UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549-1004
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
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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
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BOSTON EDISON COMPANY
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(Exact name of registrant as specified in its charter)
Massachusetts 04-1278810
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
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(Address of principal executive offices) (Zip Code)
(617) 424-2000
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(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 15, 2000
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Common Stock, $1 par value 100 shares
The Company meets the conditions set forth in General Instruction I(1)(a) and
(b) of Form 10-K as a wholly-owned subsidiary and is therefore filing this Form
with the reduced disclosure format.
Documents Incorporated by Reference Part in Form 10-K
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None Not Applicable
List of Exhibits begins on page 35 of this report.
Boston Edison Company
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Form 10-K Annual Report
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December 31, 1999
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Part I Page
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Item 1. Business 3
Item 2. Properties 7
Item 3. Legal Proceedings 7
Part II
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Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 9
Item 7. Management's Discussion and Analysis 10
Item 8. Financial Statements and Supplementary Financial
Information 20
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 38
Part IV
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Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 39
2
Part I
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Item 1. Business
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(a) General Development of Business
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Boston Edison Company (Boston Edison), is an investor-owned regulated public
utility incorporated in 1886 under Massachusetts law. Prior to the August 25,
1999 merger transaction, the company received final approval of its
reorganization plan to form a holding company structure from the Securities and
Exchange Commission (SEC) in May 1998. Effective May 20, 1998 the holding
company, BEC Energy (BEC), was formed with Boston Edison as a wholly owned
subsidiary of BEC. Effective June 25, 1998, Boston Energy Technology Group
(BETG) ceased being a subsidiary of Boston Edison and became a wholly owned
subsidiary of BEC.
Boston Edison Company is a wholly owned subsidiary of NSTAR. NSTAR was created
through a merger transaction with BEC energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25,1999 as an exempt public utility a holding
company. NSTAR's utility subsidiaries are Boston Edison, Commonwealth Electric
Company (ComElectric), Cambridge Electric Light Company (Cambridge Electric),
Canal Electric Company (Canal Electric) and Commonwealth Gas Company (ComGas).
The electric industry has continued to change in response to legislative,
regulatory and marketplace demands for improved customer service at lower
prices. These demands have resulted in an increasing trend in the industry to
seek competitive advantages and other benefits through business combinations.
NSTAR was created to operate in this new marketplace by combining the resources
of its utility subsidiaries and concentrating its activities in the transmission
and distribution of energy. This is illustrated by the sale of Boston Edison's
fossil generating facilities in 1998 and its nuclear generating facility in
1999.
In 1998, Boston Edison completed the sale of all of its fossil generating
assets. The amount received above net book value on the sale of these assets is
being returned to customers over approximately 11 years.
To complete its divestiture of generating assets, Boston Edison sold the Pilgrim
Nuclear Generating Station (Pilgrim) on July 13, 1999, for $81 million to
Entergy Nuclear Generating Company (Entergy). As part of the sale, Boston Edison
transferred approximately $228 million in decommissioning funds to the
purchaser. The purchaser, by contract, assumed all future liability related to
the ultimate decommissioning of the plant. The difference between the total
proceeds from the sale and the net book value of the Pilgrim assets plus the net
amount to fully fund the decommissioning trust is included in regulatory assets
on the accompanying Consolidated Balance Sheets as such amounts are collected
from customers.
On July 29, 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary of
Boston Edison, closed the sale of $725 million of notes to a special purpose
trust created by two Massachusetts state agencies. The trust then concurrently
closed the sale of $725 million of electric rate reduction certificates as a
public offering. The certificates are secured by a portion of the transition
charge assessed on Boston Edison's retail customers as permitted under the
Massachusetts Electric Restructuring Act and authorized by the Commonwealth of
Massachusetts Department of Telecommunication and Energy (MDTE). These
certificates are non-recourse to Boston Edison.
(b) Financial Information about Industry Segments
---------------------------------------------
Boston Edison operates as a regulated electric public utility, therefore
industry segment information is not applicable.
3
(c) Narrative Description of Business
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Principal Products and Services
Boston Edison currently supplies electricity at retail to an area of 590 square
miles, including the city of Boston and 39 surrounding cities and towns. The
population of the area served with electricity at retail is approximately 1.5
million. In 1999 Boston Edison served an average of approximately 674,000
customers. Electric operating revenues by class for the last three years
consisted of the following:
1999 1998 1997
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Retail electric revenues:
Commercial 51% 51% 51%
Residential 29% 27% 27%
Industrial 9% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 10% 12% 12%
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BEC
In May 1998, Boston Edison received final approval from the SEC for its
reorganization plan to form a holding company structure. Effective May 20,
1998, BEC, the holding company, was formed and Boston Edison became a wholly
owned subsidiary of BEC. Effective June 25, 1998, BETG ceased being a
subsidiary of Boston Edison and became a wholly owned subsidiary of BEC.
Unregulated activities are conducted through BETG and include telecommunications
and district cooling services. BEC is currently a subsidiary of NSTAR.
Sources and Availability of Electric Power Supply
NSTAR on behalf of its electric retail subsidiaries, including Boston Edison,
entered into a six-month agreement effective January 1, 2000 to transfer all of
the unit output entitlements in long-term power purchase contracts to Select
Energy (Select), a subsidiary of Northeast Utilities. In return, Select will
provide full energy service requirements, including NEPOOL capability
responsibilities, at FERC approved tariff rates through June 30, 2000.
In addition, Boston Edison will buy power generated by the Pilgrim Nuclear Power
station from Entergy on a declining basis through 2004.
Information relative to nuclear units that are no longer operating in which
Boston Edison has an equity ownership is as follows:
Connecticut Yankee
Yankee Atomic
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(dollars in thousands)
Year of Shutdown 1996 1992
Equity Ownership (%) 9.5 9.5
Equity Ownership Balance $9,888 $1,609
New England Power Pool (NEPOOL)
During 1997, NEPOOL was restructured, with changes taking effect to the
membership and governance provisions of the power pooling agreement, along with
the transfer of operating responsibility of the integrated transmission and
generation system in New England to ISO New England. Previously, NEPOOL
dispatched generating units for operation based on the lowest operating costs of
available generation and transmission. Under the new structure, generators will
be required to provide ISO New England with market prices at which they will
sell short-term energy supply. These prices formed the basis for
4
dispatch that began in the second quarter of 1999. As noted in the Sources and
Availability of Electric Power Supply section above, Boston Edison will receive
all of their power supply requirements from Select through June 30, 2000.
Therefore, the change to NEPOOL's operations and pricing structure is expected
to have no material impact on Boston Edison's costs for purchased electric
energy.
Franchises
Through its charter, which is unlimited in time, Boston Edison has the right to
engage in the business of producing and selling electricity, steam and other
forms of energy, has powers incidental thereto and is entitled to all the rights
and privileges of and subject to the duties imposed upon electric companies
under Massachusetts laws. The locations in public ways for electric transmission
and distribution lines are obtained from municipal and other state authorities
which, in granting these locations, act as agents for the state. In some cases
the action of these authorities is subject to appeal to the MDTE. The rights to
these locations are not limited in time, but are not vested and are subject to
the action of these authorities and the legislature. Pursuant to the
Massachusetts Electric 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, Harbor Electric Energy Company
(HEEC) and BEC Funding, LLC, operate primarily under the authority of the MDTE,
whose jurisdiction includes supervision over retail rates for distribution of
electricity, financing and investing activities. In addition, the Federal Energy
Regulatory Commission (FERC), has jurisdiction over various phases of Boston
Edison's electric utility businesses including rates for electricity sold at
wholesale for resale, facilities used for the transmission or sale of that
energy, certain issuances of short-term debt and regulation of the system of
accounts.
Retail Electric Rates
As a result of electric industry restructuring, Boston Edison unbundled its
rates, provided customers with a 10 percent rate reduction as of March 1, 1998
and a 15% rate reduction as of September 15, 1999 and has 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 above market power contracts), a
transmission charge (to collect the cost of moving the electricity over high
voltage lines from a generating plant), an energy conservation charge (to
collect costs for demand-side management programs) and a renewable energy charge
(to collect the cost to support the development and promotion of renewable
energy projects). Electricity supply services provided by Boston Edison include
optional standard offer service and default service.
Standard offer service is the electricity that is supplied to eligible customers
until a competitive power supplier is chosen by the customer. It is designed as
a seven-year transitional service to give the customer time to learn about
competitive power suppliers. The price of standard offer service will increase
over time. Default service is supplied to customers who are not eligible for
standard offer service when the customer is not receiving power from a
5
competitive power supplier. The market price for default service is intended to
reflect the average market price for power. Amounts collected through these
various charges will be reconciled to actual expenditures on an on-going basis.
Prior to the implementation of industry restructuring on March 1, 1998, Boston
Edison had Fuel Charge rate schedules that generally allowed for current
recovery, from retail customers, of fuel used in electric production, purchased
power and transmission costs. These schedules required a quarterly computation
and MDTE approval of a Fuel Charge decimal based upon forecasts of fuel,
purchased power, transmission costs and billed unit sales for each period. To
the extent that collections under the rate schedules did not match actual costs
for that period, an appropriate adjustment was reflected in the calculation of
the next subsequent calendar quarter decimal. These rate schedules are no
longer in effect.
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 it 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, air and water quality and other
environmental considerations. These standards could require modification of
existing facilities or curtailment or termination of operations at these
facilities. They could also potentially delay or discontinue construction of
new facilities and increase capital and operating costs by substantial
amounts. Noncompliance with certain standards can, in some cases, also result
in the imposition of monetary civil penalties.
Environmental-related capital expenditures for the years 1999 and 1998 were $0.6
million and $1.4 million, respectively. Management believes that its operating
facilities are in substantial compliance with currently applicable statutory and
regulatory environmental requirements. Additional expenditures could be required
as changes in environmental requirements occur.
Number of Employees
Boston Edison had 1,933 full-time employees as of December 31, 1999, including
1,341 (69%) represented by two locals of the Utility Workers Union of America,
AFL-CIO. The locals' labor contracts are effective through May 15, 2000.
Management believes it has satisfactory employee relations.
(d) Financial Information about Foreign and Domestic Operations and Export
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Sales
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Boston Edison delivers electricity to retail and wholesale customers in the
Boston area. Boston Edison does not have any foreign operations or export
sales.
Expenditures and Financings
The most recent estimates of plant expenditures (excluding nuclear fuel),
allowance for funds used during construction (AFUDC), long-term debt maturities
and preferred stock payment requirements for the years 2000 through 2004 are as
follows:
6
(in thousands) 2000 2001 2002 2003 2004
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Capital
expenditures $102,000 $108,000 $ 93,000 $ 86,000 $ 86,000
AFUDC $ 3,200 $ 3,200 $ 3,200 $ 3,200 3,200
Long-term debt $217,500 $114,000 $ 71,800 $220,700 70,400
Preferred stock $ - $ 50,000 $ - $ - -
=============================================================================
Management continuously reviews its plant 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, environmental
standards, availability and cost of capital, interest rates and other
assumptions.
Plant expenditures in 1999 were $115 million 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.
Refer to the Liquidity section of Item 7 for more information regarding
capital resources to fund construction programs.
Item 2. Properties
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All of Boston Edison's non-nuclear generating assets were sold as of December
31, 1998.
Boston Edison's high-tension transmission lines are generally located on land
either owned or subject to easements in its favor. Its low-tension
distribution lines are located principally on public property under permission
granted by municipal and other state authorities.
As of December 31, 1999, Boston Edison's transmission system consisted of 376
miles of overhead circuits operating at 115, 230 and 345 kilovolts (kV) and
171 miles of underground circuits operating at 115 and 345 kV. The
substations supported by these lines are 45 transmission or combined
transmission and distribution substations with transformer capacity of 11,053
megavolt amperes (MVA), 57 4 kV distribution substations with transformer
capacity of 932 MVA and 16 primary network units with 79 MVA capacity. In
addition, high tension service was delivered to 248 customers' substations.
The overhead and underground distribution systems cover approximately 3,700
and 3,200 circuit miles, respectively. HEEC, Boston Edison's regulated
subsidiary, has a distribution system that consists principally of a 4.1 mile
115 kV submarine distribution line and a substation which is located on Deer
Island in Boston, Massachusetts. HEEC provides the ongoing support required
to distribute electric energy to its one customer, the Massachusetts Water
Resources Authority, at this location.
Item 3. Legal Proceedings
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Industry and corporate restructuring legal proceedings
The MDTE order approving the Boston Edison restructuring settlement agreement
was appealed by certain parties to the Massachusetts Supreme Judicial Court
(SJC). One settlement agreement appeal remains pending, however there has to
date been no briefing, hearing or other action taken with respect to this
proceeding.
In addition, along with other Massachusetts investor-owned utilities, Boston
Edison has been named as a defendant in a class action suit seeking to declare
certain provisions of the Massachusetts electric industry restructuring
legislation unconstitutional.
7
Management is currently unable to determine the outcome of these outstanding
proceedings however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.
Regulatory proceedings
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated activities.
Hearings were completed in the fourth quarter of 1999. A MDTE ruling is
expected in 2000.
Management is currently unable to determine the outcome of this proceeding
however, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.
Merger Rate Plan
An integral component of the merger which created NSTAR was a rate plan filed by
its retail utility subsidiaries, including Boston Edison. The MDTE issued an
order approving most major elements of the rate plan on July 27, 1999. The
highlights of the rate plan include a four-year distribution rate freeze for
each of the NSTAR retail utility subsidiaries, including Boston Edison, the
collection from customers of the acquisition premium of approximately $486
million over 40 years and the recovery of transaction and integration costs
initially estimated at approximately $111 million over 10 years. The
Massachusetts Attorney General and a group of four interveners filed separate
appeals of the MDTE order with the Massachusetts Supreme Judicial Court (SJC)
regarding the rate plan. While management anticipates that the MDTE's decision
to approve the rate plan will be upheld by the SJC, it cannot determine the
ultimate outcome of these appeals or their impact on the rate plan.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim
Station, filed suit against Boston Edison. The town claimed that Boston
Edison wrongfully failed to execute an agreement with the town for payments in
addition to taxes due to the town under the Massachusetts electric industry
restructuring legislation. Boston Edison and the town agreed on a 15-year,
$141 million property tax package in March 1999. Payments in each of the
first four years are approximately $15 million after which payments gradually
decline. All payments under this agreement will be recovered from customers
through the transition charge.
In the normal course of its business Boston Edison is also involved in certain
other legal matters. Management is unable to fully determine a range of
reasonably possible legal costs in excess of amounts accrued. Based on the
information currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact
on the results of a reporting period in the near term.
8
Part II
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Item 5. Market for the Registrant's Common Stock and Related Stockholder
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Matters
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Market information for the common stock of NSTAR, Boston Edison's parent
company, is included in Item 5 of NSTAR's report on Form 10-K.
The following information is furnished in connection with the Registration
Statement on Form S-3 of the Registrant (File No. 33-57840), filed on
February 3, 1993.
Ratio of earnings to fixed charges and ratio of earnings to fixed charges and
preferred stock dividend requirements for the year ended December 31, 1999:
Ratio of earnings to fixed charges 3.06
Ratio of earnings to fixed charges and
preferred stock dividend requirements 2.84
9
Item 7. Management's Discussion and Analysis
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Boston Edison is a wholly-owned subsidiary of NSTAR. NSTAR was created through
the merger of BEC Energy (BEC) and Commonwealth Energy System (COM/Energy) on
August 25, 1999 as an exempt public utility holding company. NSTAR's utility
subsidiaries are Boston Edison, Commonwealth Electric Company (ComElectric),
Cambridge Electric Light Company (Cambridge Electric), Canal Electric Company
(Canal Electric) and Commonwealth Gas Company (ComGas).
The electric and natural gas industries have continued to change in response to
legislative, regulatory and marketplace demands for improved customer service at
lower prices. These demands have resulted in an increasing trend in the
industry to seek competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new marketplace by combining
the resources of its utility subsidiaries and concentrating its activities in
the transmission and distribution of energy. This is illustrated by the sale of
Boston Edison's fossil generating facilities in 1998 and its nuclear generating
facility in 1999.
Prior to the August 25, 1999 merger which formed NSTAR, Boston Edison received
final approval of its reorganization plan to form a holding company structure
from the Securities and Exchange Commission (SEC) in May 1998. Effective May 20,
1998, BEC Energy (BEC) was formed with Boston Edison as a wholly owned
subsidiary of BEC. Effective June 25, 1998, Boston Energy Technology Group
(BETG) ceased being a subsidiary of Boston Edison and became a wholly owned
subsidiary of BEC. The holding company structure clearly separates the
unregulated and regulated operations of BEC and provides management with greater
organizational flexibility in order to take advantage of utility and nonutility
business opportunities in a more timely manner, including the merger with
Commonwealth Energy System (CES).
Merger of BEC Energy and Commonwealth Energy System
Shareholders of BEC and COM/Energy approved the merger on June 24, 1999.
Pursuant to the merger agreement, BEC shareholders received approximately 41
million shares of NSTAR while COM/Energy shareholders received approximately 20
million shares of NSTAR. In addition, BEC and COM/Energy shareholders received
an aggregate amount of cash of approximately $300 million. An initial quarterly
dividend rate of 48.5 cents per share of NSTAR was declared by the board of
trustees ($1.94 on an annualized basis) on September 23, 1999 and paid on
November 1, 1999. The quarterly dividend was increased to 50 cents per share
($2.00 on an annualized basis) on December 16, 1999. The merger was accounted
for by NSTAR as an acquisition by BEC of COM/Energy under the purchase method of
accounting.
An integral part of the merger is the rate plan that was filed by the retail
utility subsidiaries of BEC and COM/Energy, including Boston Edison, that was
approved by MDTE on July 27, 1999. Significant elements of the rate plan include
a four-year distribution rate freeze recovery of the acquisition premium
(goodwill) over 40 years and recovery of transaction and integration costs
(costs to achieve) over 10 years. Refer to the Retail Electric Rates section of
this discussion for more information.
A group of four interveners and the Massachusetts Attorney General filed two
separate appeals of the MDTE's rate plan order with the Massachusetts Supreme
Judicial Court (SJC) in August 1999. While management anticipates that the
MDTE's decision to approve the rate plan will be upheld by the SJC, it is unable
to determine the ultimate outcome of these appeals.
Generating Assets Divestiture
In 1998, Boston Edison completed the sale of all of its fossil generating
assets. The amount received above net book value on the sale of these assets is
being returned to customers over approximately 11 years.
10
To complete its divestiture of generating assets, Boston Edison sold the Pilgrim
Nuclear Generating Station (Pilgrim) on July 13, 1999, for $81 million to
Entergy Nuclear Generating Company. As part of the sale, Boston Edison
transferred approximately $228 million in decommissioning funds to the
purchaser. The purchase, by the contract, will assume all future liability
related to the ultimate decommissioning of the plant. The difference between
the total proceeds from the sale and the net book value of the Pilgrim assets
plus the net amount to fully fund the decommissioning trust is included in
regulatory assets on the accompanying Consolidated Balance Sheets as such
amounts are collected from customers.
Securitization of Boston Edison's Transition Charge
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On July 29, 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary of
Boston Edison, closed the sale of $725 million of notes to a special purpose
trust created by two Massachusetts state agencies. The trust then concurrently
closed the sale on $725 million of electric rate reduction certificates as a
public offering. The certificates are secured by a portion of the transition
charge assessed on Boston Edison's retail customers as permitted under
the Massachusetts Electric Industry Restructuring Act and authorized by the
MDTE. These certificates are non-recourse to Boston Edison.
Retail Electric Rates
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As a result of the Massachusetts Electric Restructuring Act, Boston Edison
currently provide their standard offer customers service at inflation adjusted
rates that are 15% lower than rates in effect prior to March 1, 1998, the retail
access date.
All distribution customers must pay a transition charge as a component of their
rate. The purpose of the transition charge is to allow for the collection of
generation-related costs that would not be collected in the competitive energy
supply market. The plant and regulatory asset balances that will be recovered
through the transition charge until 2009 were approved by the MDTE.
Massachusetts Electric Industry Restructuring Act requires regulated utilities
to obtain and resell power to customers that choose not to buy energy from a
competitive energy supplier. This is referred to as "standard offer service."
Standard offer service will be available to customers through 2004 at prices
approved by the MDTE. Boston Edison is currently evaluating proposals from a
number of competitive energy providers to assume full responsibility for
providing customers with standard offer service through 2004. The cost of
providing standard offer service, which includes purchased power costs, is
recovered from customers on a fully reconciling basis. New retail customers in
the Boston Edison electric service territory and previously existing customers
that are no longer eligible for the standard offer service and have not chosen
to receive service from a competitive supplier, are on "default service." The
price of default service is intended to reflect the average competitive market
price for power.
Under the restructuring settlement agreement, Boston Edison's distribution
business is subject to a minimum and maximum return on average common equity
(ROE). The ROE is subject to a floor of 6% and a ceiling of 11.75%. If the ROE
is below 6%, Boston Edison is authorized to add a surcharge to distribution
rates in order to achieve the 6% floor. If the ROE is above 11%, it is required
to adjust distribution rates by an amount necessary to reduce the calculated ROE
between 11% and 12.5% by 50%, and a return above 12.5% by 100%. No adjustment
is made if the ROE is between 6% and 11%. This rate mechanism expires on
December 31, 2000. The cost of providing transmission service to all NSTAR
distribution customers is recovered on a fully reconciling basis.
11
Boston Edison filed proposed adjustments to its standard offer and transition
charges with the MDTE in November 1999. The MDTE approved these proposed
adjustments to be effective January 1, 2000. The MDTE continues to examine
Boston Edison's cost recovery mechanism.
Results of Operations
1999 versus 1998
Net income was $160.3 million in 1999 compared to $157.3 million in 1998. This
increase of 2% is described below.
Operating revenues
Operating revenues decreased 4.7% from 1998 as follows:
(in thousands)
- ------------------------------------------------------------
Retail revenues $ 12,379
Wholesale revenues (39,534)
Short-term sales and other revenues (49,000)
- ------------------------------------------------------------
Decrease in operating revenues $(76,155)
============================================================
Retail revenues were $1,387.5 million in 1999 compared to $1,375.1 million in
1998, a increase of $12.4 million or 1%. This change reflects a 4.7% increase
in retail kilowatt-hour (kWh) electric sales that is partially offset by a
decrease in retail revenues reflecting the impact of the 10% reduction in retail
rates mandated by the Massachusetts Electric Industry Restructuring Act that was
initially implemented in March 1998, and an additional 5% rate reduction
effective September 1, 1999.
Wholesale electric revenues were $102.4 million in 1999 compared to $142 million
in 1998, a decrease of $39.6 million or 28%. This decrease in wholesale
revenues reflects a $37 million decrease in sales to Pilgrim contract customers
due to the scheduled 1999 refueling and maintenance outage and subsequent sale
of the Pilgrim station in July 1999.
Short-term sales and other revenues were $56.9 million in 1999 compared to
$105.9 million in 1998, a decrease of $49 million or 46%. The decrease reflects
$20 million of revenue received in 1998 as a result of support of standard offer
service by Boston Edison's fossil generating stations prior to divestiture. The
decline in short-term sales amounting to $35 million is consistent with the
decrease in short-term kWh sales. Under agreements with Select Energy, a
subsidiary of Northeast Utilities, Boston Edison is only purchasing enough power
to meet obligations to its retail and wholesale customers. Therefore, Boston
Edison has no excess power supply to sell into the New England Power Pool.
Operating expenses
Fuel and purchased power was $645.2 million in 1999 compared to $567.8 million
in 1998, an increase of $77.4 million or 14%. Purchased power expense increased
$91 million reflecting the increase in Boston Edison's purchased power
requirements in the absence of its fossil generating units and the 1999 Pilgrim
refueling outage and sale. Boston Edison's adjusts its electric rates to
collect the costs related to fuel and purchased power from customers on a fully
reconciling basis. Boston Edison's fuel and purchased power expenses reflects a
reduction of $56 million in 1999 and $128 million in 1998 related to these rate
recovery mechanisms. Due to rate adjustment mechanisms, changes in the amount
of fuel and purchased power expense have no impact on earnings. The fuel
expense related to Boston Edison's fossil generation units decreased $66 million
reflecting the divestiture of those units in May 1998. Fuel expense related to
Pilgrim decreased $17 million due to the 1999 refueling outage and the sale of
the plant in July 1999.
12
Operations and maintenance expense was $271.4 million in 1999 compared to $373.4
million in 1998, a decrease of $102 million or 27%. This reflects a decrease of
$70 million of nuclear power production expenses due to the deferral of costs
related to the 1999 refueling outage and the ultimate sale of the Pilgrim plant
in July 1999, and a decrease of $22 million in fossil-fuel related power
production expenses due to the fossil generation divestiture in May 1998. In
addition, 1999 reflects a decrease of $7 million in distribution expenses
reflecting a higher level of maintenance spending in 1998.
Depreciation and amortization expense was $176.7 million in 1999 compared to
$195.6 million in 1998, a decrease of $18.9 million or 10%. This decrease
reflects the nuclear divestiture in June 1999 and the amortization of the gain
on the sale of the fossil plants that began in June 1998. These decreases are
partially offset by $2 million resulting from the amortization of costs to
achieve related to the merger and $3 million resulting from an intercompany
charge for Boston Edison's portion of goodwill. These amounts are being
collected from Boston Edison's customers in accordance with the rate plan that
was approved by the MDTE on July 27, 1999. These decreases are additionally
offset by an increase in depreciation on distribution utility plant required
under the terms of the Boston Edison settlement agreement beginning March 1,
1998.
Demand side management (DSM) and renewable energy programs expense was $57.5
million in 1999 compared to $51.8 million in 1998, an increase of $5.7 million
or 11%. In accordance with legislative and regulatory directives, these costs
are collected from customers on a fully reconciling basis.
Property and other taxes were $68.8 million in 1999 compared to $84.1 million in
1998, a decrease of $15.3 million or 18%. The decrease reflects a lower
municipal property taxes resulting from divestiture of the fossil and nuclear
generating facilities.
Income taxes from operations were $91 million in 1999 compared to $100.5 million
in 1998, a decrease of $9.5 million or 9%. This decrease reflects lower pretax
operating income in 1999.
Other income (expense), net
Other income, net of tax was $19.8 million in 1999 compared to other expense,
net of $2.9 million in 1998, a net increase in income of $22.7 million. Prior
to the consideration of tax benefits, other expenses were $2.7 million in 1999
compared to $20.8 million in 1998. BETG's equity loss in the RCN and
EnergyVision joint ventures were $9.0 million in 1998. 1999 reflects $7 million
of non-recoverable expenses related to the Pilgrim plant divestiture. 1998
reflects $23.2 million of costs related to the fossil plants divestiture and
$2.6 million of costs associated with opposition to the referendum that sought
to repeal the Massachusetts Electric Restructuring Act. These amounts are
offset by $3.8 million of interest income in 1999 compared to $7.6 million in
1998, a decrease of 3.8 million reflecting the higher level of cash on hand in
1998 as a result of the proceeds from the fossil plant divestiture. Other
miscellaneous income was $0.5 million in 1999 compared to $6.4 million in 1998.
Income tax benefits related to other income/expense was $22.5 million in 1999
and 17.9 million in 1998. The income tax benefit includes $20.8 million in 1999
and 10.9 million in 1998 related to the recognition of previously deferred
investment tax credits associated with the Pilgrim nuclear plant divested in
1999 and the fossil generating stations divested in 1998.
Interest charges
Interest on long-term debt and transition property securitization certificates
was $91.6 million in 1999 compared to $83 million in 1998, an increase of $8.6
million or 10%. The increase reflects approximately $20 million related to
securitization. This increase is partially offset by a reduction of
approximately $6 million due to the retirement of $19 million of 7.80%
debentures due March 15, 2023, $66 million, of 9.875% debentures and $91
million, of 9.375% debentures during the third quarter of 1999. The increase is
additionally offset by reductions of approximately $2 million due to the
maturity of $100 million, 5.95% debentures in March 1998 and the cessation of
amortization of the associated discounts and premiums, as well as a reduction of
approximately $3 million due to the redemption of a $100 million 6.662% bank
loan in June 1998.
13
Preferred stock dividends
Preferred stock dividends were $6 million in 1999 compared to $8.8 million in
1998, a decrease of $2.8 million or 32%. The decrease is due to the redemption
of 400,000 shares of 7.75% series cumulative preferred stock and the remaining
320,000 shares of 7.27% series in July 1998.
Retail Electric Sales and Revenues
Electric sales
Retail kWh sales increased 4.7% in 1999. The increase in retail kWh was
primarily due weather conditions that favored electric sales as well as a
continue strong local economy and an increase in the average number of
customers. The commercial sector represents approximately 50% of electric
operating revenues. The commercial sales increase reflects a 2% increase in the
Massachusetts employment rate and increased hotel occupancy in the Boston area
Total kWh sales increased 2.3% in 1998. The 2.0% increase in 1998 retail kWh
sales was primarily due to the positive impact of a continued strong local
economy on commercial customers. The commercial sector represents approximately
50% of electric operating revenues. The Boston area commercial office vacancy
rate is at a 17 year low. In addition, the Massachusetts employment rate
increased 2.8% over 1997. These positive impacts associated with the economic
conditions along with warmer than normal summer weather were partially offset by
the mild winter weather conditions in the first quarter of 1998.
Liquidity
Cash requirements for utility plant expenditures have been met in recent years
with internally generated funds. These funds are cash flows from operating
activities, adjusted to exclude changes in working capital and the payment of
dividends. During 1999, 1998 and 1997 internal generation of cash provided
298%, 111% and 211%, respectively of plant expenditures. Capital expenditures,
excluding nuclear fuel, forecasted for 2000 are $102 million. This spending
level includes the 2000 portion of business system replacements discussed below.
Capital expenditures over the next five years are forecasted to be approximately
$475 million. In addition to plant expenditures, debt and preferred stock
payment requirements are $217.5 million in 2000, $114 million in 2001, $71.8
million in 2002, $219.7 million in 2003 and $70.4 million in 2004.
Boston Edison supplements internally generated funds as needed, primarily
through the issuance of short-term commercial paper and bank borrowings.
Boston Edison has authority from the Federal Energy Regulatory Commission
(FERC) to issue up to $350 million of short-term debt. Boston Edison has a
$200 million revolving credit agreement with a group of banks that serve as back
up to Boston Edison $200 million commercial paper program. Boston Edison had no
short-term debt outstanding as of December 31, 1999.
In July 1999, BEC Funding LLC, a wholly owned special-purpose subsidiary (SPS)
of Boston Edison, closed the sale of $725 million of notes to a special purpose
trust created by two Massachusetts state agencies. The trust then concurrently
closed the sale on $725 million of electric rate reduction certificates to the
public. The certificates held by BEC Funding are secured by a portion of the
transition charge assessed to Boston Edison's retail customers as permitted
under the Massachusetts Electric Industry Restructuring Act and authorized by
the MDTE. The certificates were issued in five separate classes with variable
payment periods ranging from approximately one to ten
14
years and bearing fixed interest rates ranging from 5.99% to 7.03%. The
certificates are non-recourse to Boston Edison. Net proceeds ($719 million
received by Boston Edison from BEC Funding) were utilized to finance a portion
of the stranded costs that are being collected from customers under Boston
Edison's restructuring settlement agreement. Boston Edison will collect a
portion of the transition charge on behalf of BEC Funding and remit the proceeds
to the SPS. Boston Edison used a portion of the proceeds received from the
financing to fund a portion of the nuclear decommissioning fund transferred to
Entergy Nuclear Generating Company as part of the sale of the Pilgrim generating
station. Boston Edison used the remaining proceeds to reduce capitalization and
for general corporate purposes.
Boston Edison's goal is to maintain a capital structure that preserves an
appropriate balance between debt and equity. Management believes its equity and
capital resources are sufficient to meet its current and projected requirements.
Year 2000
NSTAR's mission critical systems and other important business systems were
considered ready for the year 2000 prior to December 31, 1999. The North
American Electric Reliability Council defined mission critical systems as those
whose mis-operation could result in loss of electric generation, transmission or
load interruption. To date, NSTAR has not experienced any significant year 2000
problems. NSTAR will continue to monitor systems in order to address any
potential continuing risk of non-compliant internal business software, internal
non-business software and embedded chip technology and external noncompliance of
third parties.
Under its year 2000 program NSTAR inventoried mission critical systems that were
date-sensitive and that used embedded technology such as micro-controllers or
microprocessors.
NSTAR also inventoried important business systems that were date-sensitive and
determined that approximately one-third of BEC's systems needed modification or
replacement. Plans were developed and implemented to correct and test all
affected systems, with priorities based on the importance of the supported
activity. As systems were remediated, they were tested for operational and year
2000 readiness in their own environment. After implementation, the systems were
then tested for their integration and compatibility with other interactive
systems.
In addition, all non-critical internal productivity systems were inventoried and
assessed as part of the year 2000 program. Approximately one-third of BEC's
systems required modification or replacement. All of these systems were
declared ready by September 30, 1999.
Costs incurred to upgrade or remediate systems have been expensed as incurred.
In addition, a decision was made to replace some of the less efficient
centralized business systems. Systems replacement costs are being capitalized
and amortized over future periods. Boston Edison has expended a total of
approximately $29 million on this project through December 31, 1999. Future
costs are expected to be immaterial.
In addition to its internal efforts, Boston Edison initiated formal
communications with their significant suppliers, service providers and other
vendors to determine the extent to which they may be vulnerable to these
parties' failure to correct their own year 2000 issues. To date, Boston Edison
has not experienced any significant year 2000 problems associated with its
reliance on third parties.
NSTAR's year 2000 program included contingency plans. If required, these plans
were intended to address both internal risks as well as potential external risks
related to vendors, customers and energy suppliers. Plans were developed in
conjunction with available national and regional guidance and were based on
system emergency plans that were developed and successfully tested over the past
15
several years. Included within its contingency plans were procedures for the
procurement of short-term power supplies and emergency distribution system
restoration procedures. In the event that a problem is to arise in 2000 (or
beyond), these contingency plans would become effective in order to remediate
the problem.
Other Matters
Environmental
Boston Edison is an owner or operator of approximately 20 properties where oil
or hazardous materials were spilled or released. As such, companies are required
to clean-up these remaining properties in accordance with a timetable developed
by the Massachusetts Department of Environmental Protection. These are
uncertainties associated with these costs due to the complexities of clean-up
technology, regulatory requirements and the particular characteristics of the
different sites. Boston Edison also continues to face possible liability as a
potentially responsible party (PRP) in the cleanup of five multi-party hazardous
waste sites in Massachusetts and other states where it is alleged to have
generated, transported or disposed of hazardous waste at the sites. Boston
Edison currently expects to have only a small percentage of the total potential
liability for these sites Through December 31, 1999, Boston Edison had
approximately $6 million accrued on its Balance Sheet related to these cleanup
liabilities. Management is unable to fully determine a range of reasonably
possible cleanup costs in excess of the accrued amount. Based on preliminary
assessments of the specific site circumstances, management does not believe that
it is probable that any such additional costs will have a material impact on
NSTAR's consolidate financial position. However, it is reasonably possible that
additional provisions for cleanup costs that may result from a change in
estimates could have a material impact on the results of a reporting period in
the near term. Uncertainties continue to exist with respect to the disposal of
both spent nuclear fuel and low-level radioactive waste resulting from the
operation of nuclear generating facilities. The United States Department of
Energy (DOE) is responsible for the ultimate disposal of spent nuclear fuel.
However, uncertainties regarding the DOE's schedule of acceptance of spent fuel
for disposal continue to exist. Under the purchase and sale agreement with
Entergy, Entergy will assume full liability and responsibility for
decommissioning and waste disposal at Pilgrim Station
Public concern continues regarding electromagnetic fields (EMF) associated with
electric transmission and distribution facilities and appliances and wiring in
buildings and homes. Such concerns have included the possibility of adverse
health effects caused by EMF as well as perceived effects on property values.
Boston Edison continues to support research into the subject and participates in
the funding of industry-sponsored studies. It is aware that public concern
regarding EMF in some cases has resulted in litigation, in opposition to
existing or proposed facilities in proceedings before regulators or in requests
for legislation or regulatory standards concerning EMF levels. It has addressed
issues relative to EMF in various legal and regulatory proceedings and in
discussions with customers and other concerned persons; however, to date it has
not been significantly affected by these developments. Boston Edison continues
to monitor all aspects of the EMF issue.
Estimates related to environmental remediation costs are reviewed and adjusted
periodically as further investigation and assignment of responsibility occurs.
Boston Edison is unable to estimate its ultimate liability for future
environmental remediation costs. However, in view of Boston Edison's current
assessment of its environmental responsibilities, existing legal requirements
and regulatory policies, management does not believe that these matters will
have a material adverse effect on Boston Edison's financial position or results
of operations for a reporting period.
16
Industry and corporate restructuring legal proceedings
The MDTE order approving the Boston Edison settlement agreement was appealed by
certain parties to the Massachusetts Supreme Judicial Court (SJC). One
settlement agreement appeal remains pending. However, there has to date been no
briefing, hearing or other action taken with respect to this proceeding.
In addition, along with other Massachusetts investor-owned utilities, Boston
Edison has been named as a defendant in a class action suit seeking to declare
certain provisions of the Massachusetts electric industry restructuring
legislation unconstitutional.
Management is currently unable to determine the outcome of these outstanding
proceedings; however, if an unfavorable outcome were to occur, there could be a
material adverse impact on business operations, the consolidated financial
position or results of operations for a reporting period.
Regulatory proceedings
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated
activities. Hearing were completed in 1999.
Management is currently unable to determine the outcome of these proceedings.
However, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim
Station, filed suit against Boston Edison. The town claimed that Boston Edison
has wrongfully failed to execute an agreement with the town for payments in
addition to taxes due to the town under the Massachusetts Electric Restructuring
Act. Boston Edison and the town settled the suit by agreeing on a 15-year $141
million property tax package in March 1999. Payments in each of the first four
years are approximately $15 million after which payments gradually decline. All
payments under this agreement will be recovered from customers through the
transition charge.
In the normal course of its business Boston Edison is also involved in certain
other legal matters. Management is unable to fully determine a range of
reasonably possible legal costs in excess of amounts accrued. Based on the
information currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.
Number of Employees
As of December 31, 1999, Boston Edison had 1,933 full-time employees including
1,341 (69%) represented by two locals of the Utility Workers Union of America,
AFL-CIO. The locals' labor contracts are effective through May 15, 2000.
Management believes it has satisfactory employee relations.
Interest rate risk
Boston Edison is exposed to changes in interest rates. Carrying amounts and fair
values of mandatory redeemable cumulative preferred stock and indebtedness
(excluding notes payable) debt as of December 31, 1999, are as follows:
17
Carrying Fair Weighted average
(in thousands) amount value interest rate
- ------------------------------------------------------------------------------
Mandatory redeemable cumulative
preferred stock $ 49,279 $ 52,250 8.00%
Indebtedness $1,476,431 $1,500,340 7.07%
New Accounting Principles
- -------------------------
In June 1998, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting
and reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts possibly including
fixed-price fuel supply and power contracts) be recorded on the Consolidated
Balance Sheets as either an asset or liability measured at its fair value, SFAS
133, as amended by SFAS 137, "Accounting for Derivative Instruments and Hedging
Activities - Deferral of the Effective Date of FASB Statement No 133", is
effective for fiscal years beginning after June 15, 2000 (January 1, 2001 for
calendar year companies). Initial application shall be as of the beginning of
an entity's fiscal quarter.
Safe harbor cautionary statement
Management occasionally makes forward-looking statements such as forecasts and
projections of expected future performance or statements of its plans and
objectives. These forward-looking statements may be contained in filings with
the Securities and Exchange Commission (SEC), press releases and oral
statements. Actual results could potentially differ materially from these
statements. Therefore, no assurances can be given that the outcomes stated in
such forward-looking statements and estimates will be achieved.
The preceding sections include certain forward-looking statements about
operating results, year 2000 and environmental and legal issues.
The impacts of continued cost control procedures on operating results could
differ from current expectations. The effects of changes in economic
conditions, tax rates, interest rates, technology and the prices and
availability of operating supplies could materially affect the projected
operating results.
The timing and total costs related to the year 2000 plan could differ from
current expectations. Factors that may cause such differences include the
ability to locate and correct all relevant computer codes and the availability
of personnel trained in this area. In addition, management cannot predict the
nature or impact on operations of third party noncompliance.
The impacts of various environmental and legal issues could differ from
current expectations. New regulations or changes to existing regulations
could impose additional operating requirements or liabilities other than
expected. The effects of changes in specific hazardous waste site conditions
and cleanup technology could affect the estimated cleanup liabilities. The
impacts of changes in available information and circumstances regarding legal
issues could affect the estimated litigation costs.
18
Item 8. Financial Statements and Supplementary Financial Information
- ---------------------------------------------------------------------
Report of Independent Accountants
To the Stockholders and Directors of Boston Edison Company:
In our opinion, the accompanying consolidated financial statements listed in
Item 14(a)(1) on page 39, present fairly, in all material respects, the
consolidated financial position of Boston Edison Company and its subsidiaries at
December 31, 1999 and 1998 and the consolidated results of their operations and
their cash flows for each of the three years in the period ended December 31,
1999 in conformity with accounting principles generally accepted in the United
States. In addition, in our opinion, the financial statement schedules listed in
the index appearing under Item 14 (a)(2) on page 39, present fairly, in all
material respects, the information set forth therein when read in conjunction
with the related consolidated financial statements. These financial statements
and financial statement schedules are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements and financial statement schedules based on our audits. We conducted
our audits of these statements and schedules in accordance with auditing
standards generally accepted in the United States, 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 the opinion expressed
above.
PricewaterhouseCoopers LLP
Boston, Massachusetts
January 26, 2000
19
Consolidated Statements of Income
years ended December 31,
(in thousands) 1999 1998 1997
- ------------------------------------------------------------------------------------
Operating revenues $1,546,817 $1,622,972 $1,778,531
- ------------------------------------------------------------------------------------
Operating expenses:
Fuel and purchased power 645,175 567,806 679,131
Operations and maintenance 271,358 373,410 423,040
Depreciation and amortization 176,705 195,610 189,489
Demand side management and
renewable energy programs 57,467 51,839 29,790
Taxes-property and other 68,826 84,091 106,428
Income taxes 91,029 100,492 93,709
- ------------------------------------------------------------------------------------
Total operating expenses 1,310,560 1,373,248 1,521,587
- ------------------------------------------------------------------------------------
Operating income 236,257 249,724 256,944
Other income (expense), net 19,803 (2,941) (6,392)
- ------------------------------------------------------------------------------------
Operating and other income 256,060 246,783 250,552
- ------------------------------------------------------------------------------------
Interest charges:
Long-term debt 71,150 82,951 92,489
Transition Property securitization
certificates 20,408 0 0
Other 6,199 8,163 14,610
Allowance for borrowed funds used
during construction (2,011) (1,668) (1,189)
- ------------------------------------------------------------------------------------
Total interest charges 95,746 89,446 105,910
- ------------------------------------------------------------------------------------
Net income $ 160,314 $ 157,337 $ 144,642
====================================================================================
Consolidated Statements of Retained Earnings
years ended December 31,
(in thousands) 1999 1998 1997
- ------------------------------------------------------------------------------------
Balance at the beginning of the year $ 297,347 $ 328,802 $ 292,191
Net income 160,314 157,337 144,642
- ------------------------------------------------------------------------------------
Subtotal 457,661 486,139 436,833
- ------------------------------------------------------------------------------------
Dividends declared:
Dividends to common shareholders 0 22,802 91,208
Dividends to BEC Energy 450,000 141,000 0
Preferred stock 5,960 8,765 13,149
Transfer of BETG to BEC Energy 0 8,392 0
- ------------------------------------------------------------------------------------
Subtotal 455,960 180,959 104,357
- ------------------------------------------------------------------------------------
Provision for preferred stock
redemption and issuance costs (a) 239 7,833 3,674
- ------------------------------------------------------------------------------------
Balance at the end of the year $ 1,462 $ 297,347 $ 328,802
====================================================================================
(a) Refer to Note A.6. to the Consolidated Financial Statements.
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.
20
Consolidated Balance Sheets
December 31,
(in thousands) 1999 1998
- ------------------------------------------------------------------------------------------
Assets
Utility plant in service, at
original cost $2,397,287 $2,720,681
Less: accumulated depreciation 848,544 $1,548,743 926,020 1,794,661
- ------------------------------------------------------------------------------------------
Construction work in progress 53,647 40,965
- ------------------------------------------------------------------------------------------
Net utility plant 1,602,390 1,835,626
Nuclear decommissioning trust 0 172,908
Equity investments 19,880 20,769
Other investments 10,939 10,029
Current assets:
Cash and cash equivalents 117,537 82,700
Restricted cash 3,625 0
Accounts receivable, net of
allowance of $18,600 and $9,066
in 1999 and 1998, respectively 322,168 206,003
Accrued unbilled revenues 16,138 14,322
Fuel, materials and supplies,
at average cost 16,226 10,287
Prepaid expenses and other 177,722 653,416 92,361 405,673
- ------------------------------------------------------------------------------------------
Deferred debits:
Regulatory assets 918,243 623,187
Other 38,133 26,423
- ------------------------------------------------------------------------------------------
Total assets $3,243,001 $3,094,615
==========================================================================================
Capitalization and Liabilities
Common equity $ 717,823 $1,039,891
Cumulative preferred stock of
subsidiary 92,279 92,040
Long-term debt 613,283 955,563
Transition property securitization
certificates 646,559 0
Current liabilities:
Long-term debt due within
one year 165,667 667
Transition property securitization
certificates due within one year 50,922 0
Accounts payable 103,640 90,890
Accrued interest 15,460 19,991
Dividends payable 993 25,993
Other 218,224 554,906 176,823 314,364
- ------------------------------------------------------------------------------------------
Deferred credits:
Accumulated deferred income taxes 484,629 348,557
Accumulated deferred investment
Tax credits 21,336 45,930
Nuclear decommissioning liability 0 176,578
Power contracts 45,123 58,415
Other 67,063 63,277
Commitments and contingencies
- ------------------------------------------------------------------------------------------
Total capitalization and liabilities $3,243,001 $3,094,615
==========================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
21
Consolidated Statements of Cash Flows
years ended December 31,
(in thousands) 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------
Operating activities:
Net income $160,314 $157,337 $144,642
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 188,078 229,668 223,529
Deferred income taxes and investment tax
credits 99,504 (152,798) (21,664)
Power contract buyout (65,781) 0 0
Allowance for borrowed funds used during
construction (2,011) (1,668) (1,189)
Net changes in:
Accounts receivable and accrued
unbilled revenues (50,736) 29,666 45,678
Fuel, materials and supplies (1,387) 29,834 (5,486)
Accounts payable (49,084) 9,834 (47,068)
Other current assets and liabilities (77,628) (25,525) 25,428
Other, net 27,828 (7,517) (4,640)
- -------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 229,097 268,831 359,230
- -------------------------------------------------------------------------------------------------------
Investing activities:
Plant expenditures (excluding AFUDC) (125,419) (117,803) (114,110)
Net cost of nuclear divestiture (87,248) 0 0
Proceeds from sale of fossil assets 533,633 0
Nuclear fuel expenditures (16,118) (26,182) (4,089)
Investments (6,301) (33,600) (27,689)
- -------------------------------------------------------------------------------------------------------
Net cash (used in) provided by investing
activities (235,086) 356,048 (145,888)
- -------------------------------------------------------------------------------------------------------
Financing activities:
Issuances:
Common stock 0 0 144
Long-term debt 725,000 0 100,000
Redemptions:
Preferred stock 0 (71,519) (44,000)
Long-term debt (203,214) (201,600) (101,600)
Net change in notes payable 0 (101,878) (64,441)
Dividends paid (480,960) (171,322) (104,956)
- -------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing
activities 40,826 (546,319) (214,853)
- -------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents 34,837 78,560 (1,511)
Cash and cash equivalents at the
beginning of the year 82,700 4,140 5,651
- -------------------------------------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $117,537 $ 82,700 $ 4,140
=======================================================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 76,926 $ 89,531 $100,795
Income taxes $ 87 $ 79,900 $ 99,326
The accompanying notes are an integral part of the consolidated financial
statements.
22
Notes to Consolidated Financial Statements
Note A. Summary of Significant Accounting Policies
1. Nature of Operations
On August 25, 1999, BEC Energy (BEC) and Commonwealth Energy System (COM/Energy)
completed a merger to create a new holding company, NSTAR, an energy delivery
company serving approximately 1.3 million customers in Massachusetts including
more than one million electric customers in 81 communities and 240,000 gas
customers in 51 communities. NSTAR also supplies electricity at wholesale for
resale to municipalities. NSTAR is an exempt public utility holding company
under the provisions of the Public Utility Holding Company Act of 1935. NSTAR's
utility subsidiaries include Boston Edison Company, Commonwealth Electric
Company, Cambridge Electric Light Company, Canal Electric Company and
Commonwealth Gas Company. NSTAR's non-utility operations include
telecommunications, district heating and cooling operations and liquefied
natural gas services.
Boston Edison currently supplies electricity at retail to an area of 590 square
miles, including the city of Boston and 39 surrounding cities and towns. Boston
Edison is focusing its operations on the transmission and distribution of
energy. This is illustrated by the sale of the Boston Edison's fossil generating
assets and the Pilgrim Nuclear Power Station.
2. Basis of Consolidation and Accounting
Under the holding company structure effective in June 1998, the owners of Boston
Edison's common stock became BEC common shareholders. All shares of BEC Energy
are owned by NSTAR. Existing debt and preferred stock of Boston Edison remained
obligations of the regulated utility business. Effective June 25, 1998, BETG
ceased being a subsidiary of Boston Edison and became a wholly owned subsidiary
of BEC. The accompanying consolidated financial statements include the results
of operations and cash flows of BETG prior to the reorganization. BETG is
excluded from the consolidated results of operations and cash flows beginning in
the third quarter of 1998. The consolidated balance sheet at December 31, 1997
reflects the financial position of Boston Edison which also included BETG. BETG
is excluded from the consolidated balance sheet at December 31, 1998. The
consolidated financial statements for each period presented include the
activities of Boston Edison's wholly owned subsidiary, Harbor Electric Energy
Company (HEEC). 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 SEC. The consolidated financial
statements conform with generally accepted accounting principles (GAAP). As a
rate-regulated company Boston Edison has been subject to Statement of Financial
Accounting Standards No. 71, Accounting for the Effects of Certain Types of
Regulation (SFAS 71), under GAAP. The application of SFAS 71 results in
differences in the timing of recognition of certain expenses from that of other
businesses and industries. As a result of the Massachusetts electric industry
restructuring legislation enacted in November 1997 and the DTE order regarding
the related Boston Edison settlement agreement, as of December 31, 1997, the
provisions of SFAS 71 are no longer being applied to the generation business.
The distribution business remains subject to rate-regulation and continues to
meet the criteria for application of SFAS 71. Refer to Note B to these
Consolidated Financial Statements for more information on the accounting
implications of the electric utility industry restructuring.
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
23
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
Estimates of retail base (transmission and distribution) revenues for
electricity used by customers but not yet billed are recorded 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 and Nuclear Fuel Amortization
Depreciation of utility plant is computed on a straight-line basis using
composite rates based on the estimated useful lives of the various classes of
property. Excluding the effect of the adjustment discussed below, the overall
composite depreciation rates were 3.31%, 3.28% and 3.30% in 1999, 1998 and 1997,
respectively.
Upon the completion of a review of Boston Edison's electric generating units,
management determined that the oldest and least efficient fossil units (Mystic
4, 5 and 6) were unlikely to provide competitively-priced power beyond the year
2000. Therefore the estimated remaining economic lives of these units was
revised to five years in 1996. These units were sold in May 1998. Refer to Note
B to these Consolidated Financial Statements.
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. AFUDC rates in 1999, 1998 and 1997 were
5.82%, 5.88% and 6.04%, respectively, and represented only the cost of short-
term debt.
8. Cash and Cash Equivalents
Cash and cash equivalents are comprised of highly liquid securities with
maturities of 90 days or less when purchased.
9. Regulatory Assets
Regulatory assets represent costs incurred which 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
24
received in order to appropriately match revenues and expenses.
Regulatory assets consisted of the following:
December 31,
1999 1998
- ---------------------------------------------------
Generation-related regulatory
assets, net $713,379 $477,317
Power contracts 45,123 58,415
Income taxes, net 65,867 52,168
Merger costs 56,666 0
Redemption premiums 16,008 23,419
Postretirement benefits costs 12,822 8,769
Other 8,378 3,099
- ---------------------------------------------------
$918,243 $623,187
===================================================
10. Related Party Transactions
The December 31, 1999 consolidated balance sheet of Boston Edison includes a $10
million receivable from NSTAR Communications, an affiliate. The receivable is
for construction and construction management services provided by Boston Edison
and its contractors. The December 31, 1999 balance sheet also includes a $67
million receivable from NSTAR. This represents Boston Edison's share of
consolidated federal income tax benefits.
11. Amortization of Goodwill and Costs to Achieve
Goodwill and costs to achieve related to the merger discussed in Note B are
being amortized over 40 years and 10 years, respectively.
Note B. Electric Utility Industry Restructuring
1. Merger of BEC Energy and Commonwealth Energy System
Shareholders of BEC and COM/Energy approved the merger on June 24, 1999. After
receiving various regulatory approvals, the SEC issued its approval of the
merger and the transaction was completed on August 24, 1999. Pursuant to the
merger agreement, BEC shareholders received approximately 41 million shares of
NSTAR, while COM/Energy shareholders received approximately 20 million shares of
NSTAR. In addition, BEC and COM/Energy shareholders received an aggregate amount
of cash of approximately $300 million. An initial quarterly dividend rate of
48.5 cents per share of NSTAR was declared by the board of trustees on September
23, 1999 and paid on November 1, 1999. This dividend rate is reviewed on a
regular basis and on December 16, 1999 a quarterly dividend of 50 cents per
share was declared.
The merger of BEC and COM/Energy has been accounted for as an acquisition of
COM/Energy by BEC using the purchase method of accounting. Under this method,
the accompanying consolidated financial statements of NSTAR include the results
of BEC for years ended December 31, 1999 and 1998 consolidated with those of
COM/Energy from the date of the merger (August 25, 1999). Goodwill amounted to
approximately $486 million while the original estimate of costs to achieve the
merger was $111 million. Goodwill is being amortized over 40 years and will
amount to approximately $12.2 million annually while the cost to achieve is
being amortized over 10 years and will initially be approximately $11.1 million
annually. The ultimate amortization of the cost to achieve will reflect the
total actual costs.
2. Accounting Implications
Under the traditional revenue requirements model, electric rates have been based
on the cost of providing electric service. Under this model, Boston Edison has
been subject to certain accounting standards that are not applicable to other
businesses and industries in general. The application of SFAS 71 requires
companies to defer the recognition of certain costs when incurred if future rate
recovery of these costs is expected. As a result of the Massachusetts Electric
Restructuring Act enacted in November 1997 and the MDTE order regarding Boston
Edison's related settlement agreement, as of December 31, 1997, the provisions
of SFAS 71 are no longer being applied to the generation business.
The implementation of the Boston Edison settlement agreement had certain
accounting implications. The highlights of these include:
Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation business, except for
those related to Pilgrim's wholesale contracts, are recovered through the
transition charge. This recovery, which includes a return, will occur over a
twelve-year period that began on March 1, 1998 (the retail access date).
25
Depreciation
The composite depreciation rate for distribution utility plant increased from
2.88% to 2.98% as of the retail access date.
Fuel and purchased power charge
The fuel and purchased power charge ceased as of the retail access date. The net
remaining over collection of fuel and purchased power costs will be reflected in
future customer billings. These over-recovered costs are included as an offset
to the settlement recovery mechanisms which is included in regulatory assets on
the accompanying Consolidated Balance Sheet.
Standard offer charge
Customers who were on Boston Edison's system at March 1, 1998, have the option
of continuing to buy power from the retail electric delivery business at
standard offer prices as of the retail access date. The standard offer charge
began at 2.8 cents/kWh at the retail access date, increased to 3.2 cents/kWh on
June 1, 1998, to 3.69 cents/kWh on January 1, 1999 and is scheduled to increase
to 5.1 cents/kWh by 2004. The cost of providing standard offer service, which
includes fuel and purchased power costs, is recovered from standard offer
customers on a fully reconciling basis.
Distribution and transmission charges
Distribution rates are subject to a minimum and maximum return on average common
equity (ROE) through December 31, 2000. The ROE is subject to a floor of 6% and
a ceiling of 11.75%. If the ROE is below 6%, Boston Edison is authorized to add
a surcharge to distribution rates in order to achieve the 6% floor. If the ROE
is above 11%, it is required to adjust distribution rates by an amount necessary
to reduce the calculated ROE between 11% and 12.5% by 50%, and a return above
12.5% by 100%. No adjustment is made if the ROE is between 6% and 11%. In
addition, distribution rates will be adjusted for any changes in tax laws or
accounting principles that result in a change in costs of more than $1 million.
The cost of providing transmission service to distribution customers is
recovered on a fully reconciling basis.
Generating Assets Divestiture
On July 13,1999, Boston Edison completed the sale of the Pilgrim Nuclear
Generating Station to Entergy Nuclear Generating Company, a subsidiary of
Entergy Corporation, for $81 Million. In addition to the amount received from
the buyer, Boston Edison has received a total of approximately $158 million from
the Pilgrim contract customers, including $103 million from Commonwealth
Electric Company, to terminate their contract. Approximately $80 Million remains
to be collected under these termination agreements. As part of the sale, Boston
Edison transferred its decommissioning trust fund to Entergy for decommissioning
of the plant. 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 results of a favorable IRS tax ruling, Boston Edison
received $43 million from Entergy reflecting a reduction in the required
decommissioning funding. The difference between the total proceeds received and
the net book value of the Pilgrim assets sold plus the net amount to fully fund
the decommissioning trust is included in the balance of generation-related
regulatory assets, net on the accompanying Consolidated Balance Sheets as such
amounts are being collected from customers under Boston Edison's settlement
agreement. The final amounts to be collected from customers related to Pilgrim
are subject to regulatory review.
Completion of the sale of Boston Edison's fossil generating assets took place in
May 1998. Boston Edison received proceeds from the sale of $674 million,
including $121 million for a six-month transitional power purchase contract. The
amount received above net book value on the sale of these assets is being
returned to Boston Edison's customers over the settlement period.
26
On July 27, 1999 BEC Funding LLC, a subsidiary of NSTAR, closed the sale of $725
million of notes to a special purpose trust created by two Massachusetts state
agencies. The trust then concurrently closed the sale of $725 million of
electric rate reduction certificates to the public. The certificates are secured
by a portion of the transition charge assessed on Boston Edison's retail
customers as permitted under the Massachusetts Electric Restructuring Act and
authorized by the MDTE. These certificates are non-recourse to Boston Edison.
Note C. Income Taxes
Income taxes are accounted for in accordance with Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109
requires the recognition of deferred tax assets and liabilities for the future
tax effects of temporary differences between the carrying amounts and the tax
basis of assets and liabilities. In accordance with SFAS 109, net regulatory
assets of $65.9 million and $52.2 million and corresponding net increases in
accumulated deferred income taxes were recorded as of December 31, 1999 and
1998, respectively. The regulatory assets represent the additional future
revenues to be collected from customers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
December 31,
(in thousands) 1999 1998
- --------------------------------------------------------------
Deferred tax liabilities:
Plant-related $336,835 $412,358
Other 311,153 85,497
- --------------------------------------------------------------
647,988 497,855
- --------------------------------------------------------------
Deferred tax assets:
Plant-related 14,218 13,174
Investment tax credits 13,490 29,622
Other 135,651 106,502
- --------------------------------------------------------------
163,359 149,298
- --------------------------------------------------------------
Net accumulated deferred income taxes $484,629 $348,557
==============================================================
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) 1999 1998 1997
- ------------------------------------------------------------------------------------
Current income tax expense (benefit) $ (29,306) $ 242,411 $ 115,373
Deferred income tax expense 122,584 (137,992) (14,104)
Investment tax credit amortization (2,249) (3,927) (7,560)
- ------------------------------------------------------------------------------------
Income taxes charged to operations 91,029 100,492 93,709
- ------------------------------------------------------------------------------------
Taxes on other income (22,465) (17,853) (11,254)
- ------------------------------------------------------------------------------------
Total income tax expense $ 68,564 $ 82,639 $ 82,455
====================================================================================
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:
1999 1998 1997
- ------------------------------------------------------------------------------------------------
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 4.3 4.6 4.5
Investment tax credit amortization (10.1) (6.2) (3.3)
Other 0.8 1.0 0.1
- -----------------------------------------------------------------------------------------------
Effective tax rate 30.0% 34.4% 36.3%
===============================================================================================
27
Income tax expense is reflected net of $20.8 million in 1999 and $10.9 million
in 1998 of investment tax credits recognized as a result generation
divestitures. Excluding these shareholders benefits, the effective tax rate
would have been approximately 39% in each year.
Note D. Pensions and Other Postretirement Benefits
1. Pensions
The changes in the benefit obligation and plan assets were as follows:
December 31,
(in thousands) 1999 1998
- -------------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation, beginning of the year $497,988 $457,436
Service cost 13,137 13,645
Interest cost 31,658 31,981
Plan participants' contributions 170 214
Plan amendments (4,306) -
Actuarial (gain)/loss (51,648) 67,564
Curtailment loss/(gain) 8,156 (15,644)
Special termination benefits 8,158 665
Settlement payments (92,484) (16,246)
Benefits paid (18,922) (41,627)
- -------------------------------------------------------------------------------------------------------
Benefit obligation, end of the year $391,907 $497,988
=======================================================================================================
Change in plan assets:
Fair value of plan assets, beginning of the year $474,552 $401,182
Actual return on plan assets 114,724 44,589
Employer contribution 58,176 86,440
Plan participants' contributions 170 214
Settlement payments (92,484) (16,246)
Benefits paid (18,922) (41,627)
- -------------------------------------------------------------------------------------------------------
Fair value of plan assets, end of the year $536,216 $474,552
=======================================================================================================
The plans' funded status were as follows:
December 31,
(in thousands) 1999 1998
- ---------------------------------------------------------------------------------------
Funded status $ 144,309 $(23,436)
Unrecognized actuarial net (gain)/loss (32,465) 96,310
Unrecognized transition obligation 2,783 3,856
Unrecognized prior service cost 8,651 15,557
- --------------------------------------------------------------------------------------
Net amount recognized $ 123,278 $ 92,287
======================================================================================
Amount recognized in the Consolidated Balance Sheets consisted of:
Prepaid retirement cost $ 125,664 $ 94,049
Accrued supplemental retirement liability (8,072) (9,856)
Intangible asset 5,686 8,094
- ---------------------------------------------------------------------------------------------------
Net amount recognized $ 123,278 $ 92,287
===================================================================================================
The projected benefit obligation, accumulated benefit obligation and fair value
of plan assets for the supplemental retirement plan with accumulated benefit
obligations in excess of plan assets were $10,325,000, $8,072,000 and $0,
respectively, as of December 31, 1999, and $11,387,000, $9,856,000 and $0,
28
respectively, as of December 31, 1998.
Weighted average assumptions were as follows:
1999 1998 1997
- -------------------------------------------------------------------------------------------
Discount rate at the end of the year 8.00% 6.50% 7.25%
Expected return on plan assets for the year
(net of investment expenses) 9.00% 9.00% 9.00%
Rate of compensation increase at the end of
the year 4.00% 4.00% 4.25%
Components of net periodic benefit cost were as follows:
years ended December 31,
(in thousands) 1999 1998 1997
- ----------------------------------------------------------------------------------------------
Service cost $ 13,137 $ 13,645 $ 12,625
Interest cost 31,658 31,981 31,537
Expected return on plan assets (41,295) (39,140) (31,250)
Amortization of prior service cost 1,610 1,847 1,827
Amortization of transition obligation 664 860 934
Recognized actuarial loss 3,594 808 1,799
- ----------------------------------------------------------------------------------------------
Net periodic benefit cost $ 9,368 $ 10,001 $ 17,472
==============================================================================================
Primarily as a result of the merger-related separation packages and nuclear
divestiture, amounts recognized for curtailment, settlement and special
termination benefit cots were $9,555,000, $930,000 and $8,158,000, respectively,
for 1999. As a result of the nuclear divestiture, amounts recognized for
curtailment and special termination benefit coasts were $2,705,000 and $665,000
respectively for 1998. The amounts resulting from the merger-related separation
packages are recoverable as part of the approved rate plans of the retail
utility subsidiaries of NSTAR. The amounts resulting from the nuclear
divestiture are recoverable under the Boston Edison settlement agreement.
Boston Edison also provided defined contribution 401(k) plans for substantially
all employees. Matching contributions included in the Consolidated Statements of
Income amounted to $8 million in 1999, 1998 and 1997, respectively.
29
2. Other Postretirement Benefits
The changes in the benefit obligation and plan assets were as follows:
December 31,
(in thousands) 1999 1998
- -------------------------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation, beginning of the year $258,756 $ 237,616
Service cost 4,043 3,892
Interest cost 17,848 16,895
Plan participants' contributions 0 1,178
Plan amendments (12,271) 0
Actuarial (gain)/loss (26,154) 27,845
Curtailment loss/(gain) 1,408 (14,665)
Special termination benefits 0 75
Settlement payments (5,810) 0
Benefits paid (16,405) (14,080)
- -------------------------------------------------------------------------------------------------
Benefit obligation, end of the year $221,415 $ 258,756
=================================================================================================
Change in plan assets:
Fair value of plan assets, beginning of the year $113,818 $ 103,989
Actual return on plan assets 18,355 14,344
Employer contribution 9,880 8,387
Plan participants' contributions 0 1,178
Settlement payments (5,810) 0
Benefits paid (16,405) (14,080)
- -------------------------------------------------------------------------------------------------
Fair value of plan assets, end of the year $119,838 $ 113,818
=================================================================================================
The plan's funded status and amount recognized in the
Consolidated Balance Sheets were as follows:
December 31,
(in thousands) 1999 1998
- ---------------------------------------------------------------------------------------------------
Funded status $(101,577) $(144,938)
Unrecognized actuarial net (gain)/loss (8,732) 24,922
Unrecognized transition obligation 73,016 88,814
Unrecognized prior service cost (20,363) (9,827)
- ---------------------------------------------------------------------------------------------------
Net amount recognized $ (57,656) $ (41,029)
===================================================================================================
Weighted average assumptions were as follows:
1999 1998 1997
- ---------------------------------------------------------------------------------------------------------------
Discount rate at the end of the year 8.00% 6.50% 7.25%
Expected return on plan assets for the year 9.00% 9.00% 9.00%
For measurement purposes a 7.75% weighted annual rate of increase in per capita
cost of covered medical claims was assumed for 2000. This rate is assumed to
decrease gradually to 4.75% in 2010 and remain at that level thereafter. Dental
claims and Medicare premiums are assumed to increase at a weighted annual rate
of 4.5% and 3.1%, respectively.
30
A 1% change in the assumed health care cost trend rate would have the following
effects:
One-Percentage-Point
(in thousands) Increase Decrease
-------- --------
Effect on total of service and interest cost
components for 1999 $ 3,060 $ (2,478)
Effect on December 31, 1999 postretirement benefit
obligation $24,902 $(24,021)
Components of net periodic benefit cost were as follows:
years ended December 31,
(in thousands) 1999 1998 1997
- ------------------------------------------------------------------------------------------
Service cost $ 4,043 $ 3,892 $ 3,543
Interest cost 17,848 16,895 17,006
Expected return on plan assets (10,107) (8,563) (6,421)
Amortization of prior service cost (683) (942) (1,017)
Amortization of transition obligation 6,162 8,474 9,151
Recognized actuarial loss 957 662 1,003
- ------------------------------------------------------------------------------------------
Net periodic benefit cost $ 18,220 $20,418 $ 23,265
==========================================================================================
As a result of the merger-related separation packages and nuclear divestiture,
amounts recognized for curtailment and settlement costs were $8,114,000 and
$172,000, respectively, for 1999. As a result of the nuclear divestiture,
amounts recognized for curtailment and special termination benefit costs were
$21,187,000 and $79,000, respectively, for 1998. The amounts resulting from the
merger-related separation packages are recoverable as part of the approved rate
plans of the retail utility subsidiaries of NSTAR. The amounts resulting from
the nuclear divestiture are recoverable under the Boston Edison settlement
agreement.
Note E. Capital Stock
December 31,
(dollars in thousands, except per share amounts) 1999 1998
- --------------------------------------------------------------------------
Common equity:
Common stock, par value $1 per share,
100,000,000 shares authorized; 100
shares issued and outstanding: $ - $ -
Premium on common stock 716,361 742,544
Retained earnings 1,462 297,347
- --------------------------------------------------------------------------
Total common equity $717,823 $1,039,891
==========================================================================
Upon the formation of the holding company in 1998, outstanding shares of
Boston Edison Company were converted into shares of BEC Energy. In addition,
100 shares of Boston Edison Company common stock were issued to BEC Energy as
part of this transaction.
The 1999 fourth quarter dividend paid to NSTAR constituted a return of capital
resulting in a reduction of premium on common stock of $25 million.
31
Cumulative preferred stock:
Par value $100 per share, 2,890,000 shares
authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
- ----------------------------------------------------------------------------------------------------------------
4.25% 180,000 $103.625 $18,000 $18,000
4.78% 250,000 $102.800 25,000 25,000
- ----------------------------------------------------------------------------------------------------------------
Total nonmandatory redeemable series $43,000 $43,000
================================================================================================================
Mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
- ----------------------------------------------------------------------------------------------------------------
8.00% 500,000 - 50,000 50,000
Less: redemption and issuance costs (721) (960)
- ----------------------------------------------------------------------------------------------------------------
Total mandatory redeemable series $49,279 $49,040
================================================================================================================
Cumulative Mandatory Redeemable Preferred Stock
Boston Edison redeemed the remaining 360,000 shares of 7.27% sinking fund
series cumulative preferred stock during 1998. The stock was subject to a
mandatory sinking fund requirement of 20,000 shares each May at par plus
accrued dividends. During 1998 and 1997 40,000 shares were redeemed. In
addition, 320,000 shares were redeemed in 1998 at $101.94 per share.
Boston Edison is not able to redeem any part of the 500,000 shares of 8%
series cumulative preferred stock prior to December 2001. The entire series
is subject to mandatory redemption in December 2001 at $100 per share plus
accrued dividends.
32
Note F. Indebtedness
December 31,
(in thousands) 1999 1998
- -------------------------------------------------------------------------------
Long-term debt:
Debentures:
6.800%, due February 2000 65,000 65,000
6.050%, due August 2000 100,000 100,000
6.800%, due March 2003 150,000 150,000
7.800%, due May 2010 125,000 125,000
9.875%, due June 2020 34,035 100,000
9.375%, due August 2021 24,270 115,000
8.250%, due September 2022 60,000 60,000
7.800%, due March 2023 181,000 200,000
Sewage facility revenue bonds 24,645 26,230
Massachusetts Industrial Finance Agency (MIFA) bonds:
5.75%, due February 2014 15,000 15,000
Transition Property Securitization Certificates:
5.99%, due March 2003 80,981 0
6.45%, due September 2005 170,610 0
6.62%, due March 2007 103,390 0
6.91%, due September 2009 170,876 0
7.03%, due March 2012 171,624 0
- -------------------------------------------------------------------------------
1,476,431 956,230
Amounts due within one year (216,589) (667)
- -------------------------------------------------------------------------------
Total long-term debt $1,259,842 $955,563
- -------------------------------------------------------------------------------
1. Long-term Debt
The 9.875% debentures due 2020 are first redeemable in June 2000 at a
redemption price of 104.483%, the 9.375% series due 2021 are first redeemable
in August 2001 at 104.612%, the 8.25% series due 2022 are first redeemable in
September 2002 at 103.780% and the 7.80% series due 2023 are first redeemable
in March 2003 at 103.730%. No other series are redeemable prior to maturity.
There is no sinking fund requirement for any series of debentures.
Sewage facility revenue bonds were issued by HEEC. The bonds are tax-exempt,
subject to annual mandatory sinking fund redemption requirements and mature
through 2015. Scheduled redemptions of $1.6 million were made in 1999, 1998
and 1997. The weighted average interest rate of the bonds is 7.3%. A portion
of the proceeds from the bonds is in reserve with the trustee. If HEEC should
have insufficient funds to pay for extraordinary expenses, 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 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.
The aggregate principal amounts of Boston Edison's long-term debt (including
HEEC sinking fund requirements) due through 2004 are $166.6 million in 2000,
$1.6 million in 2001 and 2002, $151.6 million in 2003 and $1.65 million in 2004.
In 1999, BEC Funding LLC, a wholly owned subsidiary of Boston Edison, issued
notes in the principle amount of $725 million to the Trust in exchange for the
net proceeds from the sale of $725 million of Rate Reduction certificates issued
by the Trust on July 29, 1999.
2. Short-term Debt
Boston Edison currently has regulatory authority to issue up to $350 million
of short-term debt. Boston Edison has a $200 million revolving credit
agreement with a group of banks. This agreement is intended to provide a
33
standby source of short-term borrowings. Under the terms of this agreement
Boston Edison is required to maintain a common equity ratio of not less than
30% at all times. Commitment fees must be paid on the unused portion of the
total agreement amount. It also has arrangements with several banks to
Information regarding consolidated short-term borrowings is as follows:
(dollars in thousands) 1999 1998 1997
- ---------------------------------------------------------------------------
Maximum short-term borrowings $221,000 $219,000 $316,100
Weighted average amount outstanding $ 2,860 $ 51,483 $212,663
Weighted average interest rates excluding
commitment fees 5.20% 5.81% 5.85%
- ---------------------------------------------------------------------------
Note G. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of
each class of securities for which it is practicable to estimate the value:
Cash and cash equivalents:
The carrying amount of $118 million approximates fair value due to the
short-term nature of these securities.
Mandatory redeemable cumulative preferred stock
The fair values of these securities are based upon the quoted market prices of
similar issues. Carrying amounts and fair values as of December 31, 1999, are
as follows:
Carrying Fair
(in thousands) Amount Value
- ------------------------------------------------------------------------------------
Mandatory redeemable cumulative preferred stock $ 49,279 $ 52,250
Long-term unsecured debt $1,476,431 $1,500,340
- ------------------------------------------------------------------------------------
Note H. Segment and Related Information
Statement of Financial Accounting Standards No. 131, Disclosures about
Segments of an Enterprise and Related Information, requires the disclosure of
certain financial and descriptive information by operating segments. Boston
Edison operates primarily as a regulated electric public utility for which
separate segment information is not applicable.
Note I. Commitments and Contingencies
1. Contractual Commitments
At December 31, 1999, Boston Edison had estimated contractual obligations for
plant and equipment of approximately $102 million.
Boston Edison also has leases for certain facilities and equipment. The
estimated minimum rental commitments under both transmission agreements and
noncancellable leases for the years after 1999 are as follows:
(in thousands)
- ------------------------------------------------------
2000 18,119
2001 16,814
2002 15,151
2003 12,288
2004 11,566
Years thereafter 84,172
- ------------------------------------------------------
Total $158,110
======================================================
34
The total of future minimum rental income to be received under noncancellable
subleases related to the above leases is $5,729.
The total expense for both lease rentals and transmission agreements was $38.7
million in 1999, $29.4 million in 1998 and $27.5 million in 1997, net of
capitalized expenses of $1.5 million in 1999, $1.3 million in 1998 and $1.2
million in 1997.
Boston Edison had previously entered into various take or pay and throughput
agreements, primarily to supply the New Boston fossil generating station with
natural gas. As part of the fossil divestiture agreement, Sithe Energies
assumed these obligations. The total expense under these agreements was $47.1
million in 1997.
2. Electric Company Investments
Boston Edison has an approximately 11% equity investment in two companies
which own and operate transmission facilities to import electricity from the
Hydro-Quebec system in Canada. As an equity participant Boston Edison is
required to guarantee, in addition to its own share, the total obligations of
those participants who do not meet certain credit criteria. At December 31,
1999, Boston Edison's portion of these guarantees was $15.2 million.
Boston Edison has a 9.5% equity investment of approximately $2 million in
Yankee Atomic Electric Company (Yankee Atomic). In 1992 the board of
directors of Yankee Atomic voted to discontinue operations of the Yankee
Atomic nuclear generating station permanently and decommission the facility.
Yankee Atomic received approval from the FERC to continue to collect its
investment and decommissioning costs through 2000, the period of the plant's
operating license. The estimate of Boston Edison's share of Yankee Atomic's
investment and costs of decommissioning is approximately $3 million as of
December 31, 1999. This estimate is recorded on the accompanying Consolidated
Balance Sheet as a power contract liability and an offsetting regulatory asset.
Boston Edison also has a 9.5% equity investment in Connecticut Yankee Atomic
Power Company (CYAPC) of approximately $10 million. In December 1996, the
board of directors of CYAPC, which owns and operates the Connecticut Yankee
nuclear electric generating unit (Connecticut Yankee), unanimously voted to
retire the unit.
Boston Edison's share of Connecticut Yankee's remaining investment and
estimated costs of decommissioning is approximately $42 million as of
December 31, 1999. This estimate is recorded on the accompanying Consolidated
Balance Sheet as a power contract liability and an offsetting regulatory asset
similar to Yankee Atomic.
In December 1996, CYAPC filed for rate relief at the FERC seeking to recover
certain post-operating costs, including decommissioning. In August 1998, the
FERC Administrative Law Judge (ALJ) released an initial decision regarding
CYAPC's filing. This decision called for the disallowance of the common
equity return on the CYAPC investment subsequent to the shutdown. The
decision also stated that decommissioning collections should continue to be
based on a previously approved estimate, with an adjustment for inflation,
until a more reliable estimate is developed. In October 1998, both CYAPC and
Northeast Utilities, a 49% equity investor in CYAPC, filed briefs on exceptions
to the ALJ decision. The case is still pending before the FERC. If the initial
decision is upheld by the FERC, CYAPC could be required to write off a portion
of its investment in the generating unit and refund a portion of the previously
collected return on investment to rate payers. Management is currently unable to
determine the ultimate outcome of this proceeding. However, the estimate of the
effect of the ALJ's initial decision
35
does not have a material impact on its consolidated financial position or
results of operations.
4. Hazardous Waste
Boston Edison is an owner or operator of approximately 20 properties where oil
or hazardous materials were previously spilled or released. As such, Boston
Edison is required to clean up these remaining properties in accordance with a
timetable developed by the Massachusetts Department of Environmental Protection.
There are uncertainties associated with these costs due to the complexities of
cleanup technology, regulatory requirements and the particular characteristics
of the different sites. Boston Edison also faces possible liability as a
potentially responsible party in the cleanup of five multi-party hazardous waste
sites in Massachusetts and other states where it is alleged to have generated,
transported or disposed of hazardous waste at the sites. Boston Edison is one
of many potentially responsible parties and currently expects to have only a
small percentage of the total potential liability for these sites.
Approximately $6 million is included in the December 31, 1999 Consolidated
Balance Sheet related to these cleanup liabilities. Management is unable to
fully determine a range of reasonably possible cleanup costs in excess of the
accrued amount. Based on its assessments of the specific site circumstances, it
does not believe that it is probable that any such additional costs will have a
material impact on its consolidated financial position. However, it is
reasonably possible that additional provisions for cleanup costs that may result
from a change in estimates could have a material impact on the results of a
reporting period in the near term.
5. Generating Unit Performance Program
Boston Edison's generating unit performance program ceased March 1, 1998.
Under this program the recovery of incremental purchased power costs resulting
from generating unit outages occurring through the retail access date is
subject to review by the DTE. However, proceedings relative to generating unit
performance remain pending before the DTE. These proceedings will include the
review of replacement power costs associated with the shutdown of the
Connecticut Yankee nuclear electric generating unit which is discussed in
item 2. Management is unable to fully determine a range of reasonably
possible disallowance costs in excess of amounts accrued. Based on its
assessment of the information currently available, management does not believe
that it is probable that any such additional costs will have a material impact
on its consolidated financial position. However, it is reasonably possible that
additional disallowance costs that may result from a change in estimates could
have a material impact on the results of a reporting period in the near term.
6. Legal Proceedings
Industry and corporate restructuring legal proceedings
The MDTE order approving the Boston Edison settlement restructuring agreement
was appealed by certain parties to the Massachusetts Supreme Judicial Court
(SJC). One settlement agreement appeal remains pending; however, there has to
date been no briefing, hearing or other action taken with respect to this
proceeding.
In addition, along with other Massachusetts investor-owned utilities, Boston
Edison has been named as a defendant in a class action suit seeking to declare
certain provisions of the Massachusetts electric industry restructuring
legislation unconstitutional.
Management is currently unable to determine the outcome of is proceeding.
However, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.
36
Regulatory proceedings
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order which permitted the formation of BETG and
authorized Boston Edison to invest up to $45 million in unregulated activities.
Hearings were completed in the first half of 1999.
Management is currently unable to determine the outcome of these proceedings.
However, if an unfavorable outcome were to occur, there could be a material
adverse impact on business operations, the consolidated financial position or
results of operations for a reporting period.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of Pilgrim
Station, filed suit against Boston Edison. The town claims that Boston Edison
has wrongfully failed to execute an agreement with the town for payments in
addition to taxes due to the town under the Massachusetts Electric Restructuring
Act. Boston Edison and the town settled the suit and agreed on a 15-year $141
million property tax package in March 1999. Payments in each of the first four
years are approximately $15 million after which payments gradually decline. All
payments under this agreement will be recovered from customers through the
transition charge.
In the normal course of its business Boston Edison is also involved in certain
other legal matters. Management is unable to fully determine a range of
reasonably possible legal costs in excess of amounts accrued. Based on the
information currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.
Note K. Long-Term Power Contracts
1. Long-Term Contracts for the Purchase of Electricity
Boston Edison entered into a six-month agreement effective January 1, 2000 to
transfer all of the unit output entitlements in long-term power purchase
contracts to Select Energy (Select), a subsidiary of Northeast Utilities, Inc.
In return, Select will provide full energy service requirements to Boston
Edison, including NEPOOL capability responsibilities, at FERC approved tariff
rates through June 30, 2000.
Information relating to the contracts as of December 31, 1999 is as follows:
proportionate share (in thousands)
-----------------------------------
Units of Capacity Charge
Contract Capacity 1999 Obligation
Expiration Purchased Capacity Through 1999
-----------
Generating Unit Date % MW Cost Expiration Date Cost
- -------------------------------------------------------------------------------------------
Canal Unit 1 2002 25.0 141 $ 9,523 $ 26,891 $ 27,757
Mass. Bay Trans-
portation
Authority - 1 2005 100.0 34 674 - 4,039 999
Ocean State Power -
Unit 1 2010 23.5 72 15,637 211,511 19,015
Ocean State Power -
Unit 2 2011 23.5 72 15,803 223,602 19,255
Northeast Energy
Associates (a) (a) 219 - - 126,472
Enetergy (Pilgrim) 2004 78.0 673 (b) (b) 69,407
MassPower 2013 44.3 117 39,806 710,696 51,943
Mass. Bay Transportation
Authority - 2 2019 100.0 34 355 41,732 687
- -------------------------------------------------------------------------------------------
Total $ 81,798 $1,218,471 $ 315,535
===========================================================================================
37
(a) Boston Edison purchases 75.5% of the energy output of this unit under two
contracts. One contract represents 135MW and expires in the year 2015. The
other contract is for 84MW and expires in 2010. Energy is paid for based on
a price per kWh actually received. Boston Edison does not pay a
proportionate share of the unit's capital and fixed operating costs.
(b) Boston Edison pays for this energy based on a price per kWh Actually
received. Boston Edison does not pay a proportionate share of the units
capital and fixed operating costs.
Boston Edison's total fixed and variable costs associated with these contracts
in 1999, 1998 and 1997 were approximately $315 million, $239 million and $265
million, respectively. Boston Edison's minimum fixed payments under these
contracts for the years after 1999 are as follows:
(in thousands)
- ------------------------------------------------------
1999 $ 87,430
2000 91,336
2001 90,654
2002 85,342
2003 85,117
Years thereafter 778,602
- ------------------------------------------------------
Total $1,218,481
======================================================
Item 9. Changes in and Disagreements with Accountants on Accounting and
- ------------------------------------------------------------------------
Financial Disclosure
- --------------------
Not applicable.
38
Part IV
-------
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
- -------------------------------------------------------------------------
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements:
Page
----
Consolidated Statements of Income for the years ended
December 31, 1999, 1998 and 1997 20
Consolidated Statements of Retained Earnings for the
years ended December 31, 1999, 1998 and 1997 20
Consolidated Balance Sheets as of December 31, 1999 and 1998 21
Consolidated Statements of Cash Flows for the years
ended December 31, 1999, 1998 and 1997 22
Notes to Consolidated Financial Statements 23
Report of Independent Accountants 19
2. Financial Statement Schedules:
Schedule II Valuation and Qualifying Accounts -
Years Ended December 31, 1999, 1998 and 1997. 46
3. Exhibits:
Refer to the exhibits listing beginning on the following page.
(b) Reports on Form 8-K
None
39
Exhibit SEC Docket
------- ----------
Exhibit 3 Articles of Incorporation and By-Laws
- --------- -------------------------------------
Incorporated herein by reference:
3.1 Restated Articles of Organization 3.1 1-2301
Form 10-Q
for the
quarter ended
June 30, 1994
3.2 Boston Edison Company Bylaws 3.1 1-2301
April 19, 1977, as amended Form 10-Q
January 22, 1987, January 28, 1988, for the
May 24, 1988 and November 22, 1989 quarter ended
June 30, 1990
Exhibit 4 Instruments Defining the Rights of
- --------- ----------------------------------
Security Holders, Including Indentures
--------------------------------------
Incorporated herein by reference:
4.1 Medium-Term Notes Series A - Indenture 4.1 1-2301
dated September 1, 1988, between Form 10-Q
Boston Edison Company and Bank of for the
Montreal Trust Company quarter ended
September 30,
1988
4.1.1 First Supplemental Indenture 4.1 1-2301
dated June 1, 1990 to Form 8-K
Indenture dated September 1, 1988 dated
with Bank of Montreal Trust Company - June 28, 1990
9 7/8% debentures due June 1, 2020
4.1.2 Indenture of Trust and Agreement among 4.1.26 1-2301
the City of Boston, Massachusetts Form 10-K
(acting by and through its Industrial for the
Development Financing Authority) and year ended
Harbor Electric Energy Company and December 31,
Shawmut Bank, N.A., as Trustee, dated 1991
November 1, 1991
4.1.3 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 5, 1991 re for the
9 3/8% debentures due August 15, 2021 year ended
December 31,
1991
40
Exhibit SEC Docket
------- ----------
4.1.4 Revolving Credit Agreement dated 4.1.24 1-2301
February 12, 1993 Form 10-K
for the
year ended
December 31,
1992
4.1.4.1 First Amendment to Revolving Credit 4.1.10 1-2301
Agreement dated May 19, 1995 Form 10-K
for the
year ended
December 31,
1995
4.1.4.2 Second Amendment to Revolving Credit 4.1.4.2 1-2301
Agreement dated July 1, 1997 Form 10-K
for the
year ended
December 31,
1997
4.1.5 Votes of the Pricing Committee of the 4.1.25 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken September 10, 1992 re for the
8 1/4% debentures due September 15, 2022 year ended
December 31,
1992
4.1.6 Votes of the Pricing Committee of the 4.1.26 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken January 27, 1993 re for the
6.80% debentures due February 1, 2000 year ended
December 31,
1992
4.1.7 Votes of the Pricing Committee of the 4.1.27 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken March 5,1993 re for the
6.80% debentures due March 15, 2003, year ended
7.80% debentures due March 15, 2023 December 31,
1992
4.1.8 Votes of the Pricing Committee of the 4.1.28 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken August 18, 1993 re for the
6.05% debentures due August 15, 2000 year ended
December 31,
1993
41
Exhibit SEC Docket
------- ----------
4.1.9 Votes of the Pricing Committee of the 4.1.9 1-2301
Board of Directors of Boston Edison Form 10-K
Company taken May 10, 1995 re for the
7.80% debentures due May 15, 2010 year ended
December 31,
1995
Management agrees to furnish to the Securities and Exchange Commission, upon
request, a copy of any agreements or instruments defining the rights of holders
of any long-term debt whose authorization does not exceed 10% of total assets.
Exhibit SEC Docket
------- ----------
Exhibit 10 Material Contracts
- ---------- ------------------
Incorporated herein by reference:
10.1 Key Executive Benefit Plan 10.3.1 1-2301
Standard Form of Agreement, May Form 10-K
1986, with modifications for the
year ended
December 31,
1991
10.2 Executive Annual Incentive 10.5 1-2301
Compensation Plan Form 10-K
for the
year ended
December 31,
1988
10.2.1 Supplemental Executive Retirement 10.1 1-2301
Plan Form 10-Q
for the
quarter ended
June 30, 1997
10.2.2 1997 Stock Incentive Plan 10.2 1-2301
Form 10-Q
for the
quarter ended
June 30, 1997
42
Exhibit SEC Docket
------- ----------
10.3 Boston Edison Company Deferred 10.11 1-2301
Fee Plan dated January 14, 1993 Form 10-K
for the
year ended
December 31,
1992
10.4 Deferred Compensation Trust 10.10 1-2301
between Boston Edison Company Form 10-K
and State Street Bank and for the
Trust Company dated year ended
February 2, 1993 December 31,
1992
10.4.1 Amendment No. 1 to Deferred 10.5.1 1-2301
Compensation Trust dated Form 10-K
March 31, 1994 for the
year ended
December 31,
1994
10.5 Boston Edison Company Deferred 10.9 1-2301
Compensation Plan, Amendment and Form 10-K
Restatement dated January 31, 1995 for the
year ended
December 31,
1994
10.6 Employment Agreement applicable to 10.10 1-2301
Ronald A. Ledgett dated April 30, 1987 Form 10-K
for the
year ended
December 31,
1994
10.7 Change in Control Agreement applicable 10.2 1-2301
to Thomas J. May dated July 8, 1996 Form 10-Q
for the
quarter ended
June 30, 1996
10.8 Form of Change in Control Agreement 10.3 1-2301
applicable to Ronald A. Ledgett, Form 10-Q
L. Carl Gustin, Douglas S. Horan, for the
James J. Judge and certain other quarter ended
officers dated July 8, 1996 June 30, 1996
43
Exhibit SEC Docket
------- ----------
10.9 Boston Edison Company Restructuring 10.12 1-2301
Settlement Agreement dated July 1997 Form 10-K
for the
year ended
December 31,
1997
10.10 Boston Edison Company and Sithe 10.1 1-2301
Energies, Inc. Purchase and Sale Form 10-Q
and Transition Agreements dated for the
December 10, 1997 quarter ended
March 31, 1998
10.11 Boston Edison Company Directors'
Deferred Fee Plan Restatement
effective October 1, 1998
10.12 Boston Edison Company and Entergy
Nuclear Generation Company Purchase
and Sale Agreement dated November 18,
1998
Exhibit 12 Statement re Computation of Ratios
- ---------- ----------------------------------
Filed herewith:
12.1 Computation of Ratio of Earnings
to Fixed Charges for the Year
Ended December 31, 1999
12.2 Computation of Ratio of Earnings
to Fixed Charges and Preferred Stock
Dividend Requirements for the Year
Ended December 31, 1999
Exhibit 21 Subsidiaries of the Registrant
- ---------- ------------------------------
21.1 Harbor Electric Energy Company
(incorporated in Massachusetts),
a wholly owned subsidiary of Boston
Edison Company
44
Exhibit SEC Docket
------- ----------
Exhibit 23 Consent of Independent Accountants
- ---------- ----------------------------------
Filed herewith:
23.1 Consent of Independent Accountants
to incorporate by reference their
opinion included with this Form
10-K in the Form S-3 Registration
Statement filed by Boston Edison
Company on February 3, 1993 (File
No. 33-57840)
Exhibit 27 Financial Data Schedule
- ---------- -----------------------
Filed herewith:
27.1 Schedule UT
Exhibit 99 Additional Exhibits
- ---------- -------------------
Incorporated herein by reference:
99.1 Settlement Agreement between Boston 28.1 1-2301
Edison Company and Commonwealth Form 8-K
Electric Company, Montaup Electric dated
Company and the Municipal December 21,
Light Department of the Town of 1989
Reading, Massachusetts, dated
January 5, 1990
99.2 Settlement Agreement Between Boston 28.2 1-2301
Edison Company and City of Holyoke Form 10-Q
Gas and Electric Department et. al., for the
dated April 26, 1990 quarter ended
March 31, 1990
99.3 Information required by SEC Form 1-2301
11-K for certain employee benefit Form 10-K/A
plans for the years ended Amendments to
December 31, 1997, 1996 and 1995 Form 10-K for
the years ended
December 31,
1997, 1996 and
1995 dated
June 25,1998,
June 26, 1997
and June 27,
1996,
respectively
45
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, 1997
(Dollars in Thousands)
Balance at Provisions Deductions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written Off of Year
- ------------- ------- ---------- ---------- ----------- -------
Year Ended December 31, 1999
----------------------------
Allowance for
Doubtful Accounts $ 9,066 $21,874 $4,356 $16,696 $18,600
Year Ended December 31, 1998
----------------------------
Allowance for
Doubtful Accounts $10,228 $ 9,555 $4,242 $14,959 $ 9,066
Year Ended December 31, 1997
----------------------------
Allowance for
Doubtful Accounts $ 2,000 $24,884 $3,593 $20,249 $10,228
46
FORM 10-K DECEMBER 31, 1999
- --------- -----------------
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BOSTON EDISON COMPANY
------------------------
(Registrant)
By: THOMAS J. MAY
------------------------
Thomas J. May,
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Principal Executive Officers:
/s/ THOMAS J. MAY March 30, 2000
- ---------------------------------------
Thomas J. May,
Chairman of the Board and
Chief Executive Officer
/s/ R.D. WRIGHT March 30, 2000
- ---------------------------------------
R. D. Wright
President and Chief Operating Officer
Principal Financial Officer:
/s/ ROBERT J. WEAFER, JR March 30, 2000
- ---------------------------------------
Robert J. Weafer, Jr.
Vice President and Treasurer
A majority of the Board of Directors:
/s/ THOMAS J. MAY March 30, 2000
- -----------------------------
Thomas J. May, Director
/s/ R. D. WRIGHT March 30, 2000
- -----------------------------
Russell D. Wright, Director
/s/ JAMES J. JUDGE March 30, 2000
- -----------------------------
James J. Judge, Director
47