Back to GetFilings.com
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, 2002
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 27, 2003
Common Stock, $1 par 75 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 by Reference Part in Form 10-K
None Not Applicable
List of Exhibits begins on page 54 of this report.
Boston Edison Company
Form 10-K Annual Report
December 31, 2002
Part I Page
Item 1. Business 2
Item 2. Properties 7
Item 3. Legal Proceedings 8
Part II
Item 5. Market for the Registrant's Common Stock and
Related Stockholder Matters 9
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 9
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 53
Part IV
Item 14. Controls and Procedures 53
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 54
Signatures 58
Certification Statements 59
Part I
Item 1. Business
Boston Edison Company makes available on its website at
www.nstaronline.com ("SEC filings") its annual report on Form
10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K, and all amendments to those reports as soon as
reasonably practicable after such material is electronically
filed with or furnished to the Securities and Exchange
Commission (SEC). The Company provides this service
free of charge.
(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 wholly owned subsidiary of NSTAR. NSTAR is an
energy delivery company focusing its activities in the
transmission and distribution of energy. NSTAR serves
approximately 1.4 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 0.3 million gas customers in 51 communities. Boston Edison
serves approximately 683,000 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). 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
Massachusetts Department of Telecommunications and Energy (MDTE).
These certificates are non-recourse to Boston Edison.
NSTAR was created in 1999 through the merger of BEC Energy (BEC)
and Commonwealth Energy System (COM/Energy). An integral part of
the merger was the rate plan of the retail utility subsidiaries
of BEC, which includes Boston Edison, and COM/Energy that was
approved by the MDTE in an order on July 27, 1999. Significant
elements of the rate plan included 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 "Rate and Regulatory
Proceedings" section in Item 7, Management's Discussion and
Analysis of Financial Condition and Results of Operations, 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
2002, Boston Edison served an average of approximately 683,000
customers. Boston Edison also supplies electricity at wholesale
for resale to municipal electric departments. Electric operating
revenues by customer class for the last three years consisted of
the following:
2002 2001 2000
Retail electric revenues:
Commercial 55% 57% 53%
Residential 33% 31% 30%
Industrial 7% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 4% 2% 7%
Retail Electric Rates
As a result of electric industry restructuring, Boston Edison
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.
The 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 February 2005 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 Boston Edison's 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, 2002 and 2001, customers of
Boston Edison had approximately 28% and 20%, respectively, of
their load requirements provided by competitive suppliers.
During 2000, Boston Edison's accumulated cost to provide default
and standard offer service was in excess of the revenues it was
allowed to bill by approximately $193.6 million. On January 1
and July 1, 2001, Boston Edison received approval from the MDTE
to increase its rates to customers for standard offer and default
service to collect this shortfall. Furthermore, when combined
with the reduction in energy supply costs experienced in 2001 and
through the first half of 2002, rates were reduced on January 1,
2002, April 1, 2002, July 1, 2002 and January 1, 2003. At
December 31, 2002, Boston Edison's accumulated cost to provide
default and standard offer service was in excess of the revenues
it was allowed to bill by approximately $8.7 million. This
amount is reflected as a component of Regulatory assets
on the accompanying Consolidated Balance Sheets.
Sources and Availability of Electric Power Supply
Boston Edison has existing long-term power purchase agreements
that are expected to supply approximately 75% of its standard
offer service obligation for 2003. Boston Edison has contracted
for its standard offer supply obligation through December 31,
2003. Boston Edison expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the 1997 Restructuring Act and MDTE
orders. Boston Edison is recovering its payments to suppliers
through MDTE-approved rates billed to customers. Boston Edison's
existing portfolio of long-term power purchase contracts supplied
the majority of its standard offer (including wholesale) energy
requirements in 2002. Also during 2002, Boston Edison entered
into an agreement whereby all of its energy supply resource
entitlements were transferred to an independent energy supplier,
following which Boston Edison repurchased its energy resource
needs from this independent energy supplier for Boston Edison's
ultimate sale to standard offer customers.
Boston Edison has entered into a short-term power purchase
agreement to meet its entire default service supply obligation
for the period January 1, 2003 through June 30, 2003 and for 50%
of its obligation for the second-half of 2003. A Request for
Proposals will be issued in the second quarter of 2003 for the
remainder of the obligation. Boston Edison entered into
agreements ranging in length from five to twelve-months effective
January 1, 2002 through December 31, 2002 with suppliers to
provide full default service energy and ancillary service
requirements at contract rates approved by the MDTE.
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.
Independent System Operator - New England (ISO-NE)
Prior to March 1, 2003, ISO-NE dispatched generating units based
on the lowest operating costs of available generation and
transmission. Under this structure, generators were required to
provide ISO-NE with market prices at which they sell short-term
energy supply. For each participant actively involved in the
power market, the imbalance in energy provided by a participant
and the energy consumed by such participant in each hour is
settled at a single real-time clearing hourly price for such
power. Pursuant to orders issued by the Federal Energy
Regulatory Commission (FERC) in September and December of 2002,
these markets have been further restructured into Standard Market
Design (SMD), which began on March 1, 2003. SMD provides an
additional market in which wholesale power costs can be hedged a
day in advance through binding financial commitments. Also,
under SMD, wholesale power clearing prices vary by location, with
prices increasing in areas where less efficient resources close
to the load are dispatched to meet the load requirements due to
the fact that the more efficient resources cannot be imported as
a result of transmission limitations. As part of the movement to
SMD, load-serving entities, like Boston Edison, will be granted
proceeds from the auction of "financial transmission rights" that
is conducted by ISO-NE. Holders of these rights are essentially
entitled to the positive differences in the prices between the
locations specified for such rights and are subject to additional
costs for negative differences. Boston Edison can either use
these proceeds to mitigate costs to customers directly or
transfer them to the suppliers of its energy resource needs to
reduce the cost to customers. Therefore, the impact of the
change to SMD on Boston Edison's costs to meet its standard offer
service and default service obligations are mitigated somewhat.
Franchises
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, 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.
Capital Expenditures and Financings
The most recent estimates of plant expenditures and long-term
debt maturities for the years 2003 through 2007 are as follows:
(in thousands) 2003 2004 2005 2006 2007
Capital expenditures $186,000 $172,000 $139,000 $122,000 $124,000
Long-term debt $191,242 $ 70,390 $170,052 $70,254 $70,170
Management continuously reviews its capital expenditure and
financing programs. These programs and, therefore, the estimates
included in this Form 10-K are subject to revision due to changes
in regulatory requirements, operating requirements, environmental
standards, availability and cost of capital, interest rates and
other assumptions.
Plant expenditures in 2002 and 2001 were $239 million and $138.6
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.
Seasonal Nature of Business
Boston Edison's kilowatt-hour sales and revenues are typically
higher in the winter and summer than in the spring and fall as
sales tend to vary with weather conditions.
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.
There were no environmental-related capital expenditures for the
years 2002 and 2001. Management believes that its facilities are
in substantial compliance with currently applicable statutory and
regulatory environmental requirements. Additional expenditures
could be required as changes in environmental requirements occur.
Employees and Employee Relations
Management, engineering, financing and support services are
provided to Boston Edison by employees of NSTAR Electric & Gas.
As of December 31, 2002, NSTAR Electric & Gas had approximately
3,200 employees, including approximately 2,300 or 73% of whom are
represented by two collective bargaining units covered by
separate contracts. The five-year labor contract with Local 369
of the Utility Workers Union of America, AFL-CIO covering
approximately 2,075 employees expires May 15, 2005. A labor
contract with Local 12004, United Steelworkers of America, AFL-
CIO-CLC covering 260 employees has a four-year term that expires
on March 31, 2006.
Management believes it has satisfactory relations with its
employees.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales
Boston Edison delivers electricity to retail and wholesale
customers in the Boston area. Boston Edison does not have any
foreign operations or export sales.
Item 2. Properties
Boston Edison properties include 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 transmission lines are generally located on land
either owned or subject to easements in its favor. Its
distribution lines are located principally on public property
under permission granted by municipal and other state
authorities.
As of December 31, 2002, primary and secondary overhead and
underground distribution systems cover approximately 10,900 and
6,000 circuit miles, respectively. In addition, Boston Edison's
transmission system consists of 127 substation facilities and
approximately 720,400 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
Merger Rate Plan
On December 16, 2002, the Massachusetts Supreme Judicial Court
(SJC) upheld the MDTE's 1999 decision to allow for the merger of
BEC and COM/Energy as originally structured. The SJC decision
finalized the resolution of all issues related to the appeal and
did not have any impact on Boston Edison's 2002 or prior periods'
consolidated financial position, cash flows or results of
operations. The 1999 MDTE order approving the rate plan
associated with the merger of BEC and COM/Energy, was appealed to
the SJC by the Massachusetts Attorney General (AG) and a separate
group that consisted of The Energy Consortium (TEC) and Harvard
University (Harvard). TEC and Harvard alleged that, in approving
the rate plan and merger proposal, the MDTE committed errors of
law in the following areas: (1) in adopting a public interest
standard, the MDTE applied the wrong standard of review, and
failed to investigate the propriety of rates and to determine
that the resulting rates of Boston Edison, Cambridge Electric,
ComElectric and NSTAR Gas were just and reasonable; (2) that in
permitting Cambridge Electric and ComElectric to adjust their
rates by $49.8 million to reflect demand-side management costs,
the MDTE failed to determine whether such an adjustment was
warranted in light of other cost decreases; (3) that the MDTE's
approval results in an arbitrary and unjustified sharing of
benefits and costs between ratepayers and shareholders; and (4)
that the MDTE's approval of the rate plan guarantees shareholders
recovery of future costs without any future demonstration of
customer savings. The AG's brief included similar arguments in
each of these areas and added that, in allowing recovery of the
acquisition premium, the MDTE improperly deviated from a cost
basis in setting approved rates and the ratemaking policies in
other jurisdictions.
Other legal matters
In the normal course of its business, Boston Edison and its
subsidiaries are involved in certain legal matters, including
civil lawsuits. Management is unable to fully determine a range
of reasonably possible court-ordered damages, settlement amounts,
and related litigation costs ("legal liabilities") that would be
in excess of amounts accrued. Based on the information currently
available, Boston Edison does not believe that it is probable
that any such additional legal liability will have a material
impact on its consolidated financial position. However, it is
reasonably possible that additional legal liabilities that may
result from changes in estimates could have a material impact on
its results of operations 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 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, 2002.
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations (MD&A)
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 focusing its activities in the transmission and
distribution of energy. NSTAR serves approximately 1.4 million
customers in Massachusetts, including approximately 1.1 million
electric customers in 81 communities and 0.3 million gas
customers in 51 communities. Boston Edison serves approximately
683,000 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). 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 Restructuring Act and
authorized by the MDTE. These certificates are non-recourse to
Boston Edison.
Cautionary Statement
This MD&A 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 also be contained in other filings with
the SEC, 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 sensitive to weather, the
economy and other variable conditions, 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 summer 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, and prices and
availability of operating supplies could materially affect the
projected operating results.
Boston Edison's forward-looking information depends in large
measure on prevailing governmental policies and regulatory
actions, including those of the MDTE and the FERC, with respect
to allowed rates of return, rate structure, continued recovery of
regulatory assets, 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.
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
filings to the SEC. Also note that Boston Edison provides in the
above paragraphs a cautionary discussion of risks and other
uncertainties relative to its business. These are factors that
could cause its actual results to differ materially from expected
and historical performance. Other factors in addition to those
listed here could also adversely affect Boston Edison. This
report also describes material contingencies and critical
accounting policies and estimates in this section and in the
accompanying Notes to Consolidated Financial Statements, and
Boston Edison encourages a review of these Notes.
Critical Accounting Policies and Estimates
Boston Edison's discussion and analysis of its financial
condition, results of operations and cash flows are based upon
the accompanying Consolidated Financial Statements, which have
been prepared in accordance with accounting principles generally
accepted in the United States of America (GAAP). The preparation
of these Consolidated Financial Statements required management to
make estimates and judgments that affect the reported amount of
assets and liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities at the date of
the Consolidated Financial Statements. Actual results may differ
from these estimates under different assumptions or conditions.
Critical accounting policies and estimates are defined as those
that are reflective of significant judgment and uncertainties,
and potentially may result in materially different outcomes under
different assumptions and conditions. Boston Edison believes
that its accounting policies and estimates that are most critical
to the reported results of operations, cash flows and financial
position are described below.
a. Revenue Recognition
Utility revenues are based on authorized rates approved by the
FERC and the MDTE. Estimates of transmission, distribution and
transition revenues for electricity delivered to customers but
not yet billed are accrued at the end of each accounting period.
The determination of unbilled revenues requires management to
estimate the volume and pricing of electricity delivered to
customers prior to actual meter readings.
Revenues related to the sale, transmission and distribution of
electricity are generally recorded when service is rendered or
energy is delivered to customers. However, the determination of
the electricity sales to individual customers is based on the
reading of their meters which are read on a systematic basis
throughout the month. Meters which are not read during a given
month are estimated and trued-up in a future period. At the end
of each month, amounts of electricity delivered to customers
since the date of the last billing date are estimated and the
corresponding unbilled revenue is estimated. This unbilled
revenue is estimated each month based on daily generation volumes
(territory load), line losses and applicable customer rates.
Accrued unbilled revenues recorded in the accompanying
Consolidated Balance Sheets as of December 31, 2002 and 2001 were
$21.5 million and $29.1 million, respectively.
b. Regulatory Accounting
Boston Edison follows accounting policies prescribed by GAAP, the
FERC and the MDTE. As a rate-regulated company, Boston Edison is
subject to the Financial Accounting Standards Board (FASB)
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 revenues and expenses from that
of other businesses and industries. Boston Edison's energy
delivery business remains subject to rate-regulation and
continues to meet the criteria for application of SFAS 71. This
ratemaking process results in the recording of regulatory assets
based on the probability of current and future cash flows.
Regulatory assets represent incurred costs that have been
deferred because they are probable of future recovery in customer
rates. As of December 31, 2002 and 2001, Boston Edison has
recorded regulatory assets of $1,265 million and $768.7 million,
respectively. This increase is primarily the result of the
recognition of certain purchased power costs. Boston Edison
continuously reviews these assets to assess their ultimate
recoverability within the approved regulatory guidelines. Boston
Edison expects to fully recover these regulatory assets in its
rates. If future recovery of costs ceases to be probable, Boston
Edison would be required to charge these assets to current
earnings. However, impairment risk associated with these assets
relates to potentially adverse legislative, judicial or
regulatory actions in the future. Regulatory assets related to
the generation business are recovered through the transition
charge.
c. Derivative Instruments - Power Contracts
Typically, the electric power industry contracts to buy and sell
electricity under option contracts, which allow the buyer some
flexibility in determining when to take electricity and in what
quantity to match fluctuating demand. These contracts would
normally meet the definition of a derivative requiring mark-to-
market accounting. However, because electricity cannot be stored
and an entity is obligated to maintain sufficient capacity to
meet the electricity needs of its customer base, an option
contract for the purchase of electricity typically qualifies for
the normal purchases and sales exception described in SFAS No.
133, "Accounting for Derivative Instruments and Hedging
Activities" and Derivative Implementation Group (DIG) Issue No.
C15, "Scope Exceptions: Normal Purchases and Normal Sales
Exception for Option-Type Contracts and Forward Contracts in
Electricity."
Boston Edison has long-term purchased power agreements that are
used primarily to meet its standard offer obligation. The
majority of these agreements are above-market but are not
reflected on the accompanying Consolidated Balance Sheets as they
qualify for the normal purchases and sales exception. However,
in Issue C15, the DIG concluded that contracts with a pricing
mechanism that are subject to future adjustment based on a
generic index that is not specifically related to the contracted
service commodity generally would not qualify for the normal
purchases and sales exception. Boston Edison has one purchased
power contract that contains components with pricing mechanisms
that are based on a pricing index, such as the GNP or CPI.
Although these factors are only applied to certain ancillary
pricing components of the agreement, as required by the
interpretation of DIG Issue C15, Boston Edison began recording
this contract at fair value on the Consolidated Balance Sheets
during 2002. This action resulted in the recognition of a
liability for the fair value of the above-market portion of this
contract at December 31, 2002 of approximately $305 million and
is reflected as a component of Deferred credits - Power contracts
on the accompanying Consolidated Balance Sheets.
This contract is valued using a discounted cash flow model and a
10% discount rate. The market value assumption used was provided
by a third party who determines such pricing for the New England
power market. Had management used an alternative assumption, the
value of this contract at December 31, 2002 would have changed
significantly. A one percent increase or decrease to the
discount rate would change the above-market value by
approximately $12 million from what is presently recorded.
Boston Edison recovers all of its electricity supply costs,
including the above-market costs. The recovery of its above-
market costs occurs through 2016. The recovery period coincides
with the contractual terms of this purchased power agreement.
Therefore, in addition to the liability recorded, Boston Edison
also recorded a corresponding regulatory asset representing the
future recovery of these actual costs.
d. Pension and Other Postretirement Benefits
Boston Edison is the sponsor of NSTAR's qualified Pension Plan
(the Plan). As its sponsor, Boston Edison allocates the costs of
the Plan among itself and the other NSTAR subsidiary companies
based on a percentage of total direct labor charged to the
Company.
The Company's pension and other postretirement benefits costs are
dependent upon several factors and assumptions, such as employee
demographics, the level of cash contributions made to the plan,
earnings on the plans' assets, the discount rate, the expected
long-term rate of return on the plans' assets and health care
cost trends.
In accordance with SFAS No. 87, "Employers' Accounting for
Pensions," and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106), changes
in pension and postretirement benefit obligations other than
pensions (PBOP) associated with these factors may not be
immediately recognized as pension and PBOP costs in the
statements of income, but generally are recognized in future
years over the remaining average service period of the plans'
participants.
There were no changes to pension plan benefits in 2002, 2001 and
2000 that had a significant impact on recorded pension costs. As
further described in Note D to the accompanying Consolidated
Financial Statements, the Company has revised the discount rate
in 2002 as compared to 2001 and 2000. In addition, the Company
revised the expected long-term rate of return on its pension and
PBOP plan assets for 2003 to 8.4% and 8% respectively, reduced
from 9.4% and 9% in 2002, respectively. These changes will have
a significant impact on reported pension costs in future years in
accordance with the cost recognition approach of SFAS 87
described above. This impact will be mitigated, to an extent,
through the Company's regulatory accounting treatment of pension
and PBOP costs. (See further discussion of regulatory accounting
treatment below). In determining pension obligation and cost
amounts, these assumptions may change from period to period, and
such changes could result in material changes to recorded pension
and PBOP costs and funding requirements.
The Plan's assets, which partially consist of equity investments,
have been affected by significant declines in the equity markets
in the past three years. Fluctuations in equity market returns
may result in increased or decreased pension costs in future
periods. These conditions impacted the funded status of the Plan
at December 31, 2002, and therefore, will also impact pension
costs for 2003.
The following chart reflects the projected benefit obligation and
cost sensitivities associated with a change in certain actuarial
assumptions by the indicated percentage. Each sensitivity below
reflects an evaluation of the change based solely on a change in
that assumption. Only a portion of the impact indicated would be
allocated to the Company.
(in thousands)
Impact on
Projected
Change in Benefit Impact on 2002 Cost
Actuarial Assumption Assumption Obligation (Increase)/Decrease
Increase in discount rate 50 basis points $ (48,693) $ (3,220)
Decrease in discount rate 50 basis points $ 52,580 $ 3,410
Increase in expected long-term 50 basis points NA $ 3,935
rate of return on plan assets
Decrease in expected long-term 50 basis points NA $ (3,935)
rate of return on plan assets
NA - Not applicable
The discount rate is based on rates of high quality corporate
bonds as published by nationally recognized rating agencies.
In determining the long-term rate of return on plan assets, the
Company considers past performance and economic forecasts for the
types of investments held by the Plan. In 2003, the Company
reduced the expected long-term rate of return on plan assets from
9.4% to 8.4% as a result of the prevailing outlook for equity
market returns. Reported pension costs will increase in 2003 and
future years as a result of this changed assumption. However, as
a result of the MDTE Accounting Order (Accounting Order)
discussed below, this increase will not have a material impact on
the Company's results of operations.
The unfavorable market conditions have impacted the value of Plan
assets. As a result of the negative investment performance, the
Plan's accumulated benefit obligation (ABO) exceeded Plan assets
at December 31, 2002. The ABO represents the present value of
benefits earned without considering future salary increases.
Since the fair value of its Plan assets is less than the ABO, the
Company is required to record this difference as an additional
minimum pension liability on the accompanying Consolidated
Balance Sheets.
Under SFAS 87, the Company is also required to eliminate its
prepaid pension balance. The additional minimum pension
liability adjustment is equal to the sum of the minimum pension
liability and the prepaid pension that would be recorded, net of
taxes, as a non-cash charge to Other Comprehensive Income (OCI)
on the accompanying Consolidated Statements of Comprehensive
Income. The fair value of Plan assets and the ABO are measured
at each year-end balance sheet date. The minimum liability will
be adjusted each year to reflect this measurement. At such time
that the Plan assets exceed the ABO, the minimum liability would
be reversed.
In November 2002, the Company and certain affiliates filed a
request with the MDTE seeking an accounting ruling to mitigate
the impact of the non-cash charge to OCI in 2002 and the
increases in expected pension and PBOP costs in 2003. On
December 20, 2002, the MDTE approved the Accounting Order. Based
on this Accounting Order and an opinion from legal counsel
regarding the probability of recovery of these costs in the
future, the Company recorded a regulatory asset in lieu of taking
a charge to OCI at December 31, 2002. In addition, the
Accounting Order permits the Company to defer, as a regulatory
asset or liability, the difference between the level of pension
and PBOP expenses that are included in rates and the amounts that
are required to be recorded under SFAS 87 and SFAS 106 beginning
in 2003.
The regulatory asset of $263 million, recorded as a result of
this Accounting Order, consists of the prepaid pension asset
($257 million) related to the Plan and the Company's portion of
the minimum liability ($5.6 million) incurred at December 31,
2002. The regulatory asset is shown in Deferred debits on the
accompanying Consolidated Balance Sheets.
Boston Edison anticipates filing with the MDTE, during 2003, a
specific mechanism designed to address pension and PBOP costs.
It is Boston Edison's goal to eliminate the volatility of these
costs.
The Plan currently meets the minimum funding requirements of the
Employee Retirement Income Security Act of 1974. While not
required to make contributions to the Plan, the Company
anticipates increasing the level of its cash contributions to the
Plan in 2003 to mitigate the projected adverse impact. Such cash
contributions may be material to its consolidated cash flows from
operations. Boston Edison believes it has adequate access to
capital resources to support these contributions.
e. Decommissioning Cost Estimates
The accounting for decommissioning costs of nuclear power plants
involves significant estimates related to costs to be incurred
many years in the future. Changes in these estimates will not
affect Boston Edison's results of operations or cash flows
because these costs will be collected from customers through
Boston Edison's transition charge filings with the MDTE.
While Boston Edison no longer directly owns any nuclear power
plants, it owns, through its equity investments, 9.5% of
Connecticut Yankee Atomic Power Company (CYAPC) and 9.5% of
Yankee Atomic Electric Company (YAEC) (the Yankee Companies).
Periodically, Boston Edison obtains estimates from the management
of the Yankee Companies on the cost of decommissioning the
Connecticut Yankee nuclear unit (CY) and the Yankee Atomic
nuclear unit (YA). These nuclear units are completely shut down
and are currently conducting decommissioning activities.
Based on estimates from the Yankee Companies' management as of
December 31, 2002, the total remaining cost for decommissioning
each nuclear unit is approximately as follows: $247.7 million
for CY and $224.9 million for YA. Of these amounts, Boston
Edison is obligated to pay $23.6 million towards the
decommissioning of CY and $21.4 million toward YA. These
estimates are recorded in the accompanying Consolidated Balance
Sheets as Power contract liabilities with a corresponding
regulatory asset. These estimates may be revised from time to
time based on information available to the Yankee Companies
regarding future costs.
Boston Edison expects the Yankee Companies to seek recovery of
these costs and any additional increases to these costs in rate
applications with the FERC, with any resulting adjustments being
charged to their respective sponsors, including Boston Edison.
Boston Edison would recover its share of any allowed increases
from customers through the transition charge.
New Accounting Standards
See Note A, "New Accounting Standards," of the accompanying
Consolidated Financial Statements.
Rate and Regulatory Proceedings
a. Distribution Rate Proceedings
On February 14, 2003, NSTAR notified the MDTE that it is in the
process of reviewing the 2002 test-year cost of service for its
utility subsidiaries, including Boston Edison, in order to
determine whether to request a general base rate increase. This
assessment coincides with the expiration of NSTAR's four-year
rate freeze presently in effect as part of the Merger Rate Plan
that created NSTAR. If NSTAR decides not to seek a general base
rate increase, NSTAR will request a specific rate recovery
mechanism relating to pension and PBOP costs in conjunction with
the MDTE Accounting Order dated December 20, 2002. Management
intends to finalize its decision on the appropriate regulatory
proceedings during the second quarter of 2003.
b. Merger Rate Plan
An integral part of the merger of BEC and COM/Energy that created
NSTAR was the rate plan of the retail utility subsidiaries that
was approved by the MDTE on July 27, 1999 and affirmed by the SJC
in December 2002 as further discussed below. Significant
elements of the rate plan included a four-year distribution rate
freeze, recovery of the acquisition premium (goodwill) over 40
years and recovery of transaction and integration costs (costs to
achieve) over 10 years. Refer to the "Retail Electric Rates"
section of this MD&A for more information on retail rates and
cost recovery.
On December 16, 2002, the SJC affirmed the MDTE's 1999 decision
to allow for the merger of BEC and COM/Energy as originally
structured. This decision did not have an impact on Boston
Edison's 2002 or prior periods' consolidated financial position,
cash flows or results of operations. The 1999 MDTE order
approving the rate plan associated with the merger, was appealed
to the SJC by the Massachusetts Attorney General (AG) and a
separate group that consisted of The Energy Consortium (TEC) and
Harvard University (Harvard). TEC and Harvard alleged that, in
approving the rate plan and merger proposal, the MDTE committed
errors of law in the following areas: (1) in adopting a public
interest standard, the MDTE applied the wrong standard of review,
and failed to investigate the propriety of rates and to determine
that the resulting rates of Boston Edison, Cambridge Electric,
ComElectric and NSTAR Gas were just and reasonable; (2) that in
permitting Cambridge Electric and ComElectric to adjust their
rates by $49.8 million to reflect demand-side management costs,
the MDTE failed to determine whether such an adjustment was
warranted in light of other cost decreases; (3) that the MDTE's
approval results in an arbitrary and unjustified sharing of
benefits and costs between ratepayers and shareholders; and (4)
that the MDTE's approval of the rate plan guarantees shareholders
recovery of future costs without any future demonstration of
customer savings. The AG's brief included similar arguments in
each of these areas and added that, in allowing recovery of the
acquisition premium, the MDTE improperly deviated from a cost
basis in setting approved rates and the ratemaking policies in
other jurisdictions.
c. Goodwill and Costs to Achieve
The merger that created NSTAR was accounted for using the
purchase method of accounting. In accordance with Accounting
Principles Board (APB) No. 16 - "Business Combinations," all
goodwill was recorded on the books of the subsidiaries of
COM/Energy. However, under the merger rate plan approved by the
MDTE, all of NSTAR's utility subsidiaries share in the recovery
of goodwill in their rates. As a result, goodwill amortization
expense 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 (CTA) are being
amortized based on the filed estimate of $111 million over 10
years. For the year ended December 31, 2002, Boston Edison's
portions of goodwill and CTA amortization were approximately $8
million and $7.2 million, respectively. NSTAR's retail utility
subsidiaries will reconcile the actual CTA costs incurred with
the original estimate in a future rate proceeding and any
difference is expected to be recovered over the remainder of the
amortization period. This reconciliation will include a final
accounting of the deductibility for income tax purposes of each
component of CTA. The total CTA is approximately $143 million of
which approximately $93 million has been allocated to Boston
Edison. This increase from the original estimate for NSTAR
is partially mitigated by the fact that the portion of CTA that
is not deductible for income tax purposes is approximately
$20 million lower than the original estimate. Boston Edison
anticipates that these incremental costs are probable of
recovery in future rates. CTA are the costs incurred to
execute the merger including the employee costs for a
voluntary severance program, costs of financial advisors,
legal costs and other transaction and systems integration costs.
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.
d. Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric,
including Boston Edison, filed proposed service quality plans for
each company with the MDTE. 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. Concurrently, NSTAR Electric
filed with the MDTE a report concerning its 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. On
March 22, 2002, following hearings on the matter, the MDTE issued
an order imposing a service quality penalty of approximately
$3.25 million on NSTAR Electric, of which $3.2 million related
specifically to Boston Edison, that was refunded to customers as
a credit to their bills during the month of May 2002. This
refund had no material effect on Boston Edison's consolidated
financial position, cash flows or results of operations in 2002.
For the four-month period ended December 31, 2001, the MDTE
determined that NSTAR Electric's performance relative to service
quality measures did not warrant a penalty assessment.
On February 28, 2003, NSTAR Electric and NSTAR Gas filed their
2002 Service Quality Reports with the MDTE that reflected
significant improvements in reliability and performance and
indicate that no penalty will be assessed for this period. The
Company accounts for its service quality penalties pursuant to
SFAS No. 5, "Accounting for Contingencies." Accordingly, these
penalties are monitored on a monthly basis to determine the
Company's contingent liability, and if the Company determines it
is probable that a liability has been incurred and is estimable,
the Company would then accrue an appropriate liability.
Annually, each NSTAR utility subsidiary makes a service quality
performance filing with the MDTE. Any settlement or rate order
that would result in a different liability (or credit) level from
what has been accrued would be adjusted in the period an
agreement is reached with the MDTE.
e. Retail Electric Rates
The 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 February 2005 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, 2002, Boston Edison had
approximately 28% of its load requirements provided by
competitive suppliers.
In December 2002, Boston Edison filed proposed transition rate
adjustments for 2003, including a preliminary reconciliation of
transition, transmission, standard offer and default service
costs and revenues through 2002. The MDTE subsequently approved
tariffs for the Company effective January 1, 2003. The filing
was updated in February 2003 to include final costs for 2002.
On November 14, 2002, Boston Edison and the AG (Settling
Parties), received approval from the MDTE on a Settlement
Agreement resolving issues in Boston Edison's reconciliation of
costs and revenues for the year 2001. Among other issues, the
Settlement Agreement includes an adjustment relating to the
reconciliation of costs relating to securitization and maximum
mitigation of costs incurred in relation to the purchased power
agreement with Hydro Quebec. As a result of this Settlement
Agreement with the AG, Boston Edison recognized approximately
$11.4 million in transition charge revenues in 2002. This
benefit was significantly offset by other regulatory
reconciliation 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 approved the reconciliation of costs and revenues for Boston
Edison through 2000 in its approval of a Settlement Agreement on
November 16, 2001 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 Boston Edison's consolidated financial
position, results of operations or cash flows.
During 2000, Boston Edison's accumulated costs to provide default
and standard offer service were in excess of the revenues it was
allowed to bill customers by approximately $193.6 million. On
January 1 and July 1, 2001, Boston Edison was permitted by the
MDTE to increase its rates to customers for standard offer and
default service to collect this shortfall. Furthermore, when
combined with the reduction in energy supply costs experienced in
2001 and through the first half of 2002, rates were reduced on
January 1, 2002, April 1, 2002, July 1, 2002 and January 1, 2003.
As a result, Boston Edison reflected a regulatory liability of
approximately $2.5 million at December 31, 2001 and a regulatory
asset of $8.7 million at December 31, 2002, that are reflected as
components of Regulatory assets - other on the accompanying
Consolidated Balance Sheets.
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. Effective April 1, 2002, each NSTAR
Electric company's fuel index was set to zero. The MDTE has
ruled that these fuel index adjustments are excluded from the 15%
rate reduction requirement under the Restructuring Act.
f. Standard Market Design
Effective March 1, 2003, the wholesale electric energy market in
the Northeast has been restructured into what is known as
"Standard Market Design" (SMD) in conjunction with FERC orders
issued in September and December of 2002. SMD provides an
additional market in which wholesale power costs can be hedged a
day in advance through binding financial commitments. Also,
under SMD, wholesale power clearing prices vary by location, with
prices increasing in areas where less efficient resources close
to the load are dispatched to meet the load requirements due to
the fact that the more efficient resources cannot be imported as
a result of transmission limitations. SMD is not expected to
have an impact on Boston Edison's results of operations because
of the recovery mechanism for wholesale energy costs approved by
the MDTE.
Other Legal Matters
In the normal course of its business, Boston Edison and its
subsidiaries are involved in certain legal matters, including
civil lawsuits. Management is unable to fully determine a range
of reasonably possible court-ordered damages, settlement amounts,
and related litigation costs ("legal liabilities") that would be
in excess of amounts accrued. Based on the information currently
available, Boston Edison does not believe that it is probable
that any such additional legal liability will have a material
impact on its consolidated financial position. However, it is
reasonably possible that additional legal liabilities that may
result from changes in estimates could have a material impact on
its results of operations for a reporting period.
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, 2002 and should be read in conjunction
with the accompanying Consolidated Financial Statements and Notes
to Consolidated Financial Statements included elsewhere in this
report.
2002 compared to 2001
Net income was $134.1 million in 2002 compared to $150.4 million
in 2001, a decrease of 10.8%.
Operating revenues
Operating revenues for 2002 decreased 15.7% from 2001 as follows:
(in thousands)
Retail revenues $(297,001)
Wholesale revenues (23,461)
Short-term sales and other revenues 9,909
Decrease in operating revenues $(310,553)
========
Despite a 0.5% increase in kWh sales in 2002, retail revenues
were $1,529 million in 2002 compared to $1,826 million in 2001, a
decrease of $297 million, or 16%. The change in retail revenues
reflects lower rates implemented in January and April 2002 for
standard offer service and January and July 2002 for default
service as a result of a significant decline in purchased power
costs. This revenue decrease was partially offset by higher
transition revenues of $36 million primarily due to the
reconciliation of securitization costs and to higher rates for
transition cost recovery. The decrease 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 for 2002 was
significantly warmer than the same period in 2001, resulting in
an 18% increase in cooling degree days from the prior year and a
43% increase from the 30-year average. Below is comparative
information on cooling and heating degree days in 2002 and 2001
and the number of degree days in a "normal" year as represented
by a 30-year average.
30-Year
2002 2001 Average
Cooling degree-days 972 822 777
Percentage change from prior year 18.2% 39.8%
Percentage change from 30-year average 25.1% 5.8%
Heating degree-days 5,279 5,243 5,630
Percentage change from prior year 0.7% (8.6)%
Percentage change from 30-year average (6.2)% (6.9)%
Wholesale electric revenues were $56.6 million in 2002 compared
to $80 million in 2001, a decrease of $23.4 million, or 29%.
This decrease was primarily due to the expiration of two
municipal contracts on May 31, 2002 and a third contract on
October 31, 2002. After October 31, 2005, the Company will no
longer have contracts for the supply of wholesale power. Amounts
collected from wholesale customers are credited to retail
customers through the transition charge. Therefore, the
expiration of these contracts has no impact on Boston Edison's
consolidated net income.
Other revenues were $86.6 million in 2002 compared to $76.7
million in 2001, an increase of $9.9 million, or 13%. This
increase reflects higher transmission revenues.
Operating expenses
Purchased power was $838.4 million in 2002 compared to $1,159.7
million in 2001, a decrease of $321.3 million or 28%. The
decrease in purchased power expense reflects lower prices for
natural gas and oil that are reflected in the Company's default
and standard offer service rates and the 24% decrease in
wholesale sales offset somewhat by the increase in retail sales.
The decrease also reflects the impact of the recovery of
previously deferred standard offer and default service costs in
2001 compared to an under-recovery of these costs in 2002.
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.
Operations and maintenance expense was $228.7 million in 2002
compared to $203.3 million in 2001, an increase of $25.4 million
or 12%. This increase primarily reflects increased costs related
to pension and postretirement benefits and corrective electric
systems maintenance costs.
Depreciation and amortization expense was $170.9 million in 2002
compared to $167.9 million in 2001, an increase of $3 million or
2%. The increase reflects a higher level of depreciable plant-in-
service in the current year.
Demand side management (DSM) and renewable energy programs
expense was $48.6 million in 2002 compared to $47.6 million in
2001, an increase of $1 million, or 2%. 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 $70.1 million in 2002 compared to
$69.8 million in 2001, an increase of $0.3 million, or less than
1%. The change reflects higher tax rates and assessments in the
City of Boston offset by lower payments in lieu of taxes to the
Town of Plymouth due to a lower assessed value.
Income taxes from operations were $90.5 million in 2002 compared
to $94 million in 2001, a decrease of $3.5 million, or 4%. This
decrease reflects a lower level of pretax operating income in
2002.
Other income, net
Other income, net was $4 million in 2002 compared to $8.2 million
in 2001, a decrease of $4.2 million or 51%. The decrease was
primarily due to the absence in 2002 of income related to the
receipt of equity securities in connection with the
demutualization of John Hancock Financial Services, Inc. and
MetLife, Inc. A decline in interest income of $2.5 million
primarily associated with the reconciliation of securitization
costs also contributed to the decline.
Other deductions, net
Other deductions, net increased $0.5 million due primarily to an
increase in charitable contributions.
Interest charges
Interest on long-term debt and transition property securitization
certificates was $85 million in 2002 compared to $87.5 million in
2001, a decrease of $2.5 million or 3%. The decrease is related
to securitization certificate interest reflecting the scheduled
partial retirement of this debt, and the retirement of the $24.3
million 9.375% debentures in August 2001 offset somewhat by the
issuance of $500 million in new long-term debt in October 2002.
Other interest charges were $10.8 million in 2002 compared to
$11.5 million in 2001, a decrease of $0.7 million or 6%. This
decrease reflects the repayment of short-term debt with the
proceeds from the aforementioned long-term debt issue offset by
an $8.1 million increase in carrying charges due the Company
associated with reductions in the level of regulatory deferrals.
Other Matters
Environmental
As of December 31, 2002, Boston Edison was involved in 12 state-
regulated properties ("Massachusetts Contingency Plan, or "MCP"
sites") where oil or other hazardous materials were previously
spilled or released. On February 4, 2003, Boston Edison closed
out one of these sites and filed the required information with
the Massachusetts Department of Environmental Protection. 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 result of involvement in multi-party disposal sites or third
party claims associated with contamination remediation. Boston
Edison generally expects to have only a small percentage of the
total potential liability for these sites. Estimates of
approximately $3.7 million and $4.8 million are included as
liabilities in the accompanying Consolidated Balance Sheets at
December 31, 2002 and 2001, respectively, and are the total
amount of Boston Edison's estimated environmental clean-up
obligations. Accordingly, this amount has not been reduced by
any potential rate recovery treatment of these costs or any
potential recovery from Boston Edison's insurance carriers.
Prospectively, should Boston Edison be allowed regulatory rate
recovery of these specific costs, it would record an offsetting
regulatory asset and record a credit to operating expenses equal
to previously expensed costs. 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.
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
evolve or are resolved. Boston Edison's ultimate liability for
future environmental remediation costs may vary from these
estimates. Although, 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 consolidated financial position or results of operations
for a reporting period.
Interest Rate Risk
Boston Edison is exposed to changes in interest rates primarily
based on levels of short-term debt outstanding. Carrying amounts
and fair values of long-term indebtedness (excluding notes
payable) and the weighted average interest rate as of December
31, 2002 and 2001, were as follows:
(in thousands) Weighted
Carrying Fair Average
2002 Amount Value Interest Rate
Long-term indebtedness $1,477,326 $1,480,510 6.19%
(including current indebtedness)
2001
Long-term indebtedness $1,107,346 $1,153,380 7.15%
(including current indebtedness)
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk
Although the Company has material commodity purchase contracts,
these instruments are not subject to market risk. The Company
has a rate-making mechanism that 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 February 2005. 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.
On October 15, 2002, Boston Edison issued $100 million of 3-year
floating rate debentures priced at LIBOR plus 50 basis points.
An immediate change of one percent for these variable rate
debentures would cause a change in interest expense of
approximately $1 million per year.
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 15(a)(1) on page 54, present
fairly, in all material respects, the financial position of
Boston Edison Company and its subsidiaries at December 31, 2002
and 2001, and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 2002 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 15 (a)(2) on page 54, 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 22, 2003
Item 8. Financial Statements and Supplementary Financial
Information
Boston Edison Company
Consolidated Statements of Income
(in thousands)
Years ended December 31,
2002 2001 2000
Operating revenues $1,672,148 $1,982,701 $1,671,846
Operating expenses:
Purchased power 838,435 1,159,706 839,715
Operations and maintenance 228,666 203,320 205,734
Depreciation and amortization 170,932 167,905 169,333
Demand side management and
renewable energy programs 48,579 47,639 54,836
Taxes-property and other 70,077 69,777 55,905
Income taxes 90,487 93,967 95,852
Total operating expenses 1,447,176 1,742,314 1,421,375
Operating income 224,972 240,387 250,471
Other income, net:
Other income, net 4,008 8,154 8,281
Other deductions, net (736) (224) (582)
Total other income, net 3,272 7,930 7,699
Interest charges:
Long-term debt 47,867 45,994 52,804
Transition property 37,135 41,475 45,505
securitization
Short-term and other 10,769 11,467 15,902
Allowance for borrowed funds
used during construction (1,630) (972) (2,069)
Total interest charges 94,141 97,964 112,142
Net income $ 134,103 $ 150,353 $ 146,028
========= ========= =========
Per share data is not relevant because Boston Edison Company's
common stock is wholly owned by NSTAR.
The accompanying notes are an integral part of the Consolidated
Financial Statements.
Boston Edison Company
Consolidated Statements of Comprehensive Income
(in thousands)
Years ended December 31,
2002 2001 2000
Net income $ 134,103 $ 150,353 $ 146,028
Other comprehensive income (loss), net:
Non-qualified benefit obligations - 195 (195)
Deferred income taxes - (78) 78
Comprehensive income $ 134,103 $ 150,470 $ 145,911
======== ======== ========
The accompanying notes are an integral part of the Consolidated
Financial Statements.
Boston Edison Company
Consolidated Statements of Retained Earnings
(in thousands)
Years ended December 31,
2002 2001 2000
Balance at the beginning of the year $ 428,150 $ 352,832 $ 1,462
Add:
Net income 134,103 150,353 146,028
Dividends transferred from paid in capital (a) - - 226,541
Subtotal 562,253 503,185 374,031
Deduct:
Dividends declared:
Dividends to Parent 84,300 68,927 15,000
Preferred stock 1,960 5,627 5,960
Subtotal 86,260 74,554 20,960
Provision for preferred stock redemption and
issuance costs - 481 239
Balance at the end of year $ 475,993 $ 428,150 $ 352,832
======= ======= =======
(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 in 2000.
The accompanying notes are an integral part of the Consolidated
Financial Statements.
Boston Edison Company
Consolidated Balance Sheets
(in thousands)
December 31,
Assets 2002 2001
Utility plant in service, at
original cost $2,782,854 $2,641,759
Less: accumulated depreciation 854,857 $1,927,997 875,158 $1,766,601
Construction work in progress 41,944 38,818
Net utility plant 1,969,941 1,805,419
Equity and other investments 11,592 13,611
Current assets:
Cash and cash equivalents 44,062 13,549
Restricted cash 3,616 3,625
Accounts receivable - customers,
net of allowance of $19,084 and
$24,691 in 2002 and 2001,
respectively 177,681 264,633
Accrued unbilled revenues 21,468 29,081
Fuel, materials and supplies, at
average cost 13,291 15,461
Deferred tax asset 18,141 1,835
Other 5,575 283,834 22,335 350,519
Deferred debits:
Regulatory assets 1,265,062 768,776
Prepaid pension costs - 218,713
Other 178,429 27,763
Total assets $3,708,858 $3,184,801
========= =========
Capitalization and Liabilities
Common equity:
Common stock, par value $1 per
share, 100,000,000 shares
authorized; 75 shares issued and
outstanding $ - $ -
Premium on common stock 278,795 528,795
Retained earnings 475,993 $ 754,788 428,150 $ 956,945
Cumulative non-mandatory redeemable
preferred stock of subsidiary 43,000 43,000
Long-term debt 840,194 551,803
Transition property 445,890 513,904
securitization
Current liabilities:
Long-term debt 150,687 667
Transition property
securitization 40,555 40,972
Notes payable - 191,500
Accounts payable:
Affiliates 32,450 54,663
Other 117,600 91,522
Accrued interest 13,899 10,738
Other 46,971 402,162 67,098 457,160
Deferred credits
Accumulated deferred income taxes and
unamortized investment tax credits 611,469 578,765
Power contracts 350,117 22,697
Other 261,238 60,527
Commitments and contingencies
Total capitalization and liabilities $3,708,858 $3,184,801
========== ==========
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,
2002 2001 2000
Operating activities:
Net income $ 134,103 $ 150,353 $ 146,028
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation and amortization 170,932 167,905 161,371
Deferred income taxes and investment tax credits 16,125 (51,242) 86,962
Allowance for borrowed funds used
during construction (1,630) (972) (2,069)
Net changes in:
Accounts receivable and accrued unbilled revenues 94,565 (26,356) 13,556
Fuel, materials and supplies, at average cost 2,170 160 605
Accounts payable 3,865 102,292 128,753
Other current assets and liabilities (16,503) (194,582) (363,521)
Deferred debits and credits 26,897 58,727 14,991
Net cash provided by operating activities 430,524 206,285 186,676
Investing activities:
Plant expenditures (excluding AFUDC) (239,032) (138,565) (110,437)
Investments 2,019 11,500 4,368
Net cash used in investing activities (237,013) (127,065) (106,069)
Financing activities:
Capital contribution - 43,937 -
Long-term debt 500,000 - -
Financing costs (5,218) - -
Redemptions:
Preferred stock - (50,000) -
Long-term debt (130,020) (91,513) (251,559)
Net change in notes payable (191,500) 95,000 96,500
Repurchase of Common shares (250,000) - -
Dividends paid (86,260) (75,220) (30,960)
Net cash used in financing activities (162,998) (77,796) (186,019)
Net increase (decrease) in cash and cash equivalents 30,513 1,424 (105,412)
Cash and cash equivalents at the beginning of the year 13,549 12,125 117,537
Cash and cash equivalents at the end of the year $ 44,062 $ 13,549 $ 12,125
========= ======== =========
Supplemental disclosures of cash flow information:
Interest, net of amounts capitalized $ 81,158 $ 91,007 $ 105,735
Income taxes (refunded) paid $ 46,483 $ 164,194 $ (47,312)
The accompanying notes are an integral part of the Consolidated
Financial Statements.
Notes to Consolidated Financial Statements
Note A. Business Organization and 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 an energy delivery
company focusing its activities in the transmission and
distribution of energy. NSTAR serves approximately 1.4 million
customers in Massachusetts, including approximately 1.1 million
electric customers in 81 communities and 0.3 million gas
customers in 51 communities. Boston Edison serves approximately
683,000 electric customers in the city of Boston and 39
surrounding cities and towns. NSTAR's retail utility
subsidiaries are Boston Edison, Commonwealth Electric Company
(ComElectric), Cambridge Electric Light Company (Cambridge
Electric) and NSTAR Gas Company (NSTAR Gas). 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. The population of the area served with
electricity at retail is approximately 1.6 million. 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
accounting principles generally accepted in the United States of
America (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 regulatory assets.
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.
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.
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 2.89%, 2.87% and 2.99% in 2002, 2001 and
2000, 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 2002, 2001 and 2000 were 2.89%, 4.14% and 6.00%,
respectively, and represented only the cost of short-term debt.
8. Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash are comprised of
liquid securities with maturities of 90 days or less when
purchased. 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.
9. 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.
10. Related Party Transactions
The accompanying Consolidated Balance Sheet as of December 31,
2002 includes $171 million in Other deferred charges that results
from the Company's role as the sponsor of the NSTAR Pension Plan
and represents the amount of the additional minimum liability
recognized in 2002 that was allocated to the other subsidiaries
of NSTAR. Additionally, the accompanying December 31, 2002 and
2001 Consolidated Balance Sheets include net payables of $24.1
million and $45.4 million, respectively, to NSTAR Electric & Gas,
for management and support services. Boston Edison's goodwill
amortization expense allocation payable to its affiliated
companies, ComElectric, Cambridge Electric and NSTAR Gas was
$26.6 million and $18.6 million for 2002 and 2001, respectively.
These amounts were included in Other deferred credits. Also,
included in the accompanying Consolidated Balance Sheet as of
December 31, 2002 was a payable of approximately $10 million to
the Parent Company NSTAR representing the Company's share of
postretirement benefits costs. These statements also include an
Accounts payable of $226,600 and $277,400 as of December 31, 2002
and 2001, respectively, from NSTAR Communications, Inc., an
affiliate. These balances represent the construction and
construction costs management services provided by Boston Edison
and its contractors.
11. 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 costs to achieve
are being amortized over 10 years and will initially be
approximately $11.1 million annually. As of December 31, 2002,
Boston Edison's portion of goodwill and costs to achieve
amortization was approximately $8 million and $7.2 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 costs to achieve will
reflect the total actual costs.
12. Other income, net
Major components of Other income, net were as follows:
(in thousands) 2002 2001 2000
Equity earnings $1,463 $ 1,434 $ 3,230
Income from demutualized securities - 2,743 -
Interest income 926 3,433 5,265
Rental income 1,737 1,921 1,638
Settlement of claims 1,041 943 2,000
Miscellaneous other income (includes
applicable income tax expense for
total other income) (1,159) (2,320) (3,852)
4,008 8,154 8,281
Major components of Other deductions, net were as follows:
(in thousands)
Charitable contributions (970) (22) (573)
Property taxes (129) (119) (116)
Miscellaneous other deductions
(includes applicable income tax
benefit for total other deductions) 363 (83) 107
(736) (224) (582)
Total other income, net $3,272 $ 7,930 $ 7,699
===== ====== ======
13. New Accounting Standards
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143). This Statement, which
is effective for Boston Edison on January 1, 2003, establishes
accounting and reporting standards 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. SFAS 143 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. Management has
identified several minor long-lived assets, including lease
arrangements, and has determined that it is legally responsible
to remove such property and comply with the requirement of this
standard. However, based on Boston Edison's assessment of its
potential liability and rate regulatory treatment for the
identified assets, the adoption of SFAS 143 will not have an
effect on its results of operations, cash flows, or financial
position.
The FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" (SFAS 146) that requires
entities to record a liability for costs related to exit or
disposal activities when the costs are incurred. Previous
accounting guidance required the liability to be recorded at the
date of commitment to an exit or disposal plan. Boston Edison is
required to comply with SFAS 146 beginning January 1, 2003.
Boston Edison anticipates that the implementation of this
standard will not have an adverse impact on its financial
position or results of operations.
In November 2002, FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (the
Interpretation). The Interpretation elaborates on the
disclosures to be made by a guarantor in its interim and annual
financial statements about its obligations under certain
guarantees it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial
measurement provisions of this Interpretation are applicable on a
prospective basis to guarantees issued or modified after December
31, 2002. For Boston Edison, disclosure requirements are
effective with the 2002 financial statements contained in this
report. Refer to Note K, "Commitments and Contingencies," for
more discussion. The application of this Interpretation is not
expected to materially impact the financial condition, results of
operations, and cash flows of Boston Edison.
14. Purchases and Sales Transactions with ISO - New England (ISO-
NE)
During 2001, as part of Boston Edison's normal business
operations in order to meet its energy obligation to its standard
offer and default service customers, Boston Edison entered into
hourly transactions to purchase or sell energy supply to its
ISO-NE. The Boston Edison transactions with the ISO-NE have been
treated as the ISO-NE servicing the incremental needs of Boston
Edison, that is, transactions with ISO-NE associated with the
difference between Boston Edison's resource needs compared to
Boston Edison's resource availability. Boston Edison records the
net effect of transactions with the ISO-NE as an adjustment to
purchased power expense.
During 2002, NSTAR Electric entered into an agreement whereby all
of its energy supply resource entitlements are transferred to an
independent energy supplier, following which NSTAR Electric
repurchases its energy resource needs from this independent
energy supplier for NSTAR Electric's ultimate sale to its
standard offer customers. This transaction has been and will
continue to be recorded as a net purchase, similar to those
transactions with ISO-NE during 2001.
Note B. 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) December 31,
2002 2001
Generation-related regulatory assets, net $ 466,894 $ 555,514
Power contracts (including Yankee units) 350,117 22,697
Pension costs 262,616 -
Merger costs to achieve 68,601 79,227
Income taxes, net 60,278 62,070
Redemption premiums 13,479 12,853
Purchased power costs 8,713 (2,498)
Deferred postretirement benefits and pension costs 11,415 11,415
Other 22,949 27,498
Total regulatory assets $1,265,062 $ 768,776
========= ========
Under the traditional revenue requirements model, electric rates
are based on the cost of providing electric service. Under this
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. This is applicable to
Boston Edison's distribution and transmission operations.
Generation-related regulatory assets, net
Plant and other regulatory assets related to the divestiture of
Boston Edison's generation business are recovered through the
transition charge. This recovery continues through 2016 for
Boston Edison and is subject to adjustment by the MDTE.
Power contracts
Approximately $45 million at December 31, 2002 represents the
remaining unamortized balance of the estimated costs to close the
Connecticut Yankee (CY) and Yankee Atomic (YA) nuclear power
plants that are currently being decommissioned. Boston Edison's
liability for CY decommissioning and its recovery ends in 2007
and for YA in 2010. However, should the actual costs exceed
current estimates and anticipated decommissioning dates, Boston
Edison could have an obligation beyond these periods that would
be fully recoverable. These costs are recovered in Boston
Edison's transition charge. Refer to Note K, "Commitments and
Contingencies," for more discussion.
The remaining balance includes $305.2 million at December 31,
2002 representing the recognition of a purchased power contract
as a derivative and its above-market value and future recovery
through Boston Edison's transition charge. Refer to Note I for
further details.
Pension costs
The regulatory asset attributable to pension costs represents the
deferral of pension related costs, which Boston Edison expects to
recover from customers in future years. This amount results from
the reclassification of amounts, which in the absence of the MDTE
Accounting Order issued on December 20, 2002 (see Note D), would
otherwise have been classified as a charge to other comprehensive
income pursuant to SFAS 87 (as amended by SFAS 130). The amount
of the deferral consists of approximately $5.6 million that
represents the additional minimum pension liability recorded to
reflect the Company's share of the unfunded liability of NSTAR's
pension plan, and approximately $257 million, which represents
the adjustment to reverse the prepaid pension costs. Prepaid
pension costs represent the cumulative excess of cash
contribution over the cumulative net periodic pension costs. For
purposes of financial statement presentation, the amount
previously reported as prepaid pension costs in 2001 has been
displayed net of the additional minimum pension liability in
2002, as required by SFAS 87.
Merger costs to achieve
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 included 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. Costs to
achieve are the costs incurred to execute the merger including
costs for a voluntary severance program, costs of financial
advisors, legal costs and other transaction and systems
integration costs. These costs are collected from all
distribution customers and exclude a return component. These
costs have been adjusted since the original recovery began and
any unrecovered costs will be included in the Company's next rate
case filing.
Income taxes, net
Approximately $32 million of this regulatory asset balance
reflects deferred tax reserve deficiencies that the MDTE has
allowed recovery of from ratepayers over a 17-year period. In
addition, approximately $40 million in additional deferred tax
reserve deficiencies has been recorded in accordance with an MDTE-
approved settlement agreement. Offsetting these amounts is
approximately $12 million of a regulatory liability associated
with unamortized investment tax credits.
Redemption premiums
These amounts reflect the unamortized balance of redemption
premium on Boston Edison Debentures that is amortized over the
life of the respective debentures pursuant to MDTE approval and
is consistent with the recovery from ratepayers of such costs.
There is no return recognized on this balance.
Purchased power costs
The purchased power costs relate to deferred standard offer
service and deferred default service costs. Customers have the
option of continuing to buy power from Boston Edison at standard
offer prices through February 2005. Since 1998, Boston Edison
has been allowed to defer the difference between the retail price
per kWh for standard offer and default service revenues and the
cost to supply the power, plus carrying 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.
Deferred postretirement benefits and pension costs
These amounts represent the costs deferred by the Company during
a three-year phase-in period approved by the MDTE related to the
adoption of SFAS 106.
Boston Edison will include these costs in a future rate
proceeding. There is no current recovery of these deferred
costs.
Other
These amounts primarily consist of deferred transmission revenues
that are set to be recovered over a subsequent twelve-month
period. The deferred revenue represents the difference between
the level of billed transmission revenues and the current period
costs incurred to provide transmission-related services.
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 $60.3 million and $62.1
million and corresponding net increases in accumulated deferred
income taxes were recorded as of December 31, 2002 and 2001,
respectively. The regulatory assets represent the additional
future revenues to be collected from customers for deferred
income taxes.
Accumulated deferred income taxes and unamortized investment tax
credits consisted of the following:
December 31,
(in thousands) 2002 2001
Deferred tax liabilities:
Plant-related $ 303,411 $ 211,506
Transition costs 206,895 233,465
Other 121,136 154,148
631,442 599,119
Deferred tax assets:
Investment tax credits 11,784 12,423
Other 44,536 29,015
56,320 41,438
Net accumulated deferred income taxes 575,122 557,681
Accumulated unamortized investment tax
credits 18,206 19,249
$593,328 $576,930
======== ========
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) 2002 2001 2000
Current income tax expense $ 74,362 $144,779 $ 8,890
Deferred income tax expense (benefit) 17,168 (49,715) 87,953
Investment tax credit amortization (1,043) (1,097) (991)
Income taxes charged to operations 90,487 93,967 95,852
Current tax expense on other income
(deductions), net 1,795 3,607 5,046
Total income tax expense $ 92,282 $ 97,574 $100,898
======= ======= ========
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:
2002 2001 2000
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal
income tax benefit 4.4 4.4 4.4
Investment tax credits (0.5) (0.4) (0.4)
Other 1.9 0.4 1.8
Effective tax rate 40.8% 39.4% 40.8%
==== ==== ====
Note D. Pension and Other Postretirement Benefits
1. Pension
Effective January 1, 2000, the pension plans of BEC and
COM/Energy were combined to form the NSTAR Pension Plan (the
Plan). Boston Edison is the sponsor of the Plan which is a
defined benefit funded retirement plan that covers substantially
all employees of NSTAR Electric & Gas.
In 2002, the Plan was amended to comply with the Economic Growth
and Tax Relief Reconciliation Act of 2001 (EGTRRA). EGTRRA,
among other things, increased the annual benefits limit for
amounts payable from the Plan to $160,000, increased the number
of rollover options for distributions, and allowed surviving
spouses to rollover distributions to their employer's plan. This
amendment also brought the Plan into compliance with recently
issued Internal Revenue Service revenue rulings and regulations
that require the change of the mortality table used for computing
lump sum pension distributions and annuity conversions.
The Company also maintained 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 was transferred accordingly effective December
31, 2001.
The changes in benefit obligation and Plan assets were as
follows:
December 31,
(in thousands) 2002 2001
Change in benefit obligation:
Benefit obligation, beginning of the year $ 810,517 $ 804,358
Transfer of obligation to affiliate company - (14,067)
Service cost 14,871 13,727
Interest cost 57,564 56,418
Plan participants' contributions 74 71
Plan amendments 671 -
Actuarial loss 102,598 14,091
Settlement payments (19,545) (16,573)
Benefits paid (49,258) (47,508)
Benefit obligation, end of the year $ 917,492 $ 810,517
======== ========
Change in plan assets: 2002 2001
Fair value of plan assets, beginning of the
year $ 790,704 $ 846,207
Actual loss on plan assets, net (105,578) (52,493)
Employer contribution 49,500 61,000
Plan participants' contributions 74 71
Settlement payments (19,545) (16,573)
Benefits paid (49,258) (47,508)
Fair value of plan assets, end of the year $ 665,897 $ 790,704
======== ========
The Plan's funded status was as follows:
December 31,
(in thousands) 2002 2001
Funded status $(251,595) $ (33,598)
Liability transfer to affiliate company - 13,785
Unrecognized actuarial net loss 515,859 246,708
Unrecognized transition obligation 980 1,581
Unrecognized prior service cost (8,228) (9,762)
Net amount recognized $ 257,016 $ 218,714
======== ========
Amounts recognized in the accompanying Consolidated Balance
Sheets consisted of:
2002 2001
(in thousands)
Prepaid retirement cost $ - $ 218,714
Accrued retirement liability (177,675) -
Intangible asset 980 -
Regulatory asset 262,616 -
Amount allocated to affiliates 171,095 -
Net amount recognized $ 257,016 $ 218,714
======== ========
Weighted average assumptions were as follows:
2002 2001 2000
Discount rate at the end of the year 6.5% 7.25% 7.5%
Expected return on plan assets for the year
(net of investment expenses) 9.4% 9.4% 9.3%
Rate of compensation increase at the end of
the year 4.0% 4.0% 4.0%
The expected return on Plan assets has been adjusted to 8.4% in
2003.
Components of net periodic benefit (income)/cost were as follows:
(in thousands) 2002 2001 2000
Service cost $ 14,871 $ 14,027 $ 14,636
Interest cost 57,564 57,050 59,798
Expected return on plan assets (74,426) (78,397) (85,884)
Amortization of prior service cost (863) (118) 448
Amortization of transition obligation 601 601 601
Recognized actuarial loss 13,451 775 -
Net periodic benefit (income)/cost
before allocation to affiliates $ 11,198 $ (6,062) $(10,401)
======= ======= =======
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 funds
these 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.
The Company, as the sponsor of the Plan, allocated net costs and
was reimbursed by its affiliated companies a total of $4.4
million and $1.2 million in 2002 and 2001, respectively.
Funded Status
The Plan's assets have been affected by significant declines in
the equity markets in the past three years. These conditions
have impacted the funded status of the Plan at December 31, 2002.
As a result of the negative investment performance, at December
31, 2002, the accumulated benefit obligation exceeded Plan
assets. Therefore, the Company is required to recognize an
additional minimum liability as prescribed by SFAS No. 87,
"Employers' Accounting for Pensions" (SFAS 87) and SFAS No. 132,
"Employers' Disclosures about Pensions and Postretirement
Benefits." The additional minimum liability results in the
netting of the Prepaid pension cost with the additional minimum
liability on the accompanying Consolidated Balance Sheet.
Under SFAS 87, Boston Edison is also required to net its prepaid
pension balance. The additional minimum liability adjustment,
which is equal to the sum of the minimum pension liability and
the prepaid pension adjustment, would be recorded, net of taxes,
as a non-cash charge to Other Comprehensive Income (OCI) on the
accompanying Consolidated Statements of Comprehensive Income and
would not affect the results of operations for 2002. The fair
value of Plan assets and the ABO are measured at each year-end
balance sheet date. The minimum liability will be adjusted each
year to reflect this measurement. At such time that the Plan
assets exceed the ABO, the minimum liability would be reversed.
In November 2002, the Company filed a request with the MDTE
seeking an accounting ruling to mitigate the impact of the non-
cash charge to OCI in 2002 and the increases in expected pension
and PBOP costs in 2003. On December 20, 2002, the MDTE approved
the Accounting Order. Based on this Accounting Order and an
opinion from legal counsel regarding the probability of recovery
of these costs in the future, the Company recorded a regulatory
asset in lieu of taking a charge to OCI at December 31, 2002. In
addition, the order permits the Company to defer, as a regulatory
asset or liability, the difference between the level of pension
and PBOP expense that is included in rates and the amounts that
are required to be recorded under SFAS 87 and SFAS 106 beginning
in 2003.
The regulatory asset of $262.6 million, recorded as a result of
this accounting ruling, consists of the prepaid pension asset
($257 million) and includes the Company's portion of the
additional minimum liability ($5.6 million) incurred at December
31, 2002. The regulatory asset is shown as part of Deferred
debits in the accompanying Consolidated Balance Sheets.
2. Other Postretirement Benefits
Boston Edison also provides, through the Group Welfare Benefits
Plan for Retirees of NSTAR, 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, until April 1, 2003, of
certain Medicare premiums. Under certain circumstances, eligible
employees are required to make contributions for postretirement
benefits.
To fund these postretirement benefits, NSTAR, on behalf of Boston
Edison and other subsidiaries, 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 cannot be presented separately for
Boston Edison since the Company participates in the Plan trusts
with other subsidiaries. Plan assets are available to provide
benefits for all Plan participants who are former employees of
Boston Edison and of other subsidiaries of NSTAR.
The net periodic postretirement benefits cost allocated to the
Company was $16.2 million, $14.1 million and $12.7 million in
2002, 2001 and 2000, respectively.
3. Savings Plan
Boston Edison also contributes proportionately into a defined
contribution 401(k) plan for substantially all employees of 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 $5
million in 2002 and $4 million in both 2001 and 2000. The plan
was amended, effective April 1, 2001, to allow participants the
ability to reallocate their investments in the NSTAR Common Share
Fund to other investment options. Effective January 1, 2002,
consistent with the EGTRRA, the plan was further amended to allow
for increased maximum annual pre-tax contributions and additional
"catch-up" pre-tax contributions for participants age 50 or
older, acceptance of other types of "roll-over" pre-tax funds
from other plans and the option of reinvesting dividends paid on
the NSTAR Common Share Fund or receiving such dividends in cash.
The election to reinvest dividends paid on the NSTAR Common Share
Fund or receive the dividends in cash is subject to a freeze
period beginning seven days prior to the date any dividend is
paid. During this period, participants cannot change their
election. Dividends are paid to this plan four times a year on
February 1, May 1, August 1, and November 1.
Note E. Capital Stock
1. Common Stock Repurchase
On October 15, 2002, Boston Edison repurchased and retired 25
shares of its Common stock, par value $1 per share, for $250
million with a portion of the proceeds from the $500 million
long-term debt that was issued in October 2002.
2. Cumulative Preferred Stock
Non-mandatory redeemable series:
Par value $100 per share, 2,660,000 shares authorized and 430,000
issued and outstanding:
(in thousands, except per share amounts)
Current Shares Redemption December 31,
Series Outstanding Price/Share 2002 2001
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
====== ======
500,000 shares of the mandatory redeemable 8% Series with a par
value of $100 per share were redeemed in total on December 3,
2001, plus accrued dividends from November 1, 2001 to December 1,
2001.
Note F. Indebtedness
1. Long-term Debt
Boston Edison's long-term debt consisted of the following:
December 31,
(in thousands) 2002 2001
Long-term debt
Debentures:
6.80%, due March 2003 $ 150,000 $ 150,000
Floating rate (2.275% in 2002), due October 2005 100,000 -
7.80%, due May 2010 125,000 125,000
4.875%, due October 2012 400,000 -
8.25%, due September 2022 - 60,000
7.80%, due March 2023 181,000 181,000
Sewage facility revenue bonds, due through 2015 19,882 21,470
Massachusetts Industrial Finance
Agency (MIFA) bonds:
5.75%, due February 2014 15,000 15,000
Transition Property Securitization Certificates:
6.45%, due through September 2005 40,555 108,986
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
1,477,327 1,107,346
Amounts due within one year (191,242) (41,639)
Total long-term debt $ 1,286,085 $ 1,065,707
========= =========
The 8.25% series due 2022 was redeemed in September 2002 at
103.780%. A $2.3 million redemption premium was paid; this
transaction had minimal impact on earnings. The 7.80% series
debentures 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 are tax-exempt, subject to annual
mandatory sinking fund redemption requirements and mature through
2015. Scheduled redemptions of $1.6 million were made in 2002
and 2001. The weighted average interest rate of the bonds was
7.4% in 2002 and 2001. 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.
On October 15, 2002, Boston Edison issued two new debentures:
$400 million, 4.875% due in 2012 and $100 million, floating rate
debentures due in 2005 priced at three-month LIBOR plus 50 basis
points. Boston Edison used the proceeds to pay down short-term
debt.
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 2002 are
approximately $191.2 million in 2003, $70.4 million in 2004,
$170.1 million in 2005, $70.3 million in 2006, and $70.2 million
in 2007.
2. Financial Covenant Requirements
Boston Edison has no financial covenant requirements under its
long-term debt arrangements.
The Transition Property Securitization Certificates held by
Boston Edison's subsidiary, BEC Funding, LLC, are collaterized
with a securitized regulatory asset with a balance of $493.6
million as of December 31, 2002. Boston Edison, as servicing
agent for BEC Funding, collected $105.7 million in 2002. These
collected funds are remitted daily to the trustee of BEC Funding.
These certificates are non-recourse to Boston Edison.
Boston Edison had approval from the FERC to issue up to $350
million of short-term debt until December 31, 2002. On May 31,
2002, Boston Edison received FERC authorization to issue short-
term debt securities from time to time on or before December 31,
2004, with maturity dates no later than December 31, 2005, in
amounts such that the aggregate principal does not exceed $350
million at any one time. Boston Edison had a $300 million
revolving credit agreement with a group of banks effective
through December 2002. Boston Edison replaced this credit
facility with a 364-day, $350 million revolving credit agreement
that expires on November 14, 2003. At December 31, 2002 and
2001, there were no amounts outstanding under these revolving
credit agreements. These arrangements serve as backup to Boston
Edison's $350 million commercial paper program that had no
outstanding balance at December 31, 2002 and had an outstanding
balance of $191.5 million at December 31, 2001. In October 2002,
following receipt of the proceeds of its $500 million debt issue
previously referenced, its short-term debt balance was reduced to
zero. Under the terms of this agreement, Boston Edison is
required to maintain a maximum total consolidated debt to total
capitalization of not greater than 60% at all times, excluding
Transition Property Securitization Certificates and excluding
Accumulated other comprehensive income (loss) from Common Equity.
Commitment fees must be paid on the total agreement amount. At
December 31, 2002 and 2001, Boston Edison was in full compliance
with all of the aforementioned covenants. Interest rates on the
outstanding borrowings generally are money market rates and
averaged 1.85% and 4.14% in 2002 and 2001, respectively.
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 $44.1 million and $13.5 million, for 2002
and 2001, respectively, approximates fair value due to the short-
term nature of these securities.
2. 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, 2002 and 2001 were as follows:
2002 2001
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Long-term unsecured debt $1,477,326 $1,480,510 $1,107,346 $1,153,380
(including current maturities)
Note H. Long-Term Contracts for the Purchase of Electricity
Boston Edison expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the Massachusetts Electric
Restructuring Act of 1997 (Restructuring Act) and MDTE orders.
Boston Edison has existing long-term power purchase agreements
that are expected to supply approximately 75% of its standard
offer service obligation for 2003. Boston Edison has contracted
with a third party supplier to provide 100% of its standard offer
supply obligation through December 31, 2003. In connection with
this arrangement, Boston Edison has assigned its long-term power
purchase agreements to this supplier through December 31, 2003.
Boston Edison is recovering its payments to suppliers through
MDTE approved rates billed to customers. Boston Edison's
existing portfolio of long-term power purchase contracts supplied
the majority of its standard offer (including wholesale) energy
requirements in 2002. Also during 2002, Boston Edison entered
into an agreement whereby all of its energy supply resource
entitlements were transferred to an independent energy supplier,
following which Boston Edison repurchased its energy resource
needs from this independent energy supplier for Boston Edison's
ultimate sale to standard offer customers.
Capacity costs of long-term contracts reflect Boston Edison's
proportionate share of capital and fixed operating costs of
certain generating units. In 2002, these costs were attributed
to 470 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 2002 was 1,109 MW.
Information related to long-term power contracts during 2002 was
as follows:
Proportionate share (in thousands)
Range of Units of Capacity Charge
Contract Capacity 2002 2002 Obligation
Fuel Type of Expiration Purchased Capacity Total Through Contract
Generating Unit Dates % Range Total MW Cost Cost Expiration Date
Natural Gas 2010-2015 23.5-46.5 480 $70,378 $239,144 $878,541
Nuclear 2004 62 420 - 140,000 -
Oil 2005-2019 25-100 209 9,675 27,653 49,423
1,109 $80,053 $406,797 $927,964
===== ======= ======== ========
Boston Edison has entered into a short-term power purchase
agreement to meet its entire default service supply obligation
for the period January 1, 2003 through June 30, 2003 and for 50%
of its obligation for the second-half of 2003. A Request for
Proposals will be issued in the second quarter of 2003 for the
remainder of the obligation. Boston Edison entered into
agreements ranging in length from five to twelve-months effective
January 1, 2002 through December 31, 2002 with suppliers to
provide full default service energy and ancillary service
requirements at contract rates approved by the MDTE.
Boston Edison's total capacity and energy costs associated with
these contracts in 2002, 2001 and 2000 were approximately $407
million, $415 million and $428 million, respectively. Boston
Edison's capacity charge obligation under these contracts for the
years after 2002 is as follows:
(in thousands) Capacity Charge
Obligation
2003 $ 80,689
2004 85,749
2005 86,933
2006 88,283
2007 88,403
Years thereafter 497,907
Total $ 927,964
========
Note I. Derivative Instruments - Power Contracts
Boston Edison adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133), effective January
1, 2001. The accounting for derivative financial instruments is
subject to change based on the guidance received from the
Derivative Implementation Group (DIG) of FASB. The DIG issued
No. C15, "Scope Exceptions: Normal Purchases and Sales Exception
for Option-Type Contracts and Forward Contracts in Electricity"
on October 10, 2001, which specifically addressed the
interpretation of clearly and closely related contracts that
qualify for the normal purchases and sales exception under SFAS
133. The conclusion reached by the DIG was that contracts with a
pricing mechanism that are subject to future adjustment based on
a generic index that is not specifically related to the
contracted service commodity, generally would not qualify for the
normal purchases and sales exception.
On April 1, 2002, the effective date of DIG C15, Boston Edison
adopted the interpretation of this guidance and began marking to
market certain of its long-term purchased power contracts that
previously qualified for the normal purchases and sales
exception. Boston Edison has one purchased power contract that
contains components with pricing mechanisms that are based on a
generic index, such as the GNP or CPI. Although these factors
are only applied to certain ancillary pricing components of these
agreements, as required by the interpretation of DIG Issue C15,
Boston Edison began recording this contract at fair value on its
Consolidated Balance Sheets during 2002. This action resulted in
the recognition of a liability for the fair value of the above-
market portion of this contract at December 31, 2002 of
approximately $305 million and is a component of Deferred credits-
Power contracts on the accompanying Consolidated Balance Sheets.
Boston Edison has recorded a corresponding regulatory asset to
reflect the future recovery of the above-market component of this
contract through the transition charge. Therefore, as a result
of this regulatory treatment, the recording of this contract on
the accompanying Consolidated Balance Sheets does not result in
an earnings impact.
Boston Edison has other purchased power contracts in which the
contract value is significantly above-market. However, these
contracts have met the criteria for the normal purchases and
sales exception pursuant to SFAS 133 and DIG Issue C15 and have
not been recorded on the accompanying Consolidated Balance
Sheets. The above-market portion of this contract is currently
being recovered through the transition charge. Therefore, Boston
Edison does not account for these types of capacity and energy
contracts or purchase orders for numerous supply arrangements as
derivatives.
Note J. Other Electric Utility Matters
Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric,
including Boston Edison, filed proposed service quality plans for
each company with the MDTE. 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. Concurrently, NSTAR Electric
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. On
March 22, 2002, following hearings on the matter, the MDTE issued
an order imposing a service quality penalty of approximately
$3.25 million on NSTAR Electric of which $3.2 million related
specifically to Boston Edison that was refunded to customers as a
credit to their bills during the month of May 2002. This refund
had no material effect on Boston Edison's consolidated financial
position, cash flows or results of operations in 2002. For the
four-month period ended December 31, 2001, the MDTE determined
that NSTAR's performance relative to service quality measures did
not warrant a penalty assessment.
On February 28, 2003, NSTAR Electric and NSTAR Gas filed their
2002 Service Quality Reports with the MDTE that reflected
significant improvements in reliability and performance and
indicate that no penalty will be assessed for this period. The
Company accounts for its service quality penalties pursuant to
SFAS 5, "Accounting for Contingencies." Accordingly, these
penalties are monitored on a monthly basis to determine the
Company's contingent liability, and if the Company determines it
is probable that a liability has been incurred and is estimable,
the Company would then accrue an appropriate liability.
Annually, each NSTAR utility subsidiary makes a service quality
performance filing with the MDTE. Any settlement or rate order
that would result in a different liability (or credit) level from
what has been accrued would be adjusted in the period an
agreement is reached with the MDTE.
Note K. 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 2002
are as follows:
(in thousands)
2003 $ 12,811
2004 11,822
2005 10,697
2006 8,987
2007 7,737
Years thereafter 33,590
Total $ 85,644
========
The total expense for both lease rentals and transmission
agreements was $58.1 million in 2002, $57.1 million in 2001 and
$45.3 million in 2000, net of capitalized expenses of $1.9
million in 2002, $2.3 million in 2001 and $1.7 million in 2000.
Boston Edison has entered into a short-term power purchase
agreement to meet its entire default service supply obligation
for the period January 1, 2003 through June 30, 2003 and for 50%
of its obligation for the second-half of 2003. A Request for
Proposals will be issued in the second quarter of 2003 for the
remainder of the obligation. Boston Edison entered into
agreements ranging in length from five to twelve-months effective
January 1, 2002 through December 31, 2002 with suppliers to
provide full default service energy and ancillary service
requirements at contract rates approved by the MDTE. Boston
Edison is completely recovering all of the payments it is making
to suppliers and has financial and performance assurances and
financial guarantees in place with those suppliers to protect
Boston Edison from risk in the unlikely event any of its
suppliers encounter financial difficulties or fail to maintain an
investment grade credit rating. In connection with certain of
these agreements, should, in the unlikely event, Boston Edison
receives a credit rating below investment grade, that company
potentially could be required to obtain certain financial
commitments, including but not limited to, letters of credit.
Refer to Note H, "Long-Term Contracts for the Purchase of
Electricity" for a further discussion.
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, 2002,
Boston Edison's portion of these guarantees was $10 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 2002, NEH
repurchased a total of 325,000 of its outstanding shares from all
equity holders and NHH repurchased a total of 1,725 outstanding
shares from all equity holders. Through December 31, 2002,
Boston Edison's reduction of its equity ownership resulting from
NEH buy-back of 35,915 shares and NHH buy-back of 191 shares was
approximately $870,000.
Boston Edison has a 9.5% equity investment in Connecticut Yankee
Atomic Power Company (CYAPC) and Yankee Atomic Electric Company
(YAEC), together the Yankee Companies. Periodically, Boston
Edison obtains estimates from the management of the Yankee
Companies on the cost of decommissioning the Connecticut Yankee
nuclear unit (CY) and the Yankee Atomic nuclear unit (YA). These
nuclear units are completely shut down and are currently
conducting decommissioning activities.
Based on estimates from the Yankee Companies' management as of
December 31, 2002, the total cost for decommissioning each
nuclear unit is approximately as follows: $247.7 million for CY
and $224.9 million for YA. Of these amounts, Boston Edison is
obligated to pay $23.6 million towards the decommissioning of CY
and $21.4 million toward YA. These estimates are recorded in the
accompanying Consolidated Balance Sheets as Power contract
liabilities with a corresponding regulatory asset. These
estimates may be revised from time to time based on information
available to the Yankee Companies regarding future costs.
Boston Edison expects the Yankee Companies to seek recovery of
these costs and any additional increases to these costs in rate
applications with the FERC, with any resulting adjustments being
charged to their respective sponsors, including Boston Edison.
Boston Edison would recover its share of any allowed increases
from customers through its own filings with the MDTE.
The various decommissioning trusts for which Boston Edison is
responsible through its equity ownership are established pursuant
to the Code of Federal Regulations, Title 18 - Conservation of
Power and Water Resources. The investment of decommissioning
funds that have been established, are managed in accordance with
these federal guidelines, state jurisdictions and with the
applicable Internal Revenue Service requirements. Some of the
requirements state that these investments be managed
independently by a prudent fund manager and that funds are to be
invested in conservative, minimum risk investment securities.
Any gains or losses are anticipated to be refunded to or
collected from customers, respectively.
3. Environmental Matters
As of December 31, 2002, Boston Edison was involved in 12 state-
regulated properties ("Massachusetts Contingency Plan, or "MCP"
sites") where oil or other hazardous materials were previously
spilled or released. On February 4, 2003, Boston Edison closed
out one of these sites and filed the required information with
the Massachusetts Department of Environmental Protection. 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 result of involvement in multi-party disposal sites or third
party claims associated with contamination remediation. Boston
Edison generally expects to have only a small percentage of the
total potential liability for these sites. Estimates of
approximately $3.7 million and $4.8 million are included as
liabilities in the accompanying Consolidated Balance Sheets at
December 31, 2002 and 2001, respectively, and are the total
amount of Boston Edison's estimated environmental clean-up
obligations. Accordingly, this amount has not been reduced by
any potential rate recovery treatment of these costs or any
potential recovery from Boston Edison's insurance carriers.
Prospectively, should Boston Edison be allowed regulatory rate
recovery of these specific costs, it would record an offsetting
regulatory asset and record a credit to operating expenses equal
to previously expensed costs. 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.
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
evolve or are resolved. Boston Edison's ultimate liability for
future environmental remediation costs may vary from these
estimates. Although, 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 consolidated financial position or results of operations
for a reporting period.
4. Regulatory and Legal Proceedings
a. Regulatory proceedings
In December 2002, Boston Edison filed proposed transition rate
adjustments for 2003, including a preliminary reconciliation of
transition, transmission, standard offer and default service
costs and revenues through 2002. The MDTE subsequently approved
tariffs for each retail electric subsidiary effective January 1,
2003. The filings were updated in February 2003 to include final
costs for 2002.
On November 14, 2002, Boston Edison and the AG (Settling Parties)
received approval from the MDTE on a Settlement Agreement
resolving issues in Boston Edison's reconciliation of costs and
revenues for the year 2001. Among other issues, the Settlement
Agreement includes an adjustment relating to the reconciliation
of costs relating to securitization and maximum mitigation of
costs incurred in relation to the purchased power agreement with
Hydro Quebec. As a result of this Settlement Agreement with the
AG, Boston Edison recognized approximately $11.4 million in
transition charge revenues in 2002. This benefit was
significantly offset by other regulatory reconciliation
adjustments.
In December 2001, Boston Edison filed proposed transition rate
adjustments for 2002, including a preliminary reconciliation of
costs and revenues through 2001. The MDTE subsequently approved
tariffs for the Company effective January 1, 2002. The filing
was updated in February 2002 to include final costs for 2001.
The MDTE approved the reconciliation of costs and revenues for
Boston Edison through 2000 in its approval of a Settlement
Agreement on November 16, 2001 between Boston Edison and the
Massachusetts Attorney General (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 Boston Edison's consolidated financial
position, results of operations or cash flows.
b. Merger Rate Plan
On December 16, 2002, the Massachusetts Supreme Judicial Court
(SJC) upheld the MDTE's 1999 decision to allow for the merger of
BEC and COM/Energy as originally structured. The SJC decision
finalized the resolution of all issues related to the appeal and
did not have any impact on Boston Edison's 2002 or prior periods'
consolidated financial position, cash flows or results of
operations. The 1999 MDTE order approving the rate plan
associated with the merger of BEC and COM/Energy, was appealed to
the SJC by the Massachusetts Attorney General (AG) and a separate
group that consisted of The Energy Consortium (TEC) and Harvard
University (Harvard). TEC and Harvard alleged that, in approving
the rate plan and merger proposal, the MDTE committed errors of
law in the following areas: (1) in adopting a public interest
standard, the MDTE applied the wrong standard of review, and
failed to investigate the propriety of rates and to determine
that the resulting rates of Boston Edison, Cambridge Electric,
ComElectric and NSTAR Gas were just and reasonable; (2) that in
permitting Cambridge Electric and ComElectric to adjust their
rates by $49.8 million to reflect demand-side management costs,
the MDTE failed to determine whether such an adjustment was
warranted in light of other cost decreases; (3) that the MDTE's
approval results in an arbitrary and unjustified sharing of
benefits and costs between ratepayers and shareholders; and (4)
that the MDTE's approval of the rate plan guarantees shareholders
recovery of future costs without any future demonstration of
customer savings. The AG's brief includes similar arguments in
each of these areas and adds that, in allowing recovery of the
acquisition premium, the MDTE has improperly deviated from a cost
basis in setting approved rates and the ratemaking policies in
other jurisdictions.
c. Other legal matters
In the normal course of its business, Boston Edison and its
subsidiaries are involved in certain legal matters, including
civil lawsuits. Management is unable to fully determine a range
of reasonably possible court-ordered damages, settlement amounts,
and related litigation costs ("legal liabilities") that would be
in excess of amounts accrued. Based on the information currently
available, Boston Edison does not believe that it is probable
that any such additional legal liability will have a material
impact on its consolidated financial position. However, it is
reasonably possible that additional legal liabilities that may
result from changes in estimates could have a material impact on
its results of operations for a reporting period.
5. Performance Assurances from Electricity Agreements
Boston Edison has entered into a series of purchased power
agreements to meet its default and standard offer service supply
obligations through December 31, 2003. These agreements are
generally for a term of six to twelve months. Boston Edison
currently is recovering payments it is making to suppliers from
its customers. Most of Boston Edison's power suppliers are
subsidiaries of larger companies with investment grade or better
credit ratings. Boston Edison has financial assurances and
guarantees that include letters of credit in place with the
parent company of the supplier, to minimize Boston Edison risk in
the event the supplier encounters financial difficulties or
otherwise fails to perform. In addition, under these agreements,
in the event that the supplier (or its parent guarantor) fails to
maintain an investment grade credit rating, it is required to
provide additional security for performance of its obligations.
Boston Edison's policy is to enter into power supply arrangements
only if the supplier (or its parent guarantor) has an investment
grade or better credit rating. In view of current volatility in
the energy supply industry, Boston Edison is unable to determine
whether its suppliers (or their parent guarantors) will become
subject to financial difficulties, or whether these financial
assurances and guarantees are sufficient. In the event, the
supplier (or its guarantor) may not be in a position to provide
the required additional security, Boston Edison may then
terminate the agreement. Some of these agreements include a
reciprocal provision, where in the event that Boston Edison
receives a credit rating below investment grade, that company
could be required to provide additional security for performance,
such as a letter of credit.
6. Financial and Performance Guarantees
On a limited basis, Boston Edison may enter into agreements
providing financial assurance to third parties. Such agreements
include surety bonds and other guarantees.
At December 31, 2002, outstanding guarantees totaled $17 million
as follows:
(in thousands)
Surety Bonds $ 7,013
Other Guarantees 10,000
Total Guarantees $ 17,013
=======
At December 31, 2002, Boston Edison has purchased a total of
approximately $600,000 of performance surety bonds for the
purpose of obtaining licenses, permits and rights-of-way in
various municipalities. In addition, Boston Edison has purchased
$6.4 million in workers' compensation self-insurer bonds. These
bonds support the guarantee by Boston Edison to the Commonwealth
of Massachusetts required as part of Boston Edison's workers'
compensation self-insurance program.
Boston Edison has also issued $10 million of residual value
guarantees related to its equity interest in the Hydro-Quebec
transmission companies.
Management believes the likelihood Boston Edison would be
required to perform or otherwise incur any significant losses
associated with any of these guarantees is remote.
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
None.
Part IV
Item 14. Controls and Procedures
Boston Edison's disclosure controls and procedures are designed
to ensure that information required to be disclosed in reports
that it files or submits under the Securities Exchange Act of
1934 is recorded, processed, summarized and reported within the
time periods specified in the rules and forms of the Securities
and Exchange Commission.
Within 90 days prior to the date of filing this Annual Report on
Form 10-K, Boston Edison carried out an evaluation, under the
supervision and with the participation of Boston Edison's
management, including Boston Edison's Chief Executive Officer and
Chief Financial Officer, of the effectiveness of the design and
operation of Boston Edison's disclosure controls and procedures
pursuant to Exchange Act Rule 13a-14. Based on that evaluation,
the Chief Executive Officer and the Chief Financial Officer
concluded that Boston Edison's disclosure controls and procedures
are effective in order to timely alert them to material
information required to be disclosed by Boston Edison in the
reports that it files or submits under the Securities Exchange
Act of 1934.
Subsequent to the date of that evaluation, there have been no
significant changes in Boston Edison's internal controls or in
other factors that could significantly affect internal controls,
nor were any corrective actions required with regard to
significant deficiencies and material weaknesses.
Item 15. 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, 2002, 2001 and 2000 26
Consolidated Statements of Comprehensive Income for
the years ended December 31, 2002, 2001 and 2000 27
Consolidated Statements of Retained Earnings for the
years ended December 31, 2002, 2001 and 2000 27
Consolidated Balance Sheets as of December 31, 2002
and 2001 28
Consolidated Statements of Cash Flows for the years
ended December 31, 2002, 2001 and 2000 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, 2002, 2001 and 2000 57
3. Exhibits:
Refer to the exhibits listing beginning on the
following page.
(b) Reports on Form 8-K:
A report on Form 8-K was filed on October 11, 2002
that reported on including certain exhibits for
incorporation by reference into the Registration
Statements on Form S-3 previously filed with the
Securities and Exchange Commission (Nos. 33-57840 and
333-55890) and declared effective on February 12, 1993
and February 28, 2001, respectively with regard to the
issuance of $500 million in debentures.
A report on Form 8-K was filed on November 27, 2002
that reported on revised decommissioning costs of
certain nuclear units in which Boston Edison has an
equity ownership interest.
A report on Form 8-K was filed on December 17, 2002
that reported on the Massachusetts Supreme Judicial
Court affirming a 1999 MDTE order associated with the
merger of BEC Energy and Commonwealth Energy System
that created NSTAR.
A report on Form 8-K was filed on January 3, 2003
following the MDTE approval received on December 20,
2002 to allow the Company to defer as a regulatory
asset, an additional minimum liability, and the
difference between the level of pension and
postretirement benefits that is included in rates and
the amounts that would have been recorded under SFAS
87 and SFAS 106 in 2003.
Incorporated herein by reference unless designated otherwise:
Exhibit SEC Docket
Exhibit 3 Articles of Incorporation and
By-Laws
3.1 Restated Articles of 3.1 1-2301
Organization Form 10-Q
for the
quarter
ended June
30, 1994.
3.2 Boston Edison Company Bylaws 3.1 1-2301
April 19, 1977, as amended Form 10-Q
January 22, 1987, January 28, for the
1988, May 24, 1988 and quarter
November 22, 1989. ended June
30, 1994.
Exhibit 4 Instruments Defining the
Rights of Security Holders,
Including Indentures
4.1 Indenture dated September 1, 4.1 1-2301
1988, between Boston Edison Form 10-Q
Company and The Bank of New for the
York (as successor to Bank of quarter
Montreal Trust Company). ended
September
30, 1988.
4.2 Votes of the Pricing 4.1.5 1-2301
Committee of the Board of Form 10-K
Directors of Boston Edison for the
Company taken May 18, 1995 re year ended
7.80% debentures due May 15, December
2010. 31, 1995.
4.3 Votes of the Board of 4.2 1-2301
Directors of Boston Edison Form 8-K
Company taken October 8, 2002 dated
re $500 million aggregate October 11,
principal amount of unsecured 2002.
debentures ($400 million,
4.875% due in 2012 and $100
million, floating rate due in
2005).
Management agrees to furnish to the Securities and Exchange
Commission, upon request, a copy of any other agreements or
instruments of the Registrant defining the rights of holders of
any long-term debt whose authorization does not exceed 10% of
total assets.
Exhibit 10 Material Contracts
10.1 Boston Edison Company 10.12 1-2301
Restructuring Settlement Form 10-K
Agreement dated July 1997. for the
year ended
December
31, 1997.
10.2 Boston Edison Company and 10.1 1-2301
Sithe Energies, Inc. Purchase Form 10-Q
and Sale and Transition for the
Agreements dated December 10, quarter
1997. ended March
31, 1998.
10.3 Boston Edison Company and 10.12 1-2301
Entergy Nuclear Generation Form 10-K
Company Purchase and Sale for the
Agreement dated November 18, year ended
1998. December
31, 1999.
Exhibit 12 Statement re Computation of Ratios
12.1 Computation of Ratio of
Earnings to Fixed Charges for
the Year Ended December 31,
2002 (filed herewith).
12.2 Computation of Ratio of
Earnings to Fixed Charges and
Preferred Stock Dividend
Requirements for the Year
Ended December 31, 2002
(filed herewith).
Exhibit 21 Subsidiaries of the
Registrant
21.1 Filed herewith.
Exhibit 99 Additional Exhibits
99.1 Certification Statement of
Chief Executive Officer of
Boston Edison Company
pursuant to Section 906 of
the Sarbanes-Oxley Act of
2002 (filed herewith).
99.2 Certification Statement of
Chief Financial Officer of
Boston Edison Company
pursuant to Section 906 of
the Sarbanes-Oxley Act of
2002 (filed herewith).
SCHEDULE II
BOSTON EDISON COMPANY
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000
(in thousands)
Balance at Provisions Deductions Balance
Beginning Charged to Accounts at End
Description Of Year Operations Recoveries Written Off Of Year
Allowance for
Doubtful Accounts
Year Ended
December 31, 2002 $24,691 $10,699 $4,630 $20,936 $19,084
Year Ended
December 31, 2001 $22,415 $13,000 $2,089 $12,813 $24,691
Year Ended
December 31, 2000 $19,380 $11,954 $ 471 $9,390 $22,415
FORM 10-K Boston Edison Company DECEMBER 31, 2002
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 27, 2003 By: /s/Robert J. Weafer, Jr.
Robert J. Weafer, Jr.
Vice President, Controller and
Chief Accounting 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 indicated on
the 27th day of March 2003.
Signature Title
Chairman, President, Chief
/s/ Thomas J.May Executive Officer and Director
Thomas J. May
Senior Vice President,
/s/ James J. Judge Treasurer, Chief Financial
James J. Judge Officer and Director
Director
/s/ Douglas S. Horan
Douglas S. Horan
Sarbanes - Oxley Section 302(a) Certifications
I, Thomas J. May, certify that:
1. I have reviewed this Annual Report on Form 10-K of Boston
Edison Company;
2. Based on my knowledge, this Annual Report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this Annual
Report;
3. Based on my knowledge, the financial statements, and other
financial information included in this Annual Report, fairly
present in all material respects the financial condition,
results of operations and cash flows of Boston Edison Company
as of, and for, the periods presented in this Annual Report;
4. Boston Edison Company's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-
14 and 15d-14) for Boston Edison Company and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to Boston Edison
Company, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly
during the period in which this Annual Report is being
prepared;
b) evaluated the effectiveness of Boston Edison Company's
disclosure controls and procedures as of a date within 90
days prior to the filing date of this Annual Report (the
"Evaluation Date"); and
c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. Boston Edison Company's other certifying officer and I have
disclosed, based on our most recent evaluation, to Boston
Edison Company's auditors and the audit committee of NSTAR's
Board of Trustees:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect Boston
Edison Company's ability to record, process, summarize and
report financial data and have identified for Boston Edison
Company's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. Boston Edison Company's other certifying officer and I have
indicated in this Annual Report whether or not there were
significant changes in internal controls or in other factors
that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 27, 2003 By /s/ THOMAS J. MAY
Thomas J. May
Chairman, President and
Chief Executive Officer
I, James J. Judge, certify that:
1. I have reviewed this Annual Report on Form 10-K of Boston
Edison Company:
2. Based on my knowledge, this Annual Report does not contain any
untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
Annual Report;
3. Based on my knowledge, the financial statements, and other
financial information included in this Annual Report, fairly
present in all material respects the financial condition,
results of operations and cash flows of Boston Edison Company
as of, and for, the periods presented in this Annual Report;
4. Boston Edison Company's other certifying officer and I are
responsible for establishing and maintaining disclosure
controls and procedures (as defined in Exchange Act Rules 13a-
14 and 15d-14) for Boston Edison Company and we have:
a) designed such disclosure controls and procedures to
ensure that material information relating to Boston
Edison Company, including its consolidated subsidiaries,
is made known to us by others within those entities,
particularly during the period in which this Annual
Report is being prepared;
b) evaluated the effectiveness of Boston Edison Company's
disclosure controls and procedures as of a date within 90
days prior to the filing date of this Annual Report (the
"Evaluation Date"); and
c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. Boston Edison Company's other certifying officer and I have
disclosed, based on our most recent evaluation, to Boston
Edison Company's auditors and the audit committee of NSTAR's
Board of Trustees:
a) all significant deficiencies in the design or operation
of internal controls which could adversely affect Boston
Edison Company's ability to record, process, summarize
and report financial data and have identified for Boston
Edison Company's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role
in Boston Edison Company's internal controls; and
6. Boston Edison Company's other certifying officer and I have
indicated in this Annual Report whether or not there were
significant changes in internal controls or in other factors
that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and
material weaknesses.
Date: March 27, 2003 By: /s/ JAMES J. JUDGE
James J. Judge
Senior Vice President, Treasurer
and Chief Financial Officer