity Funding Agreement dated
June 1, 1985, as amended, for NEH and NHH, in September 2001, NEH
repurchased a total of 250,000 of its outstanding shares from all
equity holders and NHH repurchased a total of 1,100 outstanding
shares from all equity holders. Through December 31, 2001,
Boston Edison's reduction of its equity ownership resulting from
NEH buy-back of 27,627 shares and NHH buy-back of 122 shares was
approximately $622,000.
Boston Edison has a 9.5% equity investment 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. As of December 31, 2001, this program was
completed and 145,730 shares were redeemed. Boston Edison's
reduction of its equity ownership resulting from the buy-back of
13,844 shares was approximately $1.4 million.
Boston Edison also has a 9.5% equity investment in the
Connecticut Yankee Atomic Power Company (CYAPC) unit that has
been retired. Boston Edison's share of CYAPC remaining
investment and estimated costs of decommissioning is
approximately $23 million as of December 31, 2001. This estimate
was 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. During April 2000, CYAPC signed settlement
agreements with the major intervening parties in the 1996 FERC
rate case. CYAPC received final FERC approval related to the
settlement agreements and revised rates went into effect
September 1, 2000. CYAPC received FERC approval on September 11,
2000, regarding the decommissioning collections, a return on
equity of 6% and full recovery of assets.
3. Environmental Matters
Boston Edison is involved in approximately 15 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 properties due to the
final method of cleanup and site-specific characteristics. 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 $4.8 million is included in the
Consolidated Balance Sheets as of December 31, 2001 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 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 1998 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 and the results of operations for a reporting period.
Regulatory proceedings
In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the AG
contested cost allocations related to Boston Edison's wholesale
customers. On June 1, 2001, the MDTE approved Boston Edison's
revenue-credit approach for wholesale sales to be consistent with
Boston Edison's restructuring settlement. The reconciliation of
wholesale revenues and costs, along with other reconciliation
issues, were addressed in Boston Edison's 2000 filing covering
the reconciliation of costs through December 31, 2000. On
November 16, 2001, the MDTE approved a Settlement Agreement
between Boston Edison and the AG resolving all outstanding issues
in this filing. This settlement agreement did not have a
material effect on Boston Edison's consolidated financial position or
results of operations.
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, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities. On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million. BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002. Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs. Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets. This change had no
material adverse effect on Boston Edison's consolidated financial
position or results of operations.
Other legal matters
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
in the near term.
Note I. Long-Term Power Contracts
Long-Term Contracts for the Purchase of Electricity
NSTAR Electric has existing long-term power purchase agreements
that are expected to supply approximately 90%-95% of its standard
offer service obligations. NSTAR Electric has entered into a
series of short-term power purchase agreements to meet its entire
default service supply obligations and its remaining unmet
standard offer supply obligations through December 31, 2002.
NSTAR Electric expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the Restructuring Act and MDTE
orders.
Capacity costs of long-term contracts reflect Boston Edison's
proportionate share of capital and fixed operating costs of
certain generating units. In 2001, these costs were attributed
to 892 MW of capacity purchased. Energy costs are paid to
generators based on a price per kWh actually received into Boston
Edison's distribution system and are included in the total cost.
Total capacity purchased in 2001 was 1,362 MW.
Information related to long-term power contracts as of December
31, 2001 was as follows:
Proportionate share (in
thousands)
Range of Units of Capacity Charge
Contract Capacity 2001 2001 Obligation
Fuel Type of Exploration Purchased Capacity Total Through Contract
Generating Unit Dates % Range Total Cost Cost Expiration Date
MW
Natural Gas 2010-2015 23.5-46.5 480 $68,397 $241,294 $ 951,916
Nuclear 2004 78 673 - 141,402 -
Oil 2002-2019 25-100 209 11,004 32,656 58,842
1,362 $79,401 $415,352 $1,010,758
===== ======= ======== ==========
NSTAR Electric entered into six-month agreements effective
January 1, 2001 through June 30, 2001 and July 1, 2001 through
December 31, 2001 with suppliers to provide full default service
energy and ancillary service requirements at contract rates
substantially similar to MDTE-approved tariff rates. NSTAR
Electric's existing portfolio of power purchase contracts
supplied the majority of its standard offer (including wholesale)
energy requirements in 2001, supplemented with long-term and
daily purchases/sales in the bilateral and spot markets. In
addition, NSTAR Electric managed its Independent System Operator-
New England Power capability responsibilities, congestion and
uplift costs associated with default service and standard offer
load throughout 2001.
Boston Edison's total capacity and energy costs associated with
these contracts in 2001, 2000 and 1999 were approximately $415
million, $428 million and $315 million, respectively. Boston
Edison's capacity charge obligation under these contracts for the
years after 2001 is as follows:
Capacity
(in thousands) Charge
Obligation
2002 $ 86,683
2003 84,288
2004 84,055
2005 85,589
2006 86,913
Years thereafter 583,230
Total $1,010,758
==========
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, 2001, 2000 and 1999 26
Consolidated Statements of Comprehensive Income for
the years ended December 31, 2001, 2000 and 1999 27
Consolidated Statements of Retained Earnings for the
years ended December 31, 2001, 2000 and 1999 27
Consolidated Balance Sheets as of December 31, 2001 28
and 2000
Consolidated Statements of Cash Flows for the years
ended December 31, 2001, 2000 and 1999 29
Report of Independent Accountants 25
Notes to Consolidated Financial Statements 30
2. Financial Statement Schedules:
Schedule II Valuation and Qualifying Accounts - For the
Years Ended December 31, 2001, 2000 and 1999 58
3. Exhibits:
Refer to the exhibits listing beginning on the 51
following page
(b) Reports on Form 8-K
None
Incorporated herein by reference:
(S>
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 January Form 10-Q for
22, 1987, January 28, 1988, May 24, the quarter
1988 and November 22, 1989 ended June
30, 1994.
Exhibit 4 Instruments Defining the
Rights of Security Holders,
Including Indentures
4.1 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.
4.2 Indentures of Trust and Agreement 4.1.26 1-2301
among the City of Boston, Form 10-K for
Massachusetts (acting by and the year
through its Industrial Development ended
Financing Authority) and Harbor December 31,
Electric Energy Company and Shawmut 1991.
Bank, N.A., as Trustees dated
November 1, 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 for
19, 1995 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 for
1, 1997 the year
ended
December 31,
1997.
4.5 Votes of the Pricing Committee 4.1.25 1-2301
of the Board of Directors of Boston Form 10-K for
Edison Company taken September 10, the year
1992 re 8 % debentures due ended
September 15, 2022. December 31,
1992.
4.6 Votes of the Pricing Committee of 4.1.27 1-2301
the Board of Directors of Boston Form 10-K for
Edison Company taken March 5, 1993 the year
re 6.80% debentures due March ended
15,2003, 7.80% debentures due December 31,
March 15, 2023 1992.
4.7 Votes of the Pricing Committee of 4.1.5 1-2301
the Board of Directors of Boston Form 10-K for
Edison Company taken May 18, 1995 the year
re 7.80% debentures due May 15, ended
2010. December 31,
1995.
4.9 Debt Securities to be issued on a Form S-3 -
delayed or continuous basis under Registration
an Indenture between Boston Edison Statement,
Company and The Bank of New York dated
(as successor to Bank of Montreal February 20,
Trust Company) 2001, 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 Restructuring 10.12 1-2301
Settlement Agreement dated July 1997 Form 10-K for
the year
ended
December 31,
1997.
10.2 Boston Edison Company and Sithe 10.1 1-2301
Energies, Inc. Purchase and Sale Form 10-Q for
and Transition Agreements dated the quarter
December 10, 1997. ended
March 31,
1998.
10.3 Boston Edison Company and Entergy 10.12 1-2301
Nuclear Generation Company Purchase Form 10-K for
and Sale Agreement dated November the year
18, 1998. ended
December 31,
1999.
10.4 NSTAR Excess Benefit Plan effective 10.1 1-14768
August 25, 1999. (NSTAR)
Form 10-K/A
for the year
ended
December 31,
1999.
10.5 NSTAR Supplemental Executive 10.2 1-14768
Retirement Plan effective August (NSTAR)
25, 1999. Form 10-K/A
for the year
ended
December 31,
1999.
10.6 Special Supplemental Executive 10.3 1-14768
Retirement Agreement between Boston (NSTAR)
Edison Company and Thomas J. May Form 10-K/A
dated March 13, 1999, regarding Key for the year
Executive Benefit Plan and ended
Supplemental Executive Retirement December 31,
Plan. 1999.
10.7 Key Executive Benefit Plan 10.4 1-14768
Agreement dated as of October 1, (NSTAR)
1983 between Boston Edison Company Form 10-K/A
and Thomas J. May. for the year
ended
December 31,
1999.
10.8 Change in Control Agreement between 10.9 1-14768
NSTAR and Thomas J. May dated May (NSTAR)
11, 1999. Form 10-K/A
for the year
ended
December 31,
1999.
10.9 NSTAR Deferred Compensation Plan 10.12 1-14768
(Restated Effective August 25, (NSTAR)
1999). Form 10-K/A
for the year
ended
December 31,
1999.
10.10 NSTAR 1997 Share Incentive Plan, as 10.14 1-14768
amended June 30, 1999 and assumed (NSTAR)
by NSTAR effective August 28, 2000. Form 10-Q for
the quarter
ended
September 30,
2000.
10.11 Amended and Restated Change in 10.9 NSTAR Form
Control Agreement between James J. 10-K for the
Judge and NSTAR, dated November 1, year ended
2001. December 31,
2001, File
No. 1-14768.
10.12 Amended and Restated Change in 10.12 NSTAR Form
Control Agreement between Douglas 10-K for the
S. Horan and NSTAR, dated November 1, year ended
2001. December 31,
2001, File
No. 1-14768.
10.13 Amended and Restated Change in 10.13 NSTAR Form
Control Agreement between Joseph R. 10-K for the
Nolan, Jr. and NSTAR, dated year ended
November 1, 2001. December 31,
2001, File
No. 1-14768.
10.14 Amended and Restated Change in 10.14 NSTAR Form
Control Agreement between Eugene J. 10-K for the
Zimon and NSTAR, dated November 1, year ended
2001. December 31,
2001, File
No. 1-14768.
10.15 Amended and Restated Change in 10.15 NSTAR Form
Control Agreement between Werner J. 10-K for the
Schweiger and NSTAR, dated March 1, year ended
2002. December 31,
2001, File
No. 1-14768.
10.16 Master Trust Agreement between 10.5 NSTAR Form
NSTAR and State Street Bank and 10-Q for the
Trust Company (Rabbi Trust), dated quarter ended
August 25, 1999 September 30,
2000, File
No. 1-14768.
10.17 Employment Agreement between Thomas NSTAR Form S-
J. May and NSTAR dated May 11, 1999 4, Annex A,
(Incorporated by reference to Annex) Dated May 11,
1999, File
No. 333-78285.
10.18 NSTAR Trustees' Deferred Plan 10.4 NSTAR Form
(Restated Effective August 25, 10-Q for the
1999), dated October 20, 2000 quarter ended
September 30,
2000, File
No. 1-14768.
Filed herewith:
Exhibit 12 Statement to Computation of Ratios
12.1 Computation of Ratio of Earnings to Form 10-K for
Fixed Charges for the Year Ended the year
December 31, 2001 ended
December
2001.
File No.
1-2301
12.2 Computation of Ratio of Earnings to Form 10-K for
Fixed Charges and Preferred Stock the year
Dividend Requirements for the Year ended
Ended December 31, 2001 December 31,
2001.
File No.
1-2301
Incorporated herein by reference:
Exhibit 21 Subsidiaries of the Registrant
21.1 Harbor Electric Energy Company Form 10-K for
(incorporated in Massachusetts), a the year
wholly owned subsidiary of Boston ended
Edison Company December 31,
1999.
File No.
1-2301
Filed herewith:
Exhibit 23 Consent of Independent Accountants
23.1 Consent of Independent Accountants Form 10-K for
to incorporate by reference their the year
opinion included with this Form ended
10-K in the Form S-3 Registration December 31,
Statements filed by Boston Edison 2000.
Company on February 1, 1993 (File File No.
No. 33-57840) and February 20, 2001 1-2301
(File No. 333-55890).
Incorporated herein by reference:
Exhibit 99 Additional Exhibits
99.1 Settlement Agreement between Boston 28.1 Form 8-K
Edison Company and Commonwealth dated
Electric Company, Montaup Electric December 21,
Company the Municipal Light 1989.
Department of the Town of Reading, File No.
Massachusetts, dated January 5,1990. 1-2301
99.2 Settlement Agreement Between Boston 28.2 Form 10-Q for
Edison Company and City of Holyoke the quarter
Gas and Electric Department et. ended March 31,
Al., dated April 24, 1990. 1990. File No.
1-2301
99.3 Information required by SEC Form Form 10-K/A
11-K for certain employee benefit Amendments to
plans for the years ended December Form 10-K for
31, 1996 and 1995. the years
ended
December 31,
1996 and 1995
dated June
26, 1997 and
June 27, 1996
respectively.
File No.
1-2301
SCHEDULE II
BOSTON EDISON COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 and 1999
(in thousands)
Balance at Provisions Deductions Balance
Beginning Charged to Accounts At End
Description Of Year Operations Recoveries Written Off Of Year
Year Ended
December 31, 2001
Allowance for
Doubtful Accounts $22,415 $13,000 $ 2,089 $ 12,813 $24,691
Year Ended December 31, 2000
Allowance for
Doubtful Accounts $19,380 $11,954 $ 471 $(9,38 0) $22,415
Year Ended
December 31, 1999
Allowance for
Doubtful Accounts $ 9,071 $22,649 $ 4,356 $(16,696) $19,380
FORM 10-K BOSTON EDISON
COMPANY DECEMBER 31, 2001
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)
Date: March 28,2002 By: /s/ JAMES J. JUDGE
James J. Judge,
Senior Vice President, Treasurer
and Chief Financial 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 Officer:
/s/ THOMAS J. MAY March 28, 2002
Thomas J. May,
Chairman of the Board, President and
Chief Executive Officer
Principal Financial Officer:
/s/ JAMES J. JUDGE March 28, 2002
James J. Judge,
Senior Vice President, Treasurer and
Chief Financial Officer
Principal Accounting Officer:
/s/ ROBERT J. WEAFER, JR. March 28, 2002
Robert J. Weafer, Jr.,
Vice President, Controller and
Chief Accounting Officer
A majority of the Board of Directors:
/s/ THOMAS J. MAY March 28, 2002
Thomas J. May, Director
/s/ JAMES J. JUDGE March 28, 2002
James J. Judge, Director
/s/ DOUGLAS S. HORAN March 28, 2002
Douglas S. Horan, Director