UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the fiscal year ended December 31, 1999
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 1-14768
NSTAR
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(Exact name of registrant as specified in its charter)
Massachusetts 04-3466300
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(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
800 Boylston St. Boston, Massachusetts 02199
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common shares, par value $1 per share New York Stock Exchange
Boston Stock Exchange
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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [X]
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of March 15, 2000 computed as the average of the high and low
market price of the common stock as reported in the listing of composite
transactions for New York Stock Exchange listed securities in the Wall Street
Journal: $2,209,524,613.
Indicate the number of shares outstanding of each for the registrant's classes
of common stock, as of the latest practicable date.
Class Outstanding at March 15, 2000
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Common Shares $1 per value 56,836,646 Shares
Documents Incorporated by Reference Part in Form 10-K
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Portions of the Registrant's Notice of Parts I, II and III
2000 Annual Meeting, Proxy Statement
and 1999 Financial Information
Dated March 30, 2000
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(pages as specified herein)
NSTAR
Form 10-K Annual Report
December 31, 1999
Part I Page
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Item 1. Business 3
Item 2. Properties 13
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of Security Holders 15
Item 4A. Executive Officers of Registrant
Part II
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Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 16
Item 6. Selected Financial Data 17
Item 7. Management's Discussion and Analysis 18
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 33
Item 8. Financial Statements and Supplementary Financial
Information 34
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 62
Part III
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Item 10. Trustees and Executive Officers of the Registrant 62
Item 11. Executive Compensation 62
Item 12. Security Ownership of Certain Beneficial Owners and
Management 62
Item 13. Certain Relationships and Related Transactions 62
Part IV
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Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K 63
2
Part I
Item 1. Business
(a) General Development of Business
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 holding company. NSTAR's utility subsidiaries are Boston Edison Company
(Boston Edison), Commonwealth Electric Company (ComElectric), Cambridge Electric
Light Company (Cambridge Electric), Canal Electric Company (Canal Electric) and
Commonwealth Gas Company (ComGas). Utility operations accounted for more than
98% of revenues in both 1999 and 1998.
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. Substantially all of COM/Energy's generating facilities were sold in 1998.
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 quartely dividend was increased to 50 cents per share
($2.00 on an annualized basis) on December 16, 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.
In 1998, prior to the merger, COM/Energy sold substantially all of its fossil
generating assets. As part of an agreement with the Massachusetts Department of
Telecommunications and Energy (MDTE), COM/Energy established Energy Investment
Services, Inc. as the vehicle to invest the net proceeds from the sale of these
assets. Both the principal amount and income earned are being used to reduce the
transition costs that would otherwise be billed to customers of Cambridge
Electric and ComElectric. The net proceeds have been classified as restricted
cash on the accompanying Consolidated Balance Sheets.
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 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 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.
NSTAR also engages in nonutility and utility generation businesses through its
subsidiaries. These include Boston Energy Technology Group Inc. (BETG), which
engages in a number of businesses including telecommunications through its joint
venture with RCN Telecom Services, Inc.; Canal Electric, which owns a 3.52%
interest in the Seabrook 1 nuclear power plant; Advanced Energy Systems, Inc., a
company that operates an energy plant providing steam, chilled water and
electric generating services serving certain Boston area hospitals and schools;
a steam distribution company; a company that services and processes liquefied
natural gas; and five real estate trusts.
3
(b) Financial Information about Industry Segments
NSTAR's principal segments are the electric and natural gas utilities that
provide the transmission and distribution of energy. Refer to Note L of the
Consolidated Financial Statements in Item 8 for specific financial information
related to NSTAR's electric utility, gas utility and unregulated nonutility
segments.
(c) Narrative Description of Business
Principal Products and Services
ELECTRIC INDUSTRY
NSTAR electric operating revenues by class of customers for the last three years
consisted of the following:
1999 1998 1997
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Retail electric revenues:
Commercial 51% 51% 51%
Residential 30% 27% 27%
Industrial 9% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 9% 12% 12%
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BEC
In May 1998, Boston Edison, a regulated public utility incorporated in 1886
under Massachusetts' law, 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.
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 670,000
customers.
COM/Energy
COM/Energy, a Massachusetts business trust, is an unincorporated business
organization with transferable shares organized under a Declaration of Trust in
1926, as amended, pursuant to the laws of Massachusetts. It is an exempt public
utility holding company holding all of the stock of four operating public
utility companies (ComElectric, Cambridge Electric, Canal Electric and ComGas).
Unregulated activities include district heating and cooling and liquidified
natural gas services. On August 25, 1999 COM/Energy became a subsidiary of
NSTAR.
Each of Com/Energy's operating utility subsidiaries serves retail customers
except for Canal Electric.
ComElectric and Cambridge Electric
Electric service is furnished by ComElectric and Cambridge Electric at retail to
approximately 329,000 year-round and 45,000 seasonal customers in 41 communities
in eastern and southeastern Massachusetts covering 1,112 square miles and having
an aggregate population of 645,000. The territory served includes the
communities of Cambridge, New Bedford and Plymouth and the geographic area
comprising Cape Cod and Martha's Vineyard. Cambridge Electric also sells power
at wholesale to the Town of Belmont, Massachusetts.
4
Com/Gas
Natural gas is distributed by COMGas to approximately 243,000 customers in 51
communities in central and eastern Massachusetts covering 1,067 square miles and
having an aggregate population of 1,128,000. 25 of these communities are also
served by Boston Edison, Cambridge Electric and ComElectric with electricity.
Some of the larger communities served by ComGas include Cambridge, Somerville,
New Bedford, Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of
Boston.
Sources and Availability of Electric Power Supply
NSTAR on behalf of its electric retail subsidiaries Boston Edison, Cambridge
Electric and ComElectric 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 Federal Energy Regulatory Commission (FERC)
approved tariff rates through June 30, 2000. NSTAR's 1999 proportionate share of
capacity and total cost reflects four months of the COM/Energy companies from
the date of the merger. For further information, refer to footnote N to
consolidated financial statements in Item 8.
5
Commonwealth Electric had an 11% contract entitlement in the output of the
Pilgrim nuclear power plant that was sold by Boston Edison in 1999 to Entergy
Nuclear Generating Company (Entergy). Boston Edison and ComElectric will buy
power generated by the Pilgrim plant from Entergy on a declining basis through
2004. Cambridge Electric has a 2.5% equity ownership in the Vermont Yankee
nuclear power plant. Vermont Yankee is under agreement to be sold to AmerGen
Energy Co.
Information relative to nuclear units that are no longer operating in which
NSTAR has an equity ownership is as follows:
Connecticut Maine Yankee
Yankee Yankee Atomic
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(dollars in thousands)
Year of Shutdown 1996 1997 1992
Equity Ownership (%) 14.00 4.00 19.00
Equity Ownership Balance $14,596 $3,519 $2,339
New England Power Pool
During 1997, the power pool 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 dispatch that
began in the second quarter of 1999. As noted in the Sources and Availability of
Electric Power Supply section above, Boston Edison, Cambridge Electric and
ComElectric 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 NSTAR's costs for purchased
electric energy.
6
Franchises
Through their charters, which are unlimited in time, Boston Edison, ComElectric
Cambridge Electric and ComGas have the right to engage in the business of
distributing and selling electricity, natural gas, steam and other forms of
energy, have powers incidental thereto and are entitled to all the rights and
privileges of and subject to the duties imposed upon electric and natural gas
companies under Massachusetts laws. The locations in public ways for electric
transmission and distribution lines or gas distribution 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 Industry Restructuring Act
enacted in November 1997, the MDTE has defined the service territory of Boston
Edison, ComElectric and Cambridge Electric 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, these companies 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, ComElectric, and Cambridge Electric which
consent, must be filed with the MDTE and the municipality so affected.
Regulation
NSTAR's electric and gas utility subsidiaries, and Boston Edison's wholly owned
subsidiary, Harbor Electric Energy Company (HEEC), operate primarily under the
authority of the MDTE, whose jurisdiction includes supervision over retail rates
for distribution of electricity, natural gas and financing and investing
activities. In addition, the FERC has jurisdiction over various phases of
NSTAR's electric and natural gas utility businesses including rates for
electricity and natural gas 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.
7
Retail Electric Rates
As a result of electric industry restructuring, the NSTAR electric utility
subsidiaries have unbundled their rates, provided customers with inflation
adjusted rates that are 15 percent lower than rates in effect prior to March 1,
1998, the retail access date, and have afforded customers the opportunity to
purchase generation supply in the competitive market. Unbundled delivery rates
are composed of a customer charge (to collect metering and billing costs), a
distribution charge (to collect the costs of delivering electricity), a
transition charge (to collect past costs for investments in generating plants
and costs related to power contracts), a transmission charge (to collect the
cost of moving the electricity over high voltage lines from a generating plant),
an energy conservation charge (to collect costs for demand-side management
programs) and a renewable energy charge (to collect the cost to support the
development and promotion of renewable energy projects). Electricity supply
services provided by NSTAR's retail electric subsidiaries include optional
standard offer service and default service.
Standard offer service is the electricity that is supplied by the retail
electric subsidiaries until a competitive power supplier is chosen by the
customer. It is designed as a seven-year transitional service (from March 1,
1998) to give the customer time to learn about competitive power suppliers. The
price of standard offer service will increase over time. Default service is
supplied by the local distribution company when a customer is not receiving
power from either standard offer service or a competitive power supplier. The
market price for default service will fluctuate based on the average market
price for power. Amounts collected through these various charges will be
reconciled to actual expenditures on an on-going basis.
Prior to the implementation of industry restructuring on March 1, 1998, Boston
Edison, ComElectric and Cambridge Electric 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.
8
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.
Gas Industry
NSTAR Gas operating revenues by class of customers, effective September 1, 1999,
consisted of the following:
1999
----------------------------------------
Retail Gas revenues:
Commercial 22%
Residential 70%
Industrial 3%
Other 4%
Wholesale & contract revenues 1%
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Gas Supply
ComGas purchases transportation, storage and balancing services from Tennessee
Gas Pipeline Company (Tennessee) and Algonguin Gas Transmission Company (and
other upstream pipelines that bring gas from the supply wells to the final
transporting pipelines) and purchases all of its gas supplies from third-party
vendors, utilizing firm contracts with terms of less than one year. The vendors
vary from small independent marketers to major gas and oil companies.
In addition to firm transportation and gas supplies mentioned above, ComGas
utilizes contracts for underground storage and LNG facilities to meet its winter
peaking demands. The underground storage contracts are a combination of existing
and new agreements which are the result of FERC Order 636 service unbundling.
The LNG facilities, described below, are used to liquefy and store pipeline gas
during the warmer months for use during the heating season.
ComGas entered into a multi-party agreement in 1992 to assume a portion of
Boston Gas Company's contracts to purchase Canadian gas supplies from Alberta
Northeast (ANE) and have the volumes delivered by the Iroquois Gas Transmission
System and Tennessee pipelines. The ANE gas supply contract was filed with the
MDTE and hearings were completed in April 1993.
On November 17, 1995, the Department approved the ComGas Original ANE Contract
between ComGas and ANE for the purchase of approximately 4.5 million cubic feet
per day of natural gas from Alberta, Canada. The MDTE approved the Gas Sales
Agreement between Alberta Northeast Gas Limited and ComGas files on March 3,
1999. Previous to the Agreement, ComGas purchased its Canadian Supply through
Boston Gas Company. The agreement allows ComGas to receive up to 4,500
MMBtu/Day of Canada Supply delivered into the Iroquois Gas Transmission system.
In compliance with this order, ComGas also signed transportation agreements
with the Tennessee Gas Pipeline and Iroquois Pipeline.
ComGas began transporting gas on its distribution system in 1990 for end-users.
As of December 31, 1999, there were 732 customers using this transportation
service, accounting for 11,146 BBTU or approximately 24% of total throughput.
A portion of the gas supply for ComGas during the heating season is provided by
Hopkinton LNG Corp. (Hopkinton), a wholly-owned subsidiary of NSTAR. The
facility consists of a liquefaction and vaporization plant and three
above-ground cryogenic storage tanks having an aggregate capacity of 3 million
MCF of natural gas.
In addition, Hopkinton owns a satellite vaporization plant and two above-ground
cryogenic storage tanks located in Acushnet, Massachusetts with an aggregate
capacity of 500,000 MCF of natural gas that are filled with LNG trucked from
Hopkinton.
ComGas has contracts for LNG service with Hopkinton extending on year to year
basis with notice of termination required five years in advance of the
anticipated termination date. Current contract payments include a demand charge
sufficient to cover Hopkinton's fixed changes and an operating charge which
covers liquefaction and vaporization expenses. ComGas furnishes pipeline gas
during the period April 15 to November 15 each year for liquefaction and
storage. As the need arises, LNG is vaporized and placed in the distribution
system of ComGas.
Based upon information presently available regarding projected growth in demand
and estimates of availability of future supplies of pipelines gas, ComGas
believes that its present sources of gas supply are adequate to meet existing
load and allow for future growth in sales.
9
Natural Gas Industry Restructuring and Rates
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In September 1997, ComGas along with other gas utilities initiated the
Massachusetts Gas Unbundling Collaborative (the Collaborative), to explore and
develop generic principles to achieve the MDTE's goals of establishing choice
of gas supplier for all customers (comprehensive unbundling).
In August 1998, the MDTE approved the unbundled rate settlement submitted by
ComGas, followed in September with compliance rates submitted by ComGas that
were consistent with a settlement agreement. These unbundled rates became
effective on November 1, 1998.
ComGas has a Seasonal Cost of Gas Adjustment Clause (CGAC) and a Local
Distribution Adjustment Clause (LDAC) that provide for the recovery, from firm
customers or Default Service customers, of certain costs previously recovered
through base rates. The CGAC provides for rates that must be approved semi-
annually by the MDTE. The LDAC provides for rates that require annual approval.
As part of its new unbundled rates, ComGas modified its existing CGAC to allow
for the following changes: (a) the addition of provisions that allow for the
recovery of certain bad-debt expenses; (b) new formulas that no longer adjust
the Gas Adjustment Factors for the seasonal embedded gas costs that were in
existing sales rates; (c) updated language reflecting the ratemaking
requirements for non-core revenue margins; and (d) the removal of provisions for
the recovery of environmental remediation costs and FERC Order 636 transition
costs, which will instead be recovered through the LDAC.
ComGas' approved LDAC recovers conservation charges, environmental remediation
costs, balancing penalty revenue credits, and costs associated with the its
participation in the MGUC.
In February 1999, the MDTE determined that the capacity market in Massachusetts
was not yet workably competitive to allow it to remove traditional regulatory
controls that were designed to ensure the reliability of gas service to
customers. The MDTE further reaffirmed that the local distribution companies
(LDCs) must continue with their obligation to plan for and procure sufficient
upstream capacity.
On November 3, 1999 after numerous Collaborative meetings, the LDC's filed the
remaining sections of the Model Terms and Conditions dealing with capacity
assignment peaking services and default service and also filed draft regulations
that establish rules to govern the statewide customer choice initiative. In
their filing the LDC's indicated that comprehensive unbundling could be
implemented no sooner than April 1, 2000. After reviewing comments from
stakeholders, the MDTE approved the new sections of the Model Terms and
Conditions on January 26, 2000. The MDTE also required each LDC to file
compliance Terms and Conditions within 21 days of their order. On December 19,
1999 the MDTE issued a NOL and a procedural schedule seeking comments from
interested parties regarding the proposed regulations.
10
Capital Expenditures and Financings
The most recent estimates of capital expenditures, 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:
(in thousands) 2000 2001 2002 2003 2004
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Capital
expenditures (1) $347,000 $216,000 $170,000 $144,000 $143,000
AFUDC $ 4,000 $ 4,000 $ 4,000 $ 4,000 $ 4,000
Long-term debt $166,600 $122,500 $108,800 $241,200 $ 78,700
Preferred stock $ - $ 50,000 $ - $ - $ -
=============================================================================
(1) Includes both plant expenditures and capital requirements of nonutility
ventures.
Management continuously reviews its capital expenditure and financing programs.
These programs and, therefore, the estimates included in this Form 10-K are
subject to revision due to changes in regulatory requirements,
11
environmental standards, availability and cost of capital, interest rates and
other assumptions.
Plant expenditures in 1999 were $159.3 million and consisted primarily of
additions to NSTAR'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 NSTAR service territory.
Refer to the Liquidity section of Item 7 for more information regarding capital
resources to fund NSTAR's construction programs.
Seasonal Nature of Business
Kilowatt-hour sales and revenues are typically higher in the winter and summer
than in the spring and fall as sales tend to vary with weather conditions. Refer
to the Selected Consolidated Quarterly Financial Data (Unaudited) in Item 8 for
specific financial information by quarter for 1999 and 1998. ComElectric's sales
are substantially higher in the summer due to the tourist industry on Cape Cod.
Competitive Conditions
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 pressures have resulted in an increasing trend in the
industry to seek competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new marketplace by combining
the resources of its utility subsidiaries in its activities in the transmission
and distribution of energy.
Environmental Matters
NSTAR's and its subsidiaries are 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 remaining
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
As of December 31, 1999, NSTAR's subsidiaries had approximately 3,400 full-time
employees, including approximately 2,300 (68%) employees represented by various
collective bargaining units covered by separate contracts with varying
expiration dates. The contracts with two union locals representing approximately
1,300 employees of the Utility Workers Union of America, AFL-CIO, will terminate
on May 15, 2000. Management believes it has satisfactory employee relations.
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(d) Financial Information about Foreign and Domestic Operations and Export Sales
None of NSTAR's subsidiaries have any foreign operations or export sales.
Item 2. Properties
Substantially all of NSTAR's non-nuclear generating assets were sold as of
December 30, 1998. The Pilgrim Nuclear Generating Station was sold in 1999.
NSTAR, through its Canal Electric subsidiary, still retains its 3.52% interest
(40.5 MW of capacity) in Seabrook 1.
Other electric properties include an integrated system of distribution lines and
substations which are located in the Boston area as well as the outlying
communities and Cape Cod and Martha's Vineyard. In addition, NSTAR's other
principal properties consist of an office building in Wareham, Massachusetts and
other structures such as garages and service buildings.
At December 31, 1999, the electric transmission and distribution system
consisted of 9,580 pole miles of overhead lines, 7,840 cable miles of
underground lines, 507 substations and 1,372,000 active customer meters.
The principal natural gas properties consist of distribution mains, services and
meters necessary to maintain reliable service to customers. At December 31,
1999, the gas system included 2,861 miles of gas distribution lines, 170,103
services and 249,874 customer meters together with the necessary measuring and
regulating equipment. In addition, NSTAR owns a liquefaction and vaporization
plant, a satellite vaporization plant and above-ground cryogenic storage tanks
having an aggregate storage capacity equivalent to 3.5 million MCF of natural
gas. NSTAR's gas division owns an office and service building in Southborough,
Massachusetts, five district office buildings and several natural gas receiving
and take stations.
13
NSTAR's subsidiaries' 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.
HEEC, Boston Edison's regulated subsidiary, has a distribution system that
consists principally of a 4.1 mile 115 kV submarine distribution line and a
substation which is located on Deer Island in Boston, Massachusetts. HEEC
provides the ongoing support required to distribute electric energy to its one
customer, the Massachusetts Water Resources Authority, at this location.
Item 3. Legal Proceedings
Industry and corporate restructuring legal proceedings
The 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.
Management is currently unable to determine the outcome of these outstanding
proceedings however, but 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.
Rate Plan
The MDTE issued an order approving most major elements of a rate plan filed by
the retail utility subsidiaries of NSTAR 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, the collection from customers of the
14
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 (SHC) 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 NSTAR and its subsidiaries are also
involved in certain other legal matters. Management is unable to fully determine
a range of reasonably possible legal costs in excess of amounts accrued. Based
on the information currently available, it does not believe that it is probable
that any such additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period.
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the fourth
quarter of 1999.
Item 4A. Executive Officers of Registrant
Identification of Executive Officers
Age
December
Name of Officer Position and Business Experience 31, 1999
- --------------- -------------------------------- --------
Thomas J. May Chairman of the Board and Chief 52
Executive Office, and a Trustee
NSTAR (since 1999), formerly Chairman of the Board,
President, and Chief Executive Officer, BEC Energy
(1998-1999); Chairman of the Board, President, and
Chief Executive Officer, Boston Edison Company
1995-1999)
Chairman of the Board and Chief Executive Officer and
Trustee of BEC Energy, Commonwealth Energy System,
COM/Energy Acushnet Realty, COM/Energy Cambridge
Realty, COM/Energy Freetown Realty, COM/Energy
Research Park Realty, and Darvel Realty Trust;
Chairman of the Board and Chief Executive Officer and
Director of Advanced Energy Systems, Inc., Advanced
Energy Systems Management Company, Inc., Medical Area
Total Energy Plant, Inc., NSTAR Communications, Inc.,
Boston Edison Company, Cambridge Electric Light
Company, Canal Electric Company, Commonwealth
Electric Company, COM/Energy Marketing, Inc.,
Commonwealth Gas Company, Coneco Corporation, Energy
Investment Services, Inc., Harbor Electric Energy
Company, Hopkinton LNG Corp., COM/Energy Steam
Company, COM/Energy Resources, Inc., Boston Energy
Technology Group, Inc., Boston Edison Services, Inc.,
NSTAR Communication Securities Corporation, NSTAR
Services Corporation, COM/Energy Services Company,
and BEC Funding LLC.
Russell D. Wright President and Chief Operating Officer 53
and Trustee.
President and Chief Operating Officer, NSTAR
(since 1999); formerly President and Chief
Executive Officer, Commonwealth Energy
System (1998-1999); President and Chief
Operating Officer, Commonwealth Energy
System's electric and gas subsidiaries
(1993-1998)
President and Chief Operating Officer and Trustee of BEC
Energy, Commonwealth Energy System; Vice Chairman and
Director of Advanced Energy Systems, Inc., Advanced
Energy Systems Management Company, Inc., Medical Area
Total Energy Plant, Inc., and NSTAR Communications,
Inc.; President and Chief Operating Officer and Director
of Boston Edison Company, Cambridge Electric Light
Company, Canal Electric Company, Commonwealth Electric
Company, Commonwealth Gas Company, Energy Investment
Services, Inc., Harbor Electric Energy Company,
COM/Energy Marketing, Inc., NSTAR Communications
Securities Corporation, NSTAR Services Corporation, and
COM/Energy Services Company; Vice Chairman, President
and Chief Operating and Trustee of COM/Energy Acushnet
Realty, COM/Energy Cambridge Realty, COM/Energy Freetown
Realty, COM/Energy Research Park Realty, and Darvel
Realty Trust; Vie Chairman, President and Chief
Operating Officer and Director of Coneco Corporation,
Hopkinton LNG Corp., COM/Energy Steam Company,
COM/Energy Resources, Inc., Boston Energy Technology
Group, Inc., Boston Edison Services, Inc. and BEC
Funding LLC.
Ronald A. Ledgett Executive Vice President - Electric 61
Operations.
Executive Vice President - Electric
Operations, NSTAR (since 1999); Executive
Vice President, Boston Edison Company (1997
to present); Senior Vice President - Fossil,
Field Service and Electric Delivery, Boston
Edison Company (1996-1997); Senior Vice
President - Power Delivery, Boston Edison
Company (1991-1995)
Executive Vice President - Electric
Operations of BEC Energy, Commonwealth
Energy System, Cambridge Electric Light
Company, Canal Electric Company,
Commonwealth Electric Company, NSTAR
Services Corporation and COM/Energy Services
Company.
Deborah A. McLaughlin Executive Vice President - Customer 41
Care/Shared Services.
Executive Vice President - Customer
Care/Shared Services, NSTAR (since 1999);
President and Chief Operating Officer,
Commonwealth Energy System's electric and
gas subsidiaries (1998-1999); Vice President
- Customer Service, Commonwealth Energy
System's electric and gas subsidiaries
(1993-1998).
Executive Vice President - Customer
Care/Shared Services of BEC energy,
Commonwealth Energy System, Boston Edison
Company, Cambridge Electric Light Company,
Canal Electric Company, Commonwealth
Electric Company, Commonwealth Gas Company,
NSTAR Service Corporation and COM/Energy
Services Company.
Alison Alden Senior Vice President - Human Resources 51
Senior Vice President - Human Resources,
NSTAR (since 1999); formerly Senior Vice
President - Sales, Services and Human
Resources, Boston Edison Company
(1996-1999), Vice President - Sales &
Services, Boston Edison Company (1993-1996)
Senior Vice President - Human Resources of
BEC Energy, Commonwealth Energy System,
Boston Edison Company,
Cambridge Electric Light Company, Canal
Electric Company, Commonwealth Electric
company, Commonwealth Gas Company NSTAR
Services Corporation and COM/Energy
Services Company.
L. Carl Gustin Senior Vice President - Corporate 56
Relations.
Senior Vice President - Corporate Relations, NSTAR
(since 1999) and Boston Edison Company (since 1995)
Senior Vice President - Corporate Relations
of BEC Energy, Commonwealth Energy System,
Cambridge Electric Light Company, Canal
Electric Company, Commonwealth Electric
Company, Commonwealth Gas Company, NSTAR
Services Corporation and COM/Energy Services
Company.
Douglas S. Horan Senior Vice President/Strategy, Law & 50
Policy.
Senior Vice President/Strategy, Law &
Policy, NSTAR (since 1999); formerly Senior
Vice President - Strategy and Law and
General Counsel, BEC Energy (1998-1999) and
Boston Edison Company (1995-1999)
Senior Vice President/Strategy, Law & Policy of BEC
Energy, Commonwealth Energy System, Advanced Energy
Systems, Inc., Advanced Energy Systems Management
Company, Inc., Medical Area Total Energy Plant, Inc.,
NSTAR Communications, Inc., Boston Edison Company,
Cambridge Electric Light Company, Canal Electric
Company, Commonwealth Electric Company, COM/Energy
Marketing, Inc., COM/Energy Acushnet Realty, COM/Energy
Cambridge Realty, COM/Energy Freetown Realty, COM/Energy
Research Park Realty, Darvel Realty Trust, Commonwealth
Gas Company, Coneco Corporation, Energy Investment
Services, Inc., Harbor Electric Energy Company,
Hopkinton LNG Corp., COM/Energy Steam Company,
COM/Energy Resources, Inc., Boston Edison Technology
Group, Inc., Boston Edison Service, Inc., NSTAR
Communications Securities Corporation,
NSTAR Services Corporation, COM/Energy Services
Company, and BEC Funding LLC.
James J. Judge Senior Vice President, Treasurer and 44
Chief Financial Officer
Senior Vice President, Treasurer and Chief
Financial Officer, NSTAR (since 2000);
formerly Senior Vice President and Chief
Financial Officer, NSTAR (1999-2000); Senior
Vice President - Corporate Services and
Treasurer, BEC Energy (1998-1999); Senior
Vice President - Corporate Services and
Treasurer, Boston Edison Company
(1995-1999).
Senior Vice President, Treasurer and Chief Financial
Officer and Trustee of BEC Energy, Commonwealth Energy
System, COM/Energy Acushnet Realty, COM/Energy Cambridge
Realty, COM/Energy Freetown Realty, COM/Energy Research
Park Realty, Darvel Realty Trust; Senior Vice President,
Treasurer and Director of Advanced Energy Systems, Inc.,
Advanced Energy Systems Management Company, Inc.,
Medical Area Total Energy Plant, Inc., NSTAR
Communications, Inc., Boston Edison Company, Cambridge
Electric Light Company, Canal Electric Company,
Commonwealth Electric Company, COM/Energy Marketing,
Inc., Commonwealth Gas Company, Coneco Corporation,
Energy Investment Services, Inc., Harbor Electric Energy
Company, Hopkinton LNG Corp., COM/Energy Steam Company,
COM/Energy Resources, Inc., Boston Energy Technology
Group, Inc., Boston Edison Services, Inc., NSTAR
Communications Securities Corporation, NSTAR Services
Corporation, COM/Energy Services Company, and BEC
Funding LLC.
Michael P. Sullivan Vice President, Secretary/Clerk and 52
General Counsel
Vice President, Secretary/Clerk and General
Counsel, NSTAR (since 1999); formerly Vice
President, Secretary and General Counsel,
Commonwealth Energy System and all of its
subsidiaries
Vice President, Secretary/Clerk and General Counsel of
BEC Energy, Commonwealth Energy System, Advanced Energy
Systems, Inc., Advanced Energy Systems Management
Company, Inc. Medical Area Total Energy Plant, Inc.,
NSTAR Communications, Inc., Boston Edison Company,
Cambridge Electric Light Company, Canal Electric
Company, Commonwealth Electric Company, COM/Energy
Marketing, Inc., COM/Energy Acushnet Realty, COM/Energy
Cambridge Realty, COM/Energy Freetown Realty, COM/Energy
Research Park Realty, Darvel Realty Trust, Commonwealth
Gas Company, Coneco Corporation, Energy Investment
Services, Inc., Harbor Electric Energy Company,
Hopkinton LNG Corp., COM/Energy Steam Company,
COM/Energy Resources, Inc., Boston Energy Technology
Group, Inc., Boston Edison Services, Inc., NSTAR
Communications Securities Corporation, NSTAR Services
Corporation, COM/Energy Services Company, and BEC
Funding LLC.
Robert J. Weafer Jr. Vice President, Controller and Chief 53
Accounting Officer
Vice President, Controller and Chief
Accounting Officer, NSTAR (since 1999), BEC
Energy (since 1998) and Boston Edison
Company (since 1991)
Vice President, Controller and Chief Accounting Officer
of Commonwealth Energy System, Advanced Energy Systems,
Inc., Advanced Energy Systems Management Company, Inc.,
Medical Area Total Energy Plant, Inc., NSTAR
Communications, Inc., Cambridge Electric Light Company,
Canal Electric Company, Commonwealth Electric Company,
COM/Energy Marketing, Inc., COM/Energy Acushnet Realty,
COM/Energy Cambridge Realty, COM/Energy Freetown Realty,
COM/Energy Research Park Realty, Darvel Realty Trust,
Commonwealth Gas Company, Coneco Corporation, Energy
Investment Services, Inc., Harbor Electric Energy
Company, Hopkinton LNG Corp., COM/Energy Steam Company,
COM/Energy
Resources, Inc., Boston Energy Technology
Group, Inc., Boston Edison Services, Inc., NSTAR
Communications Securities Corporation, NSTAR Services
Corporation, COM/Energy Services Company, and BEC
Funding LLC.
15
Part II
Item 5. Market for the Registrant's Common Stock and Related Stockholder Matters
(a) Market Information
NSTAR's common shares are listed on the New York and Boston Stock Exchanges.
The high and low market value per common share as reported in the Wall
Street Journal for each of the quarters in 1999 and 1998 was as follows. (Prior
to September 1999, the information listed refers to BEC Energy common shares
and prior to May 1998, the information listed refers to Boston Edison Company
common stock.)
1999 1998
- --------------------------------------------------------------------------------
High Low High Low
- --------------------------------------------------------------------------------
First quarter $41 3/16 $36 7/16 $41 15/16 $35 1/16
Second quarter $44 5/8 $37 3/16 $42 5/8 $38 7/8
Third quarter $43 5/16 $36 3/4 $44 5/16 $37 3/4
Fourth quarter $42 3/8 $36 5/8 $44 15/16 $39 5/8
================================================================================
(b) Holders
As of March 29, 2000, there were 35,395 holders of NSTAR common shares.
(c) Dividends
Dividends declared per common share for each of the quarters in 1999
and 1998 were as follows. (Prior to September 1999, the information listed
refers to BEC Energy common shares and prior to May 1998, the information listed
refers to Boston Edison Company common stock.)
1999 1998
- -----------------------------------------------------------
First quarter $0.485 $0.470
Second quarter $0.485 $0.470
Third quarter $0.485 $0.470
Fourth quarter $0.500 $0.485
===========================================================
16
Item 6. Selected Financial Data
The following table summarizes five years of selected consolidated financial
data (in thousands, except per share data). Prior to September 1999, the
information below refers to BEC Energy.
1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------
Operating
revenues $1,851,427 $1,622,515 $1,778,531 $1,668,856 $1,628,503
Net income $ 146,463 $ 141,046 $ 144,642 $ 141,546 $ 112,310
Earnings per
share of
common
stock:
Basic $ 2.77 $ 2.76 $ 2.71 $ 2.61 $ 2.08(a)
Diluted $ 2.76 $ 2.75 $ 2.71 $ 2.61 $ 2.08(a)
Total
assets $5,482,888 $3,204,036 $3,622,347 $3,729,291 $3,637,170
Long-term
debt $ 986,843 $ 955,563 $1,057,076 $1,058,644 $1,160,223
Transition
property
securitization
certificates $ 646,559 $ 0 $ 0 $ 0 $ 0
Redeemable
preferred
stock $ 92,279 $ 92,040 $ 163,093 $ 203,419 $ 206,514
Cash
dividends
declared
per common
share $ 1.955 $ 1.895 $ 1.880 $ 1.880 $ 1.835
=============================================================================
(a) Includes $0.44 per share restructuring charge. Excluding the
restructuring charge, 1995 earnings per share were $2.52.
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share) Earnings Basic
Available Earnings
Operating Operating Net for Common Per Average
Revenues Income Income Shareholders Common Share(a)
- --------------------------------------------------------------------------------
1999
First quarter $371,870 $ 43,729 $ 19,562 $ 18,072 $0.38
Second quarter $379,290 $ 58,669 $ 36,253 $ 34,763 $0.76
Third quarter $517,151 $ 85,022 $ 68,260 $ 66,770 $1.32
Fourth quarter $583,116 $ 76,278 $ 22,388 $ 20,898 $0.31
1998
First quarter $394,117 $ 49,390 $ 22,859 $19,940 $0.41
Second quarter $385,348 $ 64,945 $ 34,323 $ 31,452 $0.65
Third quarter $479,897 $100,304 $ 75,490 $ 74,004 $1.55
Fourth quarter $363,153 $ 28,301 $ 8,374 $ 6,885 $0.15
(a) Based on the weighted average number of common shares outstanding during
each quarter.
17
Item 7 Management's Discussion and Analysis
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 Company (Boston Edison),
Commonwealth Electric Company (ComElectric), Cambridge Electric Light Company
(Cambridge Electric), Canal Electric Company (Canal Electric) and Commonwealth
Gas Company (ComGas). Utility operations accounted for more than 98% of revenues
in both 1999 and 1998. NSTAR's nonutility operations include telecommunications,
district heating and cooling operations and liquefied natural gas services.
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. Substantially all of COM/Energy's generating facilities were sold in 1998.
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.
An integral part of the merger is the rate plan that was filed by the retail
utility subsidiaries of BEC and COM/Energy that was approved by the
Massachusetts Department of Telecommunications and Energy (MDTE) on July 27,
1999. Significant elements of the rate plan include a four-year distribution
rate freeze, recovery of the transaction 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.
The merger was accounted for by NSTAR as an acquisition by BEC of COM/Energy
under the purchase method of accounting. Goodwill amounted to approximately $486
million, resulting in an annual amortization of goodwill of approximately $12.2
million. Costs to achieve are being amortized based on the filed estimate of
$111 million over 10 years. NSTAR's retail electric utility subsidiaries will
reconcile the ultimate costs to achieve with that estimate and any difference is
expected to be recovered over the remainder of the amortization period. To date,
a majority of costs to achieve the merger are for severance costs associated
with a voluntary separation program in which approximately 700 employees elected
to participate. These amounts are expected to be offset by ongoing future cost
savings from streamlined operations and avoidance of costs that would have
otherwise been incurred by BEC and COM/Energy.
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
18
unable to determine the ultimate outcome of these appeals.
Generating Asset 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.
In 1998, prior to its merger with BEC, COM/Energy sold substantially all of its
fossil generating assets. As part of an agreement with the MDTE, COM/Energy
established Energy Investment Services, Inc. as the vehicle to invest the net
proceeds from the sale of these assets. Both the principal amount and income
earned are being used to reduce the transition costs that would otherwise be
billed to customers of Cambridge Electric and ComElectric. The net proceeds have
been classified as restricted cash on the accompanying Consolidated Balance
Sheets.
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 purchaser, by 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
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
As a result of the Massachusetts Electric Restructuring Act, the regulated
retail electric subsidiaries of NSTAR 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 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. NSTAR 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
19
power costs, is recovered from customers on a fully reconciling basis. New
retail customers in the NSTAR 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.
Each NSTAR retail electric subsidiary filed proposed adjustments to their
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 NSTAR's cost recovery mechanism.
Natural Gas Industry Restructuring and Rates
In September 1997, ComGas along with other gas utilities initiated the
Massachusetts Gas Unbundling Collaborative (the Collaborative), to explore and
develop generic principles to achieve the MDTE's goals of establishing choice of
gas supplier for all customers (comprehensive unbundling).
In August 1998, the MDTE approved the unbundled rate settlement submitted by
ComGas, followed in September with compliance rates submitted by ComGas that
were consistent with a settlement agreement. These unbundled rates became
effective on November 1, 1998.
In February 1999, the MDTE determined that the capacity market in Massachusetts
was not yet workably competitive to allow it to remove traditional regulatory
controls that were designed to ensure the reliability of gas service to
customers. The MDTE further reaffirmed that the local distribution companies
(LDCs) must continue with their obligation to plan for and procure sufficient
upstream capacity.
Results of Operation - 1999 versus 1998
NSTAR's energy delivery businesses continue to be subject to traditional utility
accounting and rate making principles since NSTAR earns a regulated equity
return on its investments in those businesses.
Due to the application of the purchase method of accounting, the results for
1999 reflect 8 months of BEC and 4 months of NSTAR. Results for 1998 only
reflect BEC.
Basic and diluted earnings per common share were $2.77 and $2.76, respectively,
in 1999 compared to $2.76 and $2.75, respectively, in 1998, a 0.4% increase in
earnings as described below.
Operating Revenues
Operating revenues increased 14.1% from 1998 as follows:
20
(in thousands)
- --------------------------------------------------------------------------------
Retail electric revenues $ 175,708
Wholesale electric revenues (33,480)
Electric short-term sales and other revenues (21,433)
Gas revenues 108,117
- --------------------------------------------------------------------------------
Increase in operating revenues $ 228,912
================================================================================
Retail electric revenues were $1,550.8 million in 1999 compared to $1,375.1
million in 1998, an increase of $175.7 million or 13%. The change in 1999
reflects an increase of $163.3 million representing 4 months of revenues from
the former COM/Energy retail electric subsidiaries from the date of the merger.
Without the impact of the merger, retail revenues would have been $1,387.5
million in 1999, an increase from 1998 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
Restructuring Law that was initially implemented in March 1998, and an
additional 5% rate reduction effective September 1, 1999.
Wholesale electric revenues were $108.5 million in 1999 compared to $142 million
in 1998, a decrease of $33.5 million or 24%. 1999 reflects an increase of $6.1
million representing 4 months of revenues from the former COM/Energy
subsidiaries from the date of the merger. Without the impact of the merger,
wholesale revenues would have been $102.4 million, a decrease from 1998 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.
Total electric short-term sales and other revenues were $84 million in 1999
compared to $105.4 million in 1998, a decrease of $21.4 million or 20%. 1999
reflects an increase of $31.4 million representing 4 months of revenues from the
former COM/Energy subsidiaries from the date of the merger. Without the impact
of the merger, short-term and other revenues would have been $52.6 million in
1999, a decrease from 1998 of $52.8 million or 50%. 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, NSTAR's retail electric subsidiaries are only
purchasing enough power to meet obligations to their retail and wholesale
customers. NSTAR has no excess power supply to sell into the New England Power
Pool.
Gas revenues were $108.1 million in 1999 representing 4 months of revenues from
ComGas from the date of the merger.
Operating Expenses
Fuel, purchased power and cost of gas sold expense was $794.7 million in 1999
compared to $567.8 million in 1998, an increase of $226.9 million or 40%. 1999
reflects an increase of $151.2 million representing 4 months of expenses from
the former COM/Energy subsidiaries from the date of the merger. Without the
impact of the merger, fuel, purchased power and cost of gas sold would have been
$643.5 million in 1999, an increase from 1998 of $75.7 million or 13%. 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. NSTAR's retail electric companies
adjust their 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 expense 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
21
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 1999. Fuel expense related to
Pilgrim decreased $17 million due to the 1999 refueling outage and the sale of
the plant in July 1999.
Operations and maintenance expense was $353.8 million in 1999 compared to $382.4
million in 1998, a decrease of $28.6 million or 7%. 1999 reflects an increase of
$73.7 million representing 4 months of expenses from the former COM/Energy
subsidiaries from the date of the merger. Without the impact of the merger,
operations and maintenance expense would have been $280.1 million in 1999, a
decrease from 1998 of $102.3 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 $9 million in expenses reflecting the
discontinued operations of two unregulated subsidiaries.
Depreciation and amortization expense was $210.3 million in 1999 compared to
$195.6 million in 1998, an increase of $14.7 million or 8%. 1999 reflects an
increase of $18.7 million representing 4 months of expenses from the former
COM/Energy subsidiaries from the date of the merger. Without this impact,
depreciation and amortization would have been $191.6 million in 1999, a decrease
from 1998 of $4 million or 2%. This decrease reflects amortization of the gain
on the sale of the fossil plants that began in June 1998. These decreases are
partially offset by an increase of $8 million resulting from the amortization of
goodwill and costs to achieve related to the merger and an increase of $11
million reflecting a reduction in the carrying amount of nonutility property.
Demand side management (DSM) and renewable energy programs expense was $63.4
million in 1999 compared to $51.8 million in 1998, an increase of $11.6 million
or 22%. 1999 reflects an increase of $6 million representing 4 months of
expenses from the former COM/Energy subsidiaries from the date of the merger.
Without the impact of the merger, DSM and renewable energy programs expense
would have been $57.4 million, an increase from 1998 of $5.6 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 $77.8 million in 1999 compared to $84.1 million in
1998, a decrease of $6.3 million or 7%. 1999 reflects an increase of $8.9
million representing 4 months of expenses from the former COM/Energy
subsidiaries from the date of the merger. Without the impact of the merger,
property and other taxes would have been $68.9 million, a decrease from 1998 of
$15.2 million or 18%. This decrease reflects a lower municipal property taxes
resulting from the divesture of the fossil and nuclear generating facilities.
Other Income (Expense), net
Other income, net of tax was $9 million in 1999 compared to other expense, net
of $11.8 million in 1998, a net increase in income of $20.8 million. Prior to
the consideration of tax benefits, other expense was $18.6 million in 1999
compared to $35.9 million in 1998. 1999 reflects an increase of $1.4 million
reflecting 4 months of expense from the former COM/Energy subsidiaries from the
date of the merger. Without the impact of the merger, other expense would have
been $17.2 million in 1999. NSTAR's equity loss in the RCN joint venture was
$16.2 million in 1999 compared to its total equity losses from both the RCN and
EnergyVision joint ventures in 1998 of $19.7 million. 1999 reflects $7 million
of non-recoverable expenses related to the
22
Pilgrim plant divestiture. 1998 reflects $23.2 million of costs related to the
fossil plants divestiture. 1998 also reflects an additional $3.5 million of
costs related to discontinued operations of a Boston Energy Technology Group
(BETG) subsidiary, Coneco Corporation, 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 $5.6 million of interest income
in 1999 compared to $7.6 million in 1998, a decrease of $2 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 $0.4 million in 1999
compared to $5.5 million in 1998. Income tax benefits related to other
income/expense was $27.6 million in 1999 and $24.1 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 $104.6 million in 1999 compared to $83 million in 1998, an increase of $21.6
million or 26%. 1999 reflects an increase of $13 million representing 4 months
of expenses from the former COM/Energy subsidiaries from the date of the merger.
Without the impact of the merger, interest on long-term debt and transition
property securitization certificates was $91.6 million in 1999, an increase from
1998 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.
Interest on short-term and other debt was $23.8 million in 1999 compared to $8.8
million in 1998, an increase of $15 million or 170%. 1999 reflects an increase
of $9.2 million representing 4 months of expenses from the former COM/Energy
subsidiaries from the date of the merger. The remaining increase primarily
reflects increased borrowings from the revolving line of credit agreements to
finance shares repurchased in connection with the merger, the common share
repurchase program and investments in unregulated subsidiaries.
Preferred dividends of a subsidiary 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. All of COM/Energy's
preferred stock was redeemed prior to the merger.
1998 versus 1997
Basic and diluted earnings per common share were $2.76 and $2.75, respectively,
in 1998 compared to $2.71 and $2.71, respectively, in 1997, a 1.8% increase in
basic earnings as described below. Results of 1998 and 1997 only reflect BEC.
23
Operating Revenues
Operating revenues decreased 8.8% from 1997 as follows:
(in thousands)
- --------------------------------------------------------------------------------
Retail revenues $(148,272)
Wholesale revenues (3,721)
Electric short-term sales and other revenues (4,023)
- --------------------------------------------------------------------------------
Decrease in operating revenues $(156,016)
================================================================================
Retail revenues were $1,375.1 million in 1998 compared to $1,523.4 million in
1997, a decrease of $148.3 million or 10%. Retail revenues reflected the impact
of the mandated 10% retail rate reduction. A 2% increase in retail kWh sales in
1998 partially offset the impact of the rate reduction. Retail revenues also
reflected a decrease due to the timing effect of fuel and purchased power cost
recovery. Prior to its cessation as of March 1, 1998, the fuel clause charge was
lower than the prior year as the 1997 charge reflected the recovery of
substantial prior year under-collections. Fuel clause revenues were offset by
fuel and purchased power expenses and, therefore, had no net effect on earnings.
Short-term sales and other revenues were $105.4 million in 1998 compared to
$109.4 million in 1997, a decrease of $4 million or 4%. Boston Edison
experienced a $20 million decrease in short-term power sales revenues consistent
with an 11% reduction in short-term kWh sales, primarily as a result of the
expiration of certain short-term sales contracts. The decrease had no net impact
on earnings as it was offset by a corresponding decrease in fuel and purchased
power expenses. Additional decreases included a $2 million decrease from Boston
Edison's Harbor Electric Energy Company subsidiary and a $2 million decrease
from BETG. These decreases were partially offset by the recognition of $20
million of revenue related to the support of standard offer service provided by
Boston Edison's fossil generating units prior to divestiture.
Operating Expenses
Fuel and purchased power expense was $567.8 million in 1998 compared to $679.1
million in 1997, a decrease of $111.3 million or 16%. Fuel expense related to
fossil generation units decreased approximately $161 million. This decrease
reflected the divestiture of those units in May 1998. Purchased power expense
increased approximately $94 million, an increase of 26%. This increase reflected
Boston Edison's purchased power requirements in the absence of its fossil
generating units. Prior to the retail access date, the fuel and purchased power
clause component of its electric rates allowed Boston Edison to adjust its rates
to fully collect fuel and purchased power costs. Since the retail access date,
Boston Edison adjusts its electric rates to collect the costs related to fuel
and purchased power from customers on a fully reconciling basis. Boston Edison's
fuel and purchased power expense reflects a reduction of $7 million in 1998 and
an increase of $37 million in 1997 related to these rate recovery mechanisms.
Due to the rate adjustment mechanisms, changes in the amount of fuel and
purchased power expense have no net impact on earnings.
Operations and maintenance expense was $382.4 million in 1998 compared to $423
million in 1997, a decrease of $40.6 million or 10%. The most significant
component of this decrease was a $28 million decrease in power production
expenses primarily due to the fossil plant divestiture in May 1998. Employee
benefit expenses decreased by approximately $24 million due to lower pension and
other postretirement benefit costs. These favorable impacts were partially
offset by a $4 million increase in general and administrative expenses primarily
due to spending related to electric industry restructuring and the year 2000
computer issue and a $7 million increase in expenses related to parent company
costs and unregulated ventures.
Depreciation and amortization expense was $195.6 million in 1998 compared to
$189.5 million in 1997, an increase of $6.1 million or 3%. Depreciation on
24
distribution utility plant increased approximately $10 million, as Boston Edison
was required to increase this depreciation under the terms of its settlement
agreement. This increase was partially offset by an $8.7 million nonrecurring
charge recorded in 1997 to reflect the removal of specific nuclear-related
intangible assets from the Consolidated Balance Sheets. These intangible assets
related to costs incurred for plant design and safety studies and were
superceded by updated studies.
DSM and renewable energy programs expense was $51.8 million in 1998 compared to
$29.8 million in 1997, an increase of $22 million or 74%. This higher expense
reflects an increase in the required spending for DSM programs in 1998. In
addition, the renewable energy programs expense of $8 million in 1998 was the
result of a new state mandate for the funding of renewable energy that became
effective March 1, 1998. These costs are collected from customers on a fully
reconciling basis.
Property and other taxes were $84.1 million in 1998 compared to $106.4 million
in 1997, a decrease of $22.3 million or 21%. The decrease was due to a reduction
in municipal property taxes resulting from the divestiture of the fossil plants
assets.
Operating income taxes were $97.8 million in 1998 compared to $93.7 million in
1997, an increase of $4.1 million or 4%. The increase in operating income taxes
was primarily the result of a $4 million reduction in investment tax credit
amortization due to the divestiture of the fossil generating assets and
non-deductible expenses incurred at BETG.
Other Income (Expense), net
Other expense, net of tax was $11.8 million in 1998 compared to $6.4 million in
1997, an increase of $5.4 million or 84%. Prior to the consideration of tax
benefits, other expenses were $35.9 million in 1998 compared to $17.7 million in
1997, an increase of $18.2 million. BETG's equity losses in the RCN and
EnergyVision joint ventures were $19.7 million in 1998 compared to $9.2 million
in 1997. The $10.5 million increase was primarily due to RCN which began
operations in the second quarter of 1997. 1998 also reflects $23.2 million of
costs related to the fossil divestiture that is offset by the recognition of
investment tax credits disclosed below, $3.5 million related to discontinued
operations of BETG's subsidiary, Coneco Corporation and $2.6 million of costs
associated with the referendum that sought to repeal the Massachusetts Electric
Restructuring Act. These negative amounts are offset in 1998 by $7.6 million of
interest income due to levels of cash on hand as a result of the proceeds from
the fossil plant divestiture. In addition, 1997 results reflect a charge of
$12.9 million from a nuclear asset impairment. Offsetting the negative impacts
in 1997 was $5 million of interest income received related to the favorable
outcome of an IRS audit. Other miscellaneous income was $5.5 million in 1998 and
other miscellaneous expense was $0.6 million in 1997. Income tax benefits
related to other expenses were $24.1 million in 1998 and $11.3 million in 1997.
The 1998 income tax benefit included $10.9 million related to the recognition of
previously deferred investment tax credits associated with the fossil generating
stations.
Interest Charges
Interest charges on long-term debt were $83 million in 1998 compared to $92.5
million in 1997, a decrease of $9.5 million or 10%. The decrease reflects $6
million due to the maturing of $100 million of 5.95% debentures in March 1998
and the cessation of amortization of the associated redemption premiums as well
as, $2 million due to the redemption of a $100 million, 6.662% bank loan in June
1998.
25
Short-term interest charges were $8.8 million in 1998 compared to $14.6 million
in 1997, a decrease of $5.8 million or 40%. Approximately $7 million of the
decrease is due to the redemption of Boston Edison's outstanding short-term debt
with proceeds from the fossil divestiture. This was partially offset by $1
million in interest charges from BEC's line of credit entered into in 1998.
Preferred Stock Dividends
Preferred stock dividends were $8.8 million in 1998 compared to $13.1 million in
1997, a decrease of $4.3 million or 33%. Preferred stock dividends decreased $1
million as a result of Boston Edison's redemption of 40,000 shares of 7.27%
series cumulative preferred stock in May 1998 and 1997 and the remaining 320,000
shares in July 1998. An additional $3 million decrease was due to the redemption
of 400,000 shares of 7.75% series cumulative preferred stock in July 1998 and
400,000 shares of 8.25% series in June 1997.
Retail Electric Sales and Revenues
Retail kWh sales increased 18% in 1999. This increase includes an increase of
12% representing 4 months of former COM/Energy subsidiaries from the date of the
merger. Without the impact of the merger, 1999 kWh sales would have increased 5%
from 1998. This increase in retail kWh sales is primarily due to weather
conditions that favored electric sales as well as a continued 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 rates in the Boston area.
Total kWh sales increased 2.3% in 1998. The 2% increase in 1998 retail kWh sales
was primarily due to the positive impact of a continued strong local economy on
commercial customers. The Boston area commercial office vacancy rate was 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 was partially offset by the mild winter
weather conditions in the first quarter of 1998.
Gas Sales and Revenue
ComGas generates revenues primarily through the sale and transportation of
natural gas. Gas sales are divided into two categories; firm, whereby ComGas
must supply gas or gas transportation services to customers on demand; and
interruptible, whereby ComGas may, generally during colder months, temporarily
discontinue service to high volume commercial and industrial customers. Sales of
gas to interruptible customers do not materially affect ComGas' operating income
because substantially all margin on such sales is returned to its firm
customers.
ComGas' tariffs include a seasonal Cost of Gas Adjustment Clause (CGAC) and a
Local Distribution Adjustment Clause (LDAC) that provide for the recovery, from
firm customers or default service customers, of certain costs previously
recovered through base rates. The CGAC provides for rates that must be approved
semi-annually by the MDTE. The LDAC provides for rates that require annual
approval.
ComGas' sales are positively impacted by colder weather because the majority
of customers use natural gas for space heating purposes.
Of ComGas' 1999 firm gas unit sales, 64.1% was sold to residential customers,
27.4% to commercial customers, 4.2% to industrial customers and 4.3% to other
customers.
26
Liquidity and Capital Resources
During 1999, 1998 and 1997 internal generation of cash provided 174%, 97% and
211%, respectively, of plant expenditures. Internally generated funds
consist of cash flows from operating activities, adjusted to exclude changes in
working capital and the payment of dividends. NSTAR companies supplement
internally generated funds as needed, primarily through the issuance of
short-term commercial paper and bank borrowings.
The capital spending level forecasted for 2000 is $347 million, which includes
amounts for utility plant and the capital requirements of nonutility ventures.
The capital spending level over the next four years is forecasted to be
approximately $673 million. In addition to capital expenditures, long-term debt
principal (including securitized debt) and preferred stock payment requirements
will be approximately $251 million in 2000, $123 million in 2001, $109 million
in 2002, $241 million in 2003 and $79 million in 2004.
In February 2000, NSTAR issued $300 million of long-term debt that was used to
reduce short-term borrowings. NSTAR has a $450 million revolving credit
agreement with a group of banks effective through November 2002. As of December
31, 1999, $350 million of short-term debt was outstanding under this credit
agreement. The purpose of this agreement is to provide financing for general
corporate purposes, to fund the common share repurchase program and for funding
NSTAR's unregulated subsidiary ventures.
In April 1998, Boston Edison announced a common share repurchase program under
which it would repurchase up to four million of its common shares. NSTAR assumed
this program effective as of the merger date. In October 1999, this program was
completed by NSTAR. Four million shares were repurchased at a total cost of
approximately $157 million. NSTAR subsequently announced a new $300 million
common share repurchase program. Under both programs, shares are repurchased
through open market, block or privately-negotiated transactions, or a
combination. The timing and actual number of shares repurchased will be impacted
by market conditions.
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 backup to Boston
Edison's $200 million commercial paper program. Boston Edison had no short-term
debt outstanding as of December 31, 1999.
The former subsidiaries of COM/Energy have $147 million available under several
lines of credit. Approximately $108 million was outstanding under these lines of
credit 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 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 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
27
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.
NSTAR's goal is to maintain a capital structure that preserves an appropriate
balance between debt and equity. Management believes its liquidity and capital
resources are sufficient to meet its current and projected requirements.
Refer to the Consolidated Financial Statements for more information regarding
the NSTAR companies' current financing activities.
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. Approximately 27% and 20% of BEC's and COM/Energy's systems,
respectively, required modification or replacement.
NSTAR also inventoried important business systems that were date-sensitive and
determined that approximately one-third of BEC's systems and approximately 90%
of COM/Energy'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 and approximately 90% of COM/Energy'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. NSTAR has expended a total of approximately
$39 million on this project through December 31, 1999.
In addition to its internal efforts, BEC and COM/Energy 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, NSTAR 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
28
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 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 arises in 2000
(or beyond), these contingency plans would become effective in order to
remediate the problem.
Joint Venture with RCN Telecom Services, Inc. of Massachusetts
In 1997 BETG, a subsidiary of NSTAR, entered into a joint venture agreement
with RCN Telecom Services, Inc. of Massachusetts (RCN) establishing a limited
liability company (LLC) to compete directly with local and long-distance
telephone, video and internet access companies for telecommunications-related
services.
BETG is responsible under the original joint venture agreement for 49% of the
capital requirements of the LLC, while RCN is responsible for 51% and maintains
the day-to-day management. BETG follows the equity method of accounting for its
interest in the LLC. As part of the joint venture agreement, BETG has the option
to exchange portions of its joint venture interest for shares of RCN common
stock. In January 1998, BETG exercised its option to convert a portion of its
interest at a cost of $11 million. As a result of the conversion, BETG received
approximately 1.1 million shares of RCN common stock during the first quarter of
1999. In May 1999, BETG exercised its option to convert an additional portion of
its interest with a book value of approximately $90 million for additional RCN
common stock. On January 24, 2000, BETG received notification that it would
receive approximately 3 million shares of RCN common stock as a result of this
latest conversion. To date, BETG has converted a portion of its joint venture
interest with a book value of approximately $101 million in return for
approximately 4.1 million RCN common shares with a fair value of approximately
$270 million (based on the January 24, 2000 closing price).
Other Matters
Environmental
Various subsidiaries of NSTAR are involved in approximately 30 properties where
oil or other hazardous materials were spilled or released. As such, the
companies are 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. NSTAR subsidiaries also face possible
liability as a potentially responsible party (PRP) in the cleanup of six
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. NSTAR currently expects to have only a small percentage of the total
potential liability for these sites. Through December 31, 1999, NSTAR had
approximately $6.6 million accrued on its Consolidated Balance Sheets related to
these cleanup liabilities. Management is unable to fully determine a range of
reasonably possible cleanup costs in excess of the accrued amount. Based on
preliminary assessments of the specific site circumstances, management does not
believe that it is probable that any such additional costs will have a material
impact on NSTAR's consolidated financial position. However, it is reasonably
possible that additional provisions for cleanup costs that may result from a
change in estimates could have a material impact on the results of a reporting
period in the near term.
29
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,
the buyer 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.
NSTAR 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. NSTAR continues to
monitor all aspects of the EMF issue.
ComGas is participating in the assessment of a number of former manufactured gas
plant (MGP) sites and alleged MGP waste disposal locations to determine if and
to what extent such sites have been contaminated and whether ComGas may be
responsible for remedial action. As of December 31, 1999, ComGas has recorded a
liability and corresponding regulatory asset amounting to $2.2 million as an
estimate for site cleanup costs for several MGP sites for which ComGas was
previously cited. The MDTE has approved recovery of costs associated with MGP
sites.
Estimates related to environmental remediation costs are reviewed and adjusted
periodically as further investigation and assignment of responsibility occurs.
NSTAR is unable to estimate its ultimate liability for future environmental
remediation costs. However, in view of NSTAR'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 NSTAR's financial position or results of operations for a
reporting period.
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. 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, NSTAR
subsidiaries have been named as defendants 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 that permitted the formation of BETG and
30
authorized Boston Edison to invest up to $45 million in unregulated activities.
Hearings 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
had 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 NSTAR and its subsidiaries are also
involved in certain other legal matters. Management is unable to fully determine
a range of reasonably possible legal costs in excess of amounts accrued. Based
on the information currently available, it does not believe that it is probable
that any such additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period.
Employees
As of December 31, 1999, NSTAR's subsidiaries had approximately 3,400 full-time
employees, including approximately 2,300 (68%) employees represented by various
collective bargaining units covered by separate contracts. The contracts with
two union locals, representing approximately 1,300 employees of the Utility
Workers Union of America, AFL-CIO, terminate on May 15, 2000. Other collective
bargaining units' contracts expire at various dates through April 2003.
Management believes it has satisfactory employee relations.
Interest rate risk
NSTAR is exposed to changes in interest rates. Carrying amounts and fair values
of mandatory redeemable cumulative preferred stock, and indebtedness (excluding
notes payable) as of December 31, 1999, was as follows:
Weighted
Carrying Fair Average
(in thousands) Amount Value Interest Rate
- --------------------------------------------------------------------------------
Mandatory redeemable cumulative
preferred stock $ 49,279 $ 52,250 8.0%
Indebtedness 1,854,794 $1,842,373 7.25%
31
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.
NSTAR will adopt SFAS 133 as of January 1, 2001. The impact of adoption cannot
be currently estimated and will be dependent upon the value, nature and purpose
of the derivative instruments held, if any, as of January 1, 2001.
Safe harbor cautionary statement
NSTAR 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, NSTAR 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.
32
Item 7A Quantitative and Qualitative Disclosures About Market Risk
Although NSTAR has material commodity purchase contracts and financial
instruments (debt), these instruments are not subject market risk. NSTAR's
electric and gas distribution subsidiaries have rate making mechanisms which
allow for the recovery of fuel costs from customers. The fuel adjustment
mechanisms allow NSTAR's subsidiaries to pass all costs related to the purchase
of commodities to the customer, thereby insulating NSTAR from market risk.
Similarly, any change in the fair market value of NSTAR's prudently incurred
debt obligations realized by NSTAR would be borne by customers through future
rates.
33
Item 8. Financial Statements and Supplementary Financial Information
Consolidated Statements of Income
years ended December 31,
(in thousands, except earnings per share) 1999 1998 1997
- -------------------------------------------------------------------------------------
Operating revenues $1,851,427 $1,622,515 $1,778,531
- -------------------------------------------------------------------------------------
Operating expenses:
Fuel, purchased power 794,748 567,806 679,131
and cost of gas sold
Operations and maintenance 353,768 382,434 423,040
Depreciation and amortization 210,306 195,607 189,489
Demand side management and
renewable energy programs 63,425 51,839 29,790
Taxes-property and other 77,761 84,091 106,428
Income taxes 87,721 97,798 93,709
- -------------------------------------------------------------------------------------
Total operating expenses 1,587,729 1,379,575 1,521,587
- -------------------------------------------------------------------------------------
Operating income 263,698 242,940 256,944
Other income (expense), net 8,965 (11,811) (6,392)
- -------------------------------------------------------------------------------------
Operating and other income 272,663 231,129 250,552
- -------------------------------------------------------------------------------------
Interest charges:
Long-term debt 84,196 82,951 92,489
Transition property securitization
certificates 20,408 0 0
Other 23,760 8,800 14,610
Allowance for borrowed funds used
during construction (AFUDC) (2,164) (1,668) (1,189)
- -------------------------------------------------------------------------------------
Total interest charges 126,200 90,083 105,910
- -------------------------------------------------------------------------------------
Net income 146,463 141,046 144,642
Preferred stock dividends of subsidiary 5,960 8,765 13,149
- -------------------------------------------------------------------------------------
Earnings available for common
shareholders $ 140,503 $ 132,281 $ 131,493
=====================================================================================
Weighted average common shares outstanding:
Basic 50,796 47,973 48,515
Diluted 50,921 48,149 48,562
Earnings per common share:
Basic $ 2.77 $ 2.76 $ 2.71
Diluted $ 2.76 $ 2.75 $ 2.71
The accompanying notes are an integral part of the consolidated financial
statements.
Consolidated Statements of Comprehensive Income
years ended December 31,
(in thousands) 1999 1998 1997
- -------------------------------------------------------------------------------------
Net income $ 146,463 $ 141,046 $ 144,642
Other comprehensive income, net:
Unrealized gain on investments 20,115 0 0
Comprehensive income $ 166,578 $ 141,046 $ 144,642
=====================================================================================
34
Consolidated Statements of Retained Earnings
years ended December 31,
(in thousands) 1999 1998 1997
- ------------------------------------------------------------------------------------
Balance at the beginning of the year $ 360,509 $ 328,802 $ 292,191
Net income 146,463 141,046 144,642
- ------------------------------------------------------------------------------------
Subtotal 506,972 469,848 436,833
- ------------------------------------------------------------------------------------
Dividends declared:
Common shares 103,099 90,610 91,208
Preferred stock 5,960 8,765 13,149
- ------------------------------------------------------------------------------------
Subtotal 109,059 99,375 104,357
- ------------------------------------------------------------------------------------
Provision for preferred stock
redemption and issuance costs (a) 239 7,833 3,674
Common share repurchase program 7,685 2,131 0
- ------------------------------------------------------------------------------------
Balance at the end of the year $ 389,989 $ 360,509 $ 328,802
====================================================================================
(a) Refer to Note A. to the Consolidated Financial Statements.
The accompanying notes are an integral part of the consolidated financial
statements.
35
Consolidated Balance Sheets
December 31,
(in thousands) 1999 1998
- -----------------------------------------------------------------------------------------------------------------
Assets
Utility plant in service, at
original cost $3,787,295 $2,720,681
Less: accumulated depreciation 1,303,893 $2,483,402 926,020 $1,794,661
- -----------------------------------------------------------------------------------------------------------------
Construction work in progress 67,217 40,965
- -----------------------------------------------------------------------------------------------------------------
Net utility plant 2,550,619 1,835,626
Nonutility property 115,270 21,565
Goodwill 485,990 0
Nuclear decommissioning trust 3,885 172,908
Equity investments 173,290 84,770
Other investments 66,057 30,206
Current assets:
Cash and cash equivalents 168,599 89,126
Restricted cash 147,941 0
Accounts receivable, net of
allowance of $22,699 and $9,066
in 1999 and 1998, respectively 392,702 202,275
Accrued unbilled revenues 34,013 14,322
Fuel, materials and supplies,
at average cost 48,756 10,731
Prepaid expenses and other 251,222 1,043,233 92,405 408,859
- -----------------------------------------------------------------------------------------------------------------
Deferred debits:
Regulatory assets 879,547 623,187
Other 164,997 26,915
- -----------------------------------------------------------------------------------------------------------------
Total assets $5,482,888 $3,204,036
=================================================================================================================
Capitalization and Liabilities
Common equity $1,523,532 $1,051,898
Accumulated other comprehensive income, net 20,115 0
Cumulative preferred stock of subsidiary 92,279 92,040
Long-term debt 986,843 955,563
Transition property securitization
certificates 646,559 0
Current liabilities:
Long-term debt
due within one year $ 170,470 $ 667
Transition property securitization
certificates, due within one year 50,922 0
Notes payable 458,000 78,000
Accounts payable 193,937 100,331
Accrued interest 21,830 20,516
Dividends payable 29,871 23,878
Other 271,191 1,196,221 183,664 407,056
- -----------------------------------------------------------------------------------------------------------------
Deferred credits:
Accumulated deferred income taxes 608,587 348,557
Accumulated deferred investment
tax credits 41,946 45,930
Nuclear decommissioning liability 0 176,578
Power contracts 100,741 58,415
Other 266,065 67,999
Commitments and contingencies
- -----------------------------------------------------------------------------------------------------------------
Total capitalization and liabilities $5,482,888 $3,204,036
=================================================================================================================
The accompanying notes are an integral part of the consolidated financial
statements.
36
Consolidated Statements of Cash Flows
years ended December 31,
(in thousands) 1999 1998 1997
- -----------------------------------------------------------------------------------------------------------
Operating activities:
Net income $ 146,463 $ 141,046 $ 144,642
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation and amortization 212,880 229,668 223,529
Deferred income taxes and investment tax
credits 88,174 (152,798) (21,664)
Allowance for borrowed funds used during
construction (2,164) (1,668) (1,189)
Power contract buy out (65,781) 0 0
Net changes (net of effect of acquisition) in:
Accounts receivable and accrued
unbilled revenues (96,909) 20,544 45,678
Fuel, materials and supplies, at average cost (2,192) 29,565 (5,486)
Accounts payable 19,469 13,316 (47,068)
Other current assets and liabilities (87,032) (33,535) 25,428
Other, net (29,548) 18,851 (4,640)
- -----------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 183,360 264,989 359,230
- -----------------------------------------------------------------------------------------------------------
Investing activities:
Plant expenditures (excluding AFUDC) (159,295) (120,202) (114,110)
Costs of nuclear divestiture, net (87,248) 0 0
Proceeds from sale of fossil generating assets 0 533,633 0
Nuclear fuel expenditures (16,117) (26,182) (4,089)
Investments (82,403) (81,589) (27,689)
Payment for cost of acquisition,
net of cash acquired (296,262) 0 0
- -----------------------------------------------------------------------------------------------------------
Net cash (used in) provided by investing activities (641,325) 305,660 (145,888)
- -----------------------------------------------------------------------------------------------------------
Financing activities:
Proceeds from transition property securitization 725,000 0 0
Issuances/(repurchases):
Common shares (189,715) (53,285) 144
Long-term debt 20,000 0 100,000
Redemptions:
Preferred stock 0 (71,519) (44,000)
Long-term debt (255,361) (201,600) (101,600)
Net change in notes payable 340,550 (59,013) (64,441)
Dividends paid (103,036) (100,246) (104,956)
- -----------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 537,438 (485,663) (214,853)
- -----------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and cash
equivalents 79,473 84,986 (1,511)
Cash and cash equivalents at the
beginning of the year 89,126 4,140 5,651
- -----------------------------------------------------------------------------------------------------------
Cash and cash equivalents at the end of the year $ 168,599 $ 89,126 $ 4,140
===========================================================================================================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 125,840 $ 89,720 $ 100,795
Income taxes $ 36,092 $ 230,260 $ 99,326
Supplemental disclosure of investing activity:
Common shares issued for
Acquisition of COM/Energy 20,251 0 0
The accompanying notes are an integral part of the consolidated financial
statements.
37
Notes to Consolidated Financial Statements
Note A. Summary of Significant Accounting Policies
1. General Information
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.
NSTAR is focusing its utility operations on the transmission and distribution of
energy. This is illustrated by the sale of the majority of NSTAR's subsidiaries
fossil generating assets and the Pilgrim Nuclear Power Station.
2. Basis of Consolidation and Accounting
The accompanying consolidated financial statements reflect the results of
operations, comprehensive income and cash flows of NSTAR and its subsidiaries.
All significant inter-company transactions have been eliminated. Certain
reclassifications have been made to the prior year data to conform with the
current presentation.
NSTAR's utility subsidiaries follow accounting policies prescribed by the
Federal Energy Regulatory Commission (FERC) and the Massachusetts Department of
Telecommunications and Energy (MDTE). In addition, NSTAR and its subsidiaries
are subject to the accounting and reporting requirements of the Securities and
Exchange Commission (SEC). The accompanying consolidated financial statements
conform with Generally Accepted Accounting Principles (GAAP). The rate-regulated
subsidiaries are subject to Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71). The
application of SFAS 71 results in differences in the timing of recognition of
certain expenses from that of other businesses and industries. The distribution
business remains subject to rate-regulation and continues to meet the criteria
for application of SFAS 71. Refer to Note E 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 NSTAR
and its subsidiaries to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from these estimates.
38
3. Revenues
Estimates of transmission and distribution revenues for electricity and natural
gas 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
Depreciation of utility plant is computed on a straight-line basis using
composite rates based on the estimated useful lives of the various classes of
property. The overall composite depreciation rates were 3.31%, 3.28% and 3.30%
in 1999, 1998 and 1997, respectively. Depreciation of nonutility property is
computed on a straight-line basis over the estimated life of the asset.
6. Costs Associated with Issuance and Redemption of Debt and Preferred Stock
Consistent with the recovery in utility rates, discounts, redemption premiums
and related costs associated with the issuance and redemption of long-term debt
and preferred stock are deferred. The costs related to long-term debt are
recognized as an addition to interest expense over the life of the original or
replacement debt. Consistent with an accounting order received from the FERC,
costs related to preferred stock issuances and redemptions are reflected as a
direct reduction to retained earnings upon redemption or over the average life
of the replacement preferred stock series as applicable.
7. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant construction. In
accordance with regulatory accounting, AFUDC is included as a cost of utility
plant and a reduction of current interest charges. Although AFUDC is not a
current source of cash income, the costs are recovered from customers over the
service life of the related plant in the form of increased revenues collected as
a result of higher depreciation expense. Average AFUDC rates in 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. Restricted cash represents the net
proceeds from the sale of Canal Electric Company's generation assets that are
being used to reduce the transition costs that otherwise would be billed to
customers.
9. Equity Method of Accounting
NSTAR uses the equity method of accounting for investments in corporate joint
ventures in which it does not have a controlling interest. Under this
39
method, it records as income or loss the proportionate share of the net earnings
or losses of the joint ventures with a corresponding increase or decrease in the
carrying value of the investment. The investment is reduced as cash dividends
are received.
10. Regulatory Assets
Regulatory assets represent costs incurred that are expected to be collected
from customers through future charges in accordance with agreements with
regulators. These costs are expensed when the corresponding revenues are
received in order to appropriately match revenues and expenses.
Regulatory assets consist of the following:
December 31,
(in thousands) 1999 1998
- --------------------------------------------------------------------------------
Generation-related regulatory assets, net $559,446 $477,317
Power contracts 96,911 58,415
Income taxes, net 65,867 52,168
Merger costs 79,681 0
Redemption premiums 16,014 23,419
Postretirement benefits costs and pension 25,164 8,769
Other 36,464 3,099
- --------------------------------------------------------------------------------
$879,547 $623,187
================================================================================
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. 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.
Based on unaudited data, the following pro forma summary presents the
consolidated results of operations for years ended December 31, 1999 and 1998
40
as if the merger had occurred at the beginning of the years presented. These
results do not reflect future cost savings or avoidances expected from the
merger.
(in thousands, except per share amounts)
Year Ended Year Ended
December 31, 1999 December 31, 1998
- -------------------------------------------------------------------------------
Revenues $2,419,433 $2,537,907
Earnings available for
Common shareholders $136,782 $158,294
Weighted average common shares
Basic 61,258 63,688
Diluted 61,397 63,864
Earnings per common share
Basic $2.23 $2.49
Diluted $2.23 $2.48
The pro forma results do not purport to be indicative of the results of
operations that actually would have resulted had the merger occurred at the
beginning of the year presented, or of results that may occur in the future,
including the future cost savings resulting from the merger.
Note C. Earnings Per Common Share
Basic earnings per common share (EPS) is calculated by dividing net income,
after deductions for preferred dividends, by the weighted average common shares
outstanding during the year. Statement of Financial Accounting Standards No.
128, "Earnings per Share", requires the disclosure of diluted EPS. Diluted EPS
is similar to the computation of basic EPS except that the weighted average
common shares is increased to include the number of dilutive potential common
shares. Diluted EPS reflects the impact on shares outstanding of the deferred
(nonvested) shares and stock options granted under the NSTAR's Stock Incentive
Plan.
The following table summarizes the reconciling amounts between basic and diluted
EPS:
(in thousands, except per share amounts) 1999 1998 1997
- --------------------------------------------------------------------------------
Earnings available for common shareholders $140,503 $132,281 $131,493
Basic EPS $2.77 $2.76 $2.71
Diluted EPS $2.76 $2.75 $2.71
Weighted average common shares outstanding
for basic EPS 50,796 47,973 48,515
Effect of dilutive shares:
Weighted average dilutive potential common
shares 125 176 47
- --------------------------------------------------------------------------------
Weighted average common shares outstanding
for diluted EPS 50,921 48,149 48,562
================================================================================
41
Note D. RCN Joint Venture and Investment Conversion
Boston Energy Technology Group (BETG), a subsidiary of NSTAR through NSTAR
Communications, Inc. (NSTAR COM)(formerly known as BecoCom,Inc.) is a
participant in a telecommunications venture with RCN Telecom Services, Inc. of
Massachusetts (RCN). NSTAR accounts for its investment in the joint venture
using the equity method of accounting. As part of the joint venture agreement,
NSTAR has the option to exchange portions of its joint venture interest for
shares of RCN common stock at specified periods. During 1998, NSTAR exercised
its option to convert a portion of its interest. In the first quarter of 1999,
NSTAR received 1.1 million shares of RCN common stock in exchange for a portion
of its joint venture interest that had a book value of $11 million. The RCN
shares received are included in other investments on the accompanying
Consolidated Balance Sheets at their fair value of approximately $54 million at
December 31, 1999. The unrealized gain due to the increase in fair value on
these shares since they were received is reflected, net of associated income
taxes, as comprehensive income on the accompanying Consolidated Statements of
Comprehensive Income and the accompanying Consolidated Balance Sheets.
Note E. Electric Utility Industry Restructuring
1. Accounting Implications
Under the traditional revenue requirements model, electric rates have been based
on the cost of providing electric service. Under this model, NSTAR retail
electric companies have 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 Law enacted in November 1997 and the MDTE
order regarding retail electric companies settlement agreement, as of December
31, 1997, the provisions of SFAS 71 were no longer being applied to Boston
Edison's generation business. NSTAR's remaining generation business, Canal
Electric Company's 3.52% ownership interest in the Seabrook Nuclear Power Plant
is subject to the provisions of SFAS 71.
The implementation of electric utility industry restructuring had certain
accounting implications. The highlights of these include:
a. Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation business, are
recovered through the transition charge. This recovery, which includes a return,
occurs over a 12 year period for Boston Edison and an 11 year period for the
former COM/Energy retail electric companies that began on March 1, 1998 (the
retail access date).
b. 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 is being returned to
customers through March 31, 2000. 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 Sheets.
42
c. Standard offer charge
Customers have the option of continuing to buy power from the retail electric
delivery businesses at standard offer prices as of the retail access date. 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.
d. Distribution and transmission charges
An integral part of the merger is the rate plan that was filed by the retail
utility subsidiaries of BEC and COM/Energy and approved by the MDTE on July 27,
1999. Significant elements of the rate plan include a four-year distribution
rate freeze, recovery of the acquisition premium (goodwill) over 40 years and
recovery of transaction and integration costs (costs to achieve) over 10 years.
Boston Edison distribution rates are subject to a minimum and maximum return on
average common equity (ROE) from its distribution business 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 all NSTAR electric distribution customers is recovered on a fully
reconciling basis.
2. 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 contracts. 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 result of a favorable IRS tax ruling,
Boston Edison received $43 million from Entergy reflecting a reduction in the
required decommissioning funding. The difference between the total proceeds
received and the net book value of the Pilgrim assets sold plus the net amount
to fully fund the decommissioning trust is included in 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.
43
The amount received above net book value on the sale of these assets is being
returned to Boston Edison's customers over the settlement period.
On July 27, 1999 BEC Funding 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 Law and
authorized by the MDTE. These certificates are non-recourse to Boston Edison.
COM/Energy completed the sale of substantially all of its investment in electric
generation assets in 1998. Proceeds from the sale of these assets, after
construction-related adjustments at the closing that occurred on December 30,
1998, amounted to approximately $453.9 million or 6.1 times their book value of
approximately $74.2 million. The proceeds from the sale, net of book value,
transaction costs and certain other adjustments, amounted to $358.6 million and
is being used to reduce transition costs related to electric industry
restructuring that otherwise would have been collected from customers.
COM/Energy established Energy Investment Services, Inc. (EIS) as the vehicle to
invest the net proceeds from the sale of Canal Electric Company's generation
assets. These proceeds have been invested in a portfolio of securities that is
designed to maintain principal and earn a reasonable return. Both the principal
amount and income earned will be used to reduce the transition costs that would
otherwise be billed to customers of Cambridge Electric Light Company and
Commonwealth Electric Company. The net proceeds have been classified as
restricted cash on the accompanying Consolidated Balance Sheets.
Note F. 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 $71.1 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 $ 484,021 $ 412,358
Other 424,128 85,497
- -------------------------------------------------------------------------------
908,149 497,855
- -------------------------------------------------------------------------------
Deferred tax assets:
Plant-related 78,587 13,174
Investment tax credits 29,013 29,622
Other 191,962 106,502
- -------------------------------------------------------------------------------
299,562 149,298
- -------------------------------------------------------------------------------
Net accumulated deferred income taxes $ 608,587 $ 348,557
===============================================================================
44
No valuation allowances for deferred tax assets are deemed necessary.
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 $(33,121) $239,717 $ 115,373
Deferred income tax expense 123,393 (137,992) (14,104)
Investment tax credit amortization (2,551) (3,927) (7,560)
- -------------------------------------------------------------------------------
Income taxes charged to operations 87,721 97,798 93,709
- -------------------------------------------------------------------------------
Taxes on other income (27,580) (24,116) (11,254)
- -------------------------------------------------------------------------------
Total income tax expense $ 60,141 $ 73,682 $ 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 5.5 5.2 4.5
Investment tax credits (11.3) (6.9) (3.3)
Other (0.1) 1.0 0.1
- --------------------------------------------------------------------------------
Effective tax rate 29.1% 34.3% 36.3%
================================================================================
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 of generation
divestitures. Excluding these shareholder benefits, the effective tax rate would
have been approximately 39% in each year.
Note G. Pensions and Other Postretirement Benefits
Effective December 31, 1999, the pension and other postretirement benefit plans
of BEC and COM/Energy were combined under NSTAR.
1. Pensions
NSTAR has a defined benefit funded retirement plan with certain contributory
features that covers substantially all employees. NSTAR also maintains an
unfunded supplemental retirement plan for certain management employees.
Effective January 1, 2000, the defined benefit plan was amended to provide
management employees lump sum benefits under a final average pay pension equity
formula. Prior to January 1, 2000 these pension benefits were provided under a
traditional final average pay formula. This amendment is reflected in the
December 31, 1999 benefit obligation.
45
The changes in 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
COM/Energy obligation 401,902 0
Service cost 14,741 13,645
Interest cost 42,426 31,981
Plan participants' contributions 170 214
Plan amendments (12,697) 0
Actuarial (gain)/loss (62,464) 67,564
Curtailment loss/(gain) 18,424 (15,644)
Special termination benefits 15,712 665
Settlement payments (92,484) (16,246)
Benefits paid (25,470) (41,627)
- -------------------------------------------------------------------------------
Benefit obligation, end of the year $ 798,248 $ 497,988
===============================================================================
Change in plan assets:
Fair value of plan assets, beginning of
the year $ 474,552 $ 401,182
COM/Energy plan assets 395,783 0
Actual return on plan assets 143,116 44,589
Employer contribution 59,831 86,440
Plan participants' contributions 170 214
Settlement payments (92,484) (16,246)
Benefits paid (25,470) (41,627)
- -------------------------------------------------------------------------------
Fair value of plan assets, end of the year $ 955,498 $ 474,552
===============================================================================
The plans' funded status were as follows: December 31,
(in thousands) 1999 1998
- -------------------------------------------------------------------------------
Funded status $ 157,250 $ (23,436)
Unrecognized actuarial net (gain)/loss (59,909) 96,310
Unrecognized transition obligation 2,783 3,856
Unrecognized prior service cost 260 15,557
- -------------------------------------------------------------------------------
Net amount recognized $ 100,384 $ 92,287
===============================================================================
Amount recognized in the Consolidated Balance Sheets consisted of:
December,31,
(in thousands) 1999 1998
- -------------------------------------------------------------------------------
Prepaid retirement cost $ 125,664 $ 94,049
Accrued retirement liability (30,966) (9,856)
Intangible asset 5,686 8,094
- -------------------------------------------------------------------------------
Net amount recognized $ 100,384 $ 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,
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%
46
Components of net periodic benefit cost were as follows:
years ended December 31,
(in thousands) 1999 1998 1997
- -------------------------------------------------------------------------------
Service cost $ 14,741 $ 13,645 $ 12,625
Interest cost 42,426 31,981 31,537
Expected return on plan assets (53,059) (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 $ 9,976 $ 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 costs were $19,823,000, $930,000 and $15,712,000,
respectively, for 1999. As a result of the nuclear divestiture, amounts
recognized for curtailment and special termination benefit costs 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.
NSTAR also provides defined contribution 401(k) plans for substantially all
employees. Matching contributions included in the Consolidated Statements of
Income amounted to $9 million in 1999 and $8 million in 1998 and 1997,
respectively.
2. Other Postretirement Benefits
In addition to pension benefits, NSTAR also provides health care and other
benefits to retired employees who meet certain age and years of service
eligibility requirements. These benefits include health and life insurance
coverage and reimbursement of certain Medicare premiums. Under certain
circumstances, eligible employees are required to make contributions for
postretirement benefits. Effective January 1, 2000 the plan was amended to
include certain new managed care features. This amendment is reflected in the
December 31, 1999 benefit obligation.
The changes in benefit obligation and plan assets were as follows:
(in thousands) 1999 1998
- -------------------------------------------------------------------------------
Change in benefit obligation:
Benefit obligation, beginning of the year $ 258,756 $ 237,616
COM/Energy obligation 146,741 0
Service cost 4,505 3,892
Interest cost 21,896 16,895
Plan participants' contributions 37 1,178
Plan amendments (14,062) 0
Actuarial (gain)/loss (24,186) 27,845
Curtailment loss/(gain) 1,408 (14,665)
Special termination benefits 0 75
Settlement payments (5,810) 0
Benefits paid (18,371) (14,080)
- -------------------------------------------------------------------------------
Benefit obligation, end of the year $ 370,914 $ 258,756
===============================================================================
47
Change in plan assets:
Fair value of plan assets, beginning
of the year $ 113,818 $ 103,989
COM/Energy plan assets 73,558 0
Actual return on plan assets 23,337 14,344
Employer contribution 14,484 8,387
Plan participants' contributions 37 1,178
Settlement payments (5,810) 0
Benefits paid (18,371) (14,080)
- -------------------------------------------------------------------------------
Fair value of plan assets, end of the year $ 201,053 $ 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 $(169,861) $(144,938)
Unrecognized actuarial net (gain)/loss (9,524) 24,922
Unrecognized transition obligation 73,016 88,814
Unrecognized prior service cost (22,154) (9,827)
- -------------------------------------------------------------------------------
Net amount recognized $(128,523) $ (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.
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 $ 3,614 $ (2,936)
Effect on December 31, 1999 postretirement benefit
obligation $ 40,257 $(36,959)
Components of net periodic benefit cost were as follows:
years ended December 31,
(in thousands) 1999 1998 1997
- -------------------------------------------------------------------------------
Service cost $ 4,505 $ 3,892 $ 3,543
Interest cost 21,896 16,895 17,006
Expected return on plan assets (12,329) (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 $ 20,508 $ 20,418 $ 23,265
===============================================================================
48
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 H. Stock-Based Compensation
In 1997, Boston Edison initiated a Stock Incentive Plan (the Plan) that was
adopted by the board of directors and approved by common stockholders and
subsequently approved for all eligible NSTAR subsidiary company employees. The
Plan permits a variety of stock and stock-based awards, including stock options
and deferred (nonvested) stock to be granted to certain key employees. The Plan
limits the terms of awards to ten years. Subject to adjustment for stock-splits
and similar events, the aggregate number of shares of common stock that may be
delivered under the Plan is 2,000,000, including shares issued in lieu of or
upon reinvestment of dividends arising from awards. During 1999, 58,500 shares
of deferred stock and 248,000 ten-year non-qualified stock options were granted.
During 1998, 19,150 shares of deferred stock and 419,200 ten-year non-qualified
stock options were granted under the Plan. During 1997, 73,820 shares of
deferred stock and 298,400 ten-year non-qualified stock options were granted.
The weighted average grant date fair value of the deferred stock issued during
1999, 1998 and 1997 was $41.73, $39.75 and $27.26, respectively. The options
were granted at the full market price of the stock on the date of the grant. All
the awards vest ratably over a three-year period.
Compensation cost for stock-based awards is computed by measuring the quoted
stock market price at the measurement date less the amount, if any, an employee
is required to pay. The fair value disclosures were as follows:
(in thousands, except per share amounts) 1999 1998 1997
- ------------------------------------------------------------------------------------
Net income
Actual $146,463 $141,046 $144,642
Pro forma $145,955 $140,661 $144,572
Basic earnings per common share
Actual $ 2.77 $ 2.76 $ 2.71
Pro forma $ 2.76 $ 2.75 $ 2.71
Diluted earnings per common share
Actual $ 2.76 $ 2.75 $ 2.71
Pro forma $ 2.75 $ 2.74 $ 2.71
Stock option activity of the Plan was as follows:
1999 1998 1997
- ------------------------------------------------------------------------------------
Options outstanding at January 1 666,600 273,000 0
Options granted 248,000 419,200 $298,400
Options exercised (4,400) (3,800) 0
Options forfeited (95,933) (21,800) (25,400)
- ------------------------------------------------------------------------------------
Options outstanding at December 31 814,267 666,600 $273,000
====================================================================================
49
Summarized information regarding stock options outstanding at December 31, 1999:
Options Outstanding Options Exerciserable
Weighted Average Weighted Weighted
Remaining Average Average
Range of Numbers Contractual Life Exercise Numbers Execise
Exercise Prices Outstanding (Years) Price Outstanding Price
- ---------------------------------------------------------------------------------------------
$25.75-$26.00 244,200 7.44 $25.85 168,333 $25.85
$39.75-$41.375 570,067 8.78 $40.35 130,000 $39.75
There were 298,333, stock options exercisable at December 31, 1999, 87,200 at
December 31, 1998 and 0 at December 31, 1997.
The stock options granted during 1999, 1998 and 1997 have a weighted average
grant date fair value of $4.86, $4.61 and $2.22, respectively. The fair value
was estimated using the Black-Scholes option pricing model with the following
weighted average assumptions:
1999 1998 1997
- -------------------------------------------------------------------------------
Expected life (years) 4.0 4.0 4.0
Risk-free interest rate 5.31% 5.66% 6.44%
Volatility 17% 16% 16%
Dividends 4.86% 4.88% 7.28%
Compensation cost recognized in the accompanying Consolidated Statements of
Income for stock-based compensation awards in 1999, 1998 and 1997 was
$1,044,000, $850,000 and $275,000, respectively.
Note I. Capital Stock
December 31,
(in thousands, except per share amounts) 1999 1998
- --------------------------------------------------------------------------------
Common equity:
Common shares, par value $1 per share,
100,000,000 shares authorized; 58,059,646
and 47,184,073 shares issued and
outstanding $ 58,060 $ 47,184
Premium on common shares 1,075,483 644,205
Retained earnings 389,989 360,509
- --------------------------------------------------------------------------------
Total common equity $1,523,532 $1,051,898
================================================================================
Dividends declared per share of common stock were $1.955, $1.895 and $1.88 in
1999, 1998 and 1997 respectively.
Cumulative preferred stock:
(in thousands, except per share amounts)
- --------------------------------------------------------------------------------
Par value $100 per share, 2,890,000 shares
authorized; issued and outstanding:
Nonmandatory redeemable series:
Current Shares Redemption December 31,
Series Outstanding Price/Share 1999 1998
- --------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------
50
Mandatory redeemable series:
Current Shares Redemption
Series Outstanding Price/Share
- --------------------------------------------------------------------------------
8.00% 500,000 0 50,000 50,000
Less: redemption and issuance costs (721) (960)
- --------------------------------------------------------------------------------
Total mandatory redeemable series 49,279 49,040
- --------------------------------------------------------------------------------
Total $ 92,279 $ 92,040
================================================================================
1. Common Shares
Common share issuances and repurchases in 1997 through 1999 were as follows:
Number Total Premium on
(in thousands) of Shares Par Value Common Shares
- --------------------------------------------------------------------------------
Balance at December 31, 1996 48,510 $ 48,510 $ 695,723
Dividend reinvestment plan 5 5 414
- -------------------------------------------------------------------------------
Balance at December 31, 1997 48,515 48,515 696,137
Common share repurchase program (1,331) (1,331) (49,823)
Stock incentive plan 0 0 (2,109)
- -------------------------------------------------------------------------------
Balance at December 31, 1998 47,184 47,184 644,205
Common share repurchase program (4,839) (4,839) (179,593)
Stock incentive plan 0 0 (3,189)
Shares issued to COM/Energy shareholders 20,251 20,251 809,524
BEC Energy shares repurchased under
merger agreement (4,536) (4,536) (195,464)
- -------------------------------------------------------------------------------
Balance at December 31,1999 58,060 $ 58,060 $1,075,483
===============================================================================
51
2. 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.
Note J. Indebtedness
NSTAR's long-term debt consisted of the following:
December 31,
(in thousands) 1999 1998
- -------------------------------------------------------------------------------
Mortgage Bonds, collateralized by property of operating subsidiaries:
8.99%, due December 2001 $ 7,150 $ 0
6.54%, due September 2007 10,000 0
7.04%, due September 2017 25,000 0
9.95%, due December 2020 25,000 0
7.11%, due December 2033 35,000 0
Notes:
7.75%, due June 2002 2,301 0
9.30%, due January 2002 29,978 0
7.43%, due March 2003 15,000 0
9.50%, due December 2004 5,000 0
7.62%, due November 2006 20,000 0
8.70%, due March 2007 5,000 0
9.55%, due December 2007 10,000 0
7.70%, due March 2008 10,000 0
9.37%, due January 2012 13,684 0
7.98%, due March 2013 25,000 0
9.53%, due December 2014 10,000 0
9.60%, due December 2019 10,000 0
6.924%, due June 2021 105,250 0
8.47%, due March 2023 15,000 0
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
- -------------------------------------------------------------------------------
1,854,794 956,230
Amounts due within one year (221,392) (667)
- -------------------------------------------------------------------------------
Total long-term debt $1,633,402 $ 955,563
===============================================================================
52
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%. None of the other series are redeemable prior to maturity.
There is no sinking fund requirement for any series of debentures.
Sewage facility revenue bonds are tax-exempt, subject to annual mandatory
sinking fund redemption requirements and mature through 2015. Scheduled
redemptions of $1.6 million were made in 1999, 1998 and 1997. The weighted
average interest rate of the bonds was 7.3%.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable beginning in
February 2004 at a redemption price of 102%. The redemption price decreases to
101% in February 2005 and to par in February 2006.
The aggregate principal amounts of NSTAR long-term-debt (including
securitization certificates and sinking fund requirements) due for the five
years subsequent to 1999 are approximately $251 million in 2000, $123 million in
2001, $109 million in 2002, $241 million in 2003 and $79 million in 2004.
In 1999, BEC Funding LLC, a wholly owned subsidiary of Boston Edison, issued
notes in the principal 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
NSTAR has a $450 million revolving credit agreement with a group of banks
effective through November 2002. Under the terms of this agreement, it is
required to maintain a consolidated common equity ratio of not less than 35% at
all times and to maintain a ratio of consolidated earnings before interest and
taxes to consolidated total interest expense of not less than 2 to 1 for each
period of four consecutive fiscal quarters. Commitment fees must be paid on the
total agreement amount. Approximately $350 million was outstanding under this
agreement as of December 31, 1999.
Boston Edison has regulatory authority to issue up to $350 million of short-term
debt. In addition, Boston Edison has a $200 million revolving credit agreement
with a group of banks that serves as back-up to the Boston Edison commercial
paper program. Under the terms of this agreement, Boston Edison is required to
maintain a common equity ratio of not less than 30% at all times. Commitment
fees must be paid on the total agreement amount.
COM/Energy maintains committed lines of credit for the short-term financing of
their construction programs and other corporate purposes. As of December 31,
1999, COM/Energy had $115 million of committed lines of credit that will expire
at varying intervals in 2000. These lines are normally renewed upon expiration
and require annual fees of approximately .1875%.
Interest rates on the outstanding borrowings generally are money market rates
and averaged 5.82% and 5.85% in 1999 and 1998, respectively. Notes payable
53
to banks totaled $458 million and $78 million at December 31, 1999 and 1998,
respectively.
Note K. 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 $169 million approximates fair value due to the
short-term nature of these securities.
Mandatory redeemable cumulative preferred stock and indebtedness (excluding
notes payable):
The fair values of these securities are based upon the quoted market prices of
similar issues. Carrying amounts and fair values as of December 31, 1999, were
as follows:
Carrying Fair
(in thousands) Amount Value
- --------------------------------------------------------------------------------
Mandatory redeemable cumulative preferred stock $ 49,279 $ 52,250
Long-term indebtedness $1,854,794 $1,842,373
Note L. Segment and Related Information
For the purpose of providing segment information, NSTAR's principal operating
segments, or its traditional core businesses, are the electric and natural gas
utilities that provide energy delivery services in numerous cities and towns in
Massachusetts. NSTAR subsidiaries also supply electricity at wholesale for
resale to municipalities. The unregulated operating segments engage in
non-utility business activities. Such activities include telecommunications,
district heating and cooling operations, and liquefied natural gas services.
Financial data for the operating segments were as follows:
(in thousands): 1999 1998 1997
- -------------------------------------------------------------------------------
Operating revenues
Electric utility operations $1,710,576 $1,622,435 $1,776,233
Gas utility operations 108,117 0 0
Unregulated nonutility Operations 32,734 80 2,298
-------------------------------------
Consolidated total $1,851,427 $1,622,515 $1,778,531
Depreciation and amortization
Electric utility operations $ 190,560 $ 192,644 $ 188,687
Gas Utility operations 5,566 0 0
Unregulated nonutility operations 14,180 2,963 802
-------------------------------------
Consolidated total $ 210,306 $ 195,607 $ 189,489
Operating income tax expense (benefit)
Electric utility operations $ 98,125 $ 101,492 $ 95,021
Gas utility operations 4,208 0 0
Unregulated nonutility operations (14,612) (3,694) (1,312)
--------------------------------------
Consolidated total $ 87,721 $ 97,798 $ 93,709
54
Equity income (loss) in investments
accounted for by the equity method
Electric utility operations $ 999 $ 1,725 $ 1,534
Gas utility operations 0 0 0
Unregulated nonutility operations (10,505) (11,967) (5,571)
--------------------------------------
Consolidated total $ (9,506) $ (10,242)(b) $ (4,037)(b)
Interest charges
Electric utility operations $ 107,717 $ 88,516 $ 105,710
Gas utility operations 3,738 0 0
Unregulated nonutility operations 14,745 1,567 200
--------------------------------------
Consolidated total $ 126,200 $ 90,083 $ 105,910
Segment net income (loss)
Electric utility operations $ 165,655 $ 170,374 $ 153,738
Gas utility operations 5,381 0 0
Unregulated nonutility operations (24,573) (29,328)(a) (9,096)(a)
--------------------------------------
Consolidated total $ 146,463 $ 141,046 $ 144,642
Equity investments
Electric utility operations $ 32,995 $ 20,769 $ 23,326
Gas utility operations 9 0 0
Unregulated nonutility operations 140,286 64,001 12,129
--------------------------------------
Consolidated total $ 173,290 $ 84,770 $ 35,455
Expenditures for property
Electric utility operations $ 134,906 $ 108,344 $ 106,659
Gas utility operations 7,669 0 0
Unregulated nonutility operations 16,720 11,858 7,451
--------------------------------------
Consolidated total $ 159,295 $ 120,202 $ 114,110
Segment assets
Electric utility operations $4,411,630 $3,073,058 $3,584,384
Gas utility operations 459,887 0 0
Unregulated nonutility operations 611,371 130,978 37,963
--------------------------------------
Consolidated total $5,482,888 $3,204,036 $3,622,347
===============================================================================
(a) During the latter half of 1998 BEC discontinued the operations of Coneco
Corporation, a wholly owned unregulated subsidiary that provided energy
management services, and ceased its participation in EnergyVision, an
energy marketing joint venture with Williams Energy Services Company. The
combined net loss from these businesses was ($11,450,000) and ($3,160,000)
in 1998 and 1997, respectively.
(b) The net equity income (loss) from equity investments is included in other
income (expense), net on the accompanying Consolidated Statements of
Income.
Note M. Commitments and Contingencies
1. Contractual Commitments
As December 31, 1999, NSTAR and its subsidiaries had estimated contractual
obligations for plant and equipment of approximately $347 million.
55
NSTAR also had leases for certain facilities and equipment. The estimated
minimum rental commitments under both transmission agreements and non-cancelable
operating leases for the years after 1999 are as follows:
(in thousands)
- ------------------------------------------------
2000 $ 25,649
2001 22,485
2002 20,436
2003 17,142
2004 16,351
Years thereafter 108,302
- ------------------------------------------------
Total $ 210,365
================================================
The total expense for both lease rentals and transmission agreements was $38.7
million in 1999, $29.6 million in 1998 and $27.5 million in 1997, net of
capitalized expenses of $1.5 million in 1999, $1.6 million in 1998 and $1.2
million in 1997.
Total rent expense for all operating leases, except those with terms of a month
or less, amounted to $10.8 million in 1999, $11.5 million in 1998 and $11.2
million in 1997.
2. Electric Company Investments
NSTAR has an equity investment of approximately 14.5% in two companies that own
and operate transmission facilities to import electricity from the Hydro-Quebec
system in Canada. As an equity participant NSTAR 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, NSTAR's portion of these
guarantees was $18 million.
NSTAR also has a 2.5% equity investment in the 540 MW Vermont Yankee nuclear
power plant. Vermont Yankee has developed its estimate of the cost of
decommissioning its unit and has received the approval of FERC to include
charges for the estimated costs of decommissioning its unit in the cost of
energy that it sells. Periodically, Vermont Yankee re-estimates the cost of
decommissioning and applies to FERC for increased rates in response to increased
decommissioning costs. The Vermont Yankee unit is under agreement to be sold to
Amergen Energy Company. NSTAR is currently entitled to electricity produced from
the remaining facility based on its ownership interest and is billed for its
entitlement pursuant to a contractual agreement that is approved by the FERC.
The estimated cost to decommission this plant is $428.7 million in current
dollars. NSTAR's share of this liability (approximately $10.7 million), less its
share of the market value of the assets held in a decommissioning trust
(approximately $6.2 million), is approximately $4.5 million at December 31,
1999.
NSTAR has a 14% equity investment in Yankee Atomic Electric Company (Yankee
Atomic). In 1992, the board of directors of Yankee Atomic voted to discontinue
operations of the Yankee Atomic nuclear generating station permanently and
decommission the facility.
Yankee Atomic received approval from the FERC to continue to collect its
investment and decommissioning costs through 2000, the period of the plant's
operating license. The estimate of NSTAR's share of Yankee Atomic's investment
and costs of decommissioning is approximately $4.5 million as of
56
December 31, 1999. These estimates are recorded on the accompanying Consolidated
Balance Sheets as a power contract liability and an offsetting regulatory asset.
NSTAR also has a 14% equity investment in Connecticut Yankee Atomic Power
Company (CYAPC). In 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. NSTAR'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 Sheets 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 ratepayers. Management is currently unable to
determine the ultimate outcome of this proceeding. However, the estimate of the
effect of the ALJ's initial decision does not have a material impact on its
consolidated financial position or results of operations.
NSTAR has a 4% equity investment in the Maine Yankee Atomic Power Company (Maine
Yankee). In 1997 the board of directors of Maine Yankee voted to discontinue
operations of the Maine Yankee nuclear generating station permanently and
decommission the facility.
NSTAR's share of Maine Yankee's remaining decommissioning is approximately $28
million as of December 31, 1999. This estimate is recorded on the accompanying
Consolidated Balance Sheets as a power contract liability and an offsetting
regulatory asset.
3. Nuclear Insurance
Under the Price-Anderson Act (the Act), owners of nuclear power plants have the
benefit of approximately $9.5 billion of public liability coverage that would
compensate the public for covered bodily injury and property loss in the event
of an accident at a commercial nuclear power plant. The first $200 million of
nuclear liability is covered by commercial insurance. Additional nuclear
liability insurance up to $9.3 billion is provided by a retrospective assessment
of up to $88.1 million per incident levied on each of the 106 nuclear generating
units currently licensed to operate in the United States, with a maximum
assessment of $10 million per incident per year.
NSTAR has an equity ownership interest in four nuclear generating facilities as
well as a 3.52% joint-ownership interest in Seabrook 1. The operators of these
units maintain nuclear insurance coverage (on behalf of the owners of
57
the facilities) with either Nuclear Electric Insurance Limited (NEIL), a
combination of NEIL and the American Nuclear Insurers (ANI) or ANI only
depending on the limit of insurance required to be maintained. NEIL provides
$2.25 billion of property, boiler, machinery and decontamination insurance
coverage, including accidental premature decommissioning insurance. All
companies insured with NEIL are subject to retroactive assessments. ANI provides
$500 million of "all risk" property damage, boiler, machinery and
decontamination insurance. Three of the four units in which NSTAR has an equity
ownership interest have permanently ceased operations. The Nuclear Regulatory
Commission has approved each of these units' requests to withdraw from
participation in the financial protection insurance program of the act and
reduce their limits of property insurance.
Based on its various ownership interests in the five nuclear generating
facilities, NSTAR's retrospective premium could be $600,000 annually or a
cumulative total of $5.3 million under the Act.
4. Environmental Matters
The utility subsidiaries of NSTAR are involved in approximately 30 properties
where oil or hazardous materials were previously spilled or released. As such,
the companies are 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. NSTAR's subsidiaries also face possible
liability as a potentially responsible party in the cleanup of six 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. NSTAR
currently expects to have only a small percentage of the total potential
liability for these sites. Approximately $6.6 million is included in the
December 31, 1999 Consolidated Balance Sheets related to these cleanup
liabilities. Management is unable to fully determine a range of reasonably
possible cleanup costs in excess of the accrued amount. Based on its assessments
of the specific site circumstances, management does not believe that it is
probable that any such additional costs will have a material impact on NSTAR's
consolidated financial position. However, it is reasonably possible that
additional provisions for cleanup costs that may result from a change in
estimates could have a material impact on the results of a reporting period in
the near term.
Public concern continues regarding Electro Magnetic 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.
NSTAR 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. NSTAR continues to
monitor all aspects of the EMF issue.
ComGas is participating in the assessment of a number of former Manufactured Gas
Plant (MGP) sites and alleged MGP waste disposal locations to determine
58
if and to what extent such sites have been contaminated and whether ComGas may
be responsible for remedial action. As of December 31, 1999, ComGas has recorded
a liability and corresponding regulatory asset amounting to $2.2 million as an
estimate for site cleanup costs for several MGP sites for which ComGas was
previously cited as a Potentially Responsible Party. The MDTE has approved
recovery of costs associated with MGP sites.
Estimates related to environmental remediation costs are reviewed and adjusted
periodically as further investigation and assignment of responsibility occurs.
NSTAR is unable to estimate its ultimate liability for future environmental
remediation costs. However, in view of NSTAR's current assessment of its
environmental responsibilities, existing legal requirements and regulatory
policies, management does not believe that these matters will have material
adverse effect on NSTAR's results of operations or financial position.
5. Generating Unit Performance Program
The MDTE's generating unit performance programs ceased March 1, 1998. Under
these programs the recovery of incremental purchased power costs resulting from
generating unit outages occurring through the retail access date was subject to
review by the MDTE. However, proceedings relative to generating unit performance
remain pending before the MDTE. These proceedings will include the review of
replacement power costs associated with the shutdown of the Connecticut Yankee
nuclear electric generating unit that 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 NSTAR's consolidated financial
position. However, it is reasonably possible that additional provisions for
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 restructuring settlement agreement
was appealed by certain parties to the Massachusetts Supreme Judicial Court. 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, NSTAR
utility subsidiaries have 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.
59
Regulatory proceedings
In October 1997, the MDTE opened a proceeding to investigate Boston Edison's
compliance with the 1993 order that 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 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.
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
had wrongfully failed to execute an agreement with the town for payments in
addition to taxes due to the town under the Massachusetts Electric Restructuring
Law. 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 NSTAR and its subsidiaries are also
involved in certain other legal matters. Management is unable to fully determine
a range of reasonably possible legal costs in excess of amounts accrued. Based
on the information currently available, it does not believe that it is probable
that any such additional costs will have a material impact on its consolidated
financial position. However, it is reasonably possible that additional legal
costs that may result from a change in estimates could have a material impact on
the results of a reporting period in the near term.
Note N. Long-Term Power Contracts for the Purchase of Electricity
1. Energy Agreements
NSTAR on behalf of Boston Edison, Cambridge Electric Light Company and
ComElectric 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. NSTAR's 1999 proportionate share of capacity and total cost reflects four
months of the COM/Energy subsidiaries from the date of the merger.
60
Information relating to the contracts as of December 31, 1999 is as follows:
proportionate share (in thousands)
Units of ------------------------------------
Range of Capacity Capacity Charge
Contract Purchased 1999 Obligation 1999
Fuel Type of Expiration ------------- Capacity Through Contract Total
Generating Unit Dates % MW Cost Expiration Date Cost
- -----------------------------------------------------------------------------------------
Natural Gas 2008-2017 11.1-100 28.8-135 $ 94,625 $1,585,675 $258,838
Nuclear 2004-2026 2.3-8.9 40.9-747.1 16,624 691,741 93,719
Waste-to-energy 2015 100 76.9 - - 14,393
Hydro 2014-2023 100 1.3-20 - - 3,680
Oil 2002-2019 50-100 34-282 13,719 99,553 39,020
- -----------------------------------------------------------------------------------------
Total $124,968 $2,376,969 $409,650
=========================================================================================
Energy is paid for based on a price per kWh actually received. In 1999, NSTAR's
retail distribution companies did not pay a proportionate share of capital and
fixed operating costs for 1,121.4 MW purchased.
NSTAR's total fixed and variable costs associated with these contracts in 1999,
1998 and 1997 were approximately $410 million, $267 million and $288 million,
respectively. NSTAR's capacity charge obligation under these contracts for the
years after 1999 are as follows:
Capacity Charge
(in thousands) Obligation
- --------------------------------------------------------
2000 $ 179,979
2001 160,648
2002 159,832
2003 147,505
2004 147,538
Years thereafter 1,581,467
- --------------------------------------------------------
Total $2,376,969
========================================================
2. Natural Gas Contracts
ComGas has various contractual agreements covering the transportation of natural
gas, underground storage facilities and the purchase of natural gas, which are
recoverable under ComGas' CGAC. These contracts expire at various times from
2003 to 2013.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
- --------------------------------------------------------------------------------
Not applicable.
61
Part III
Item 10. Trustees and Executive Officers of the Registrant
(a) Identification of Trustees
Information required by this item is incorporated herein by reference to the
Notice of Year 2000 Annual Meeting, Proxy Statement and 1999 Financial
Information dated March 30, 2000 on pages 3, 4 and 5.
(b) Identification of Officers
Information required by this item is included in Item 4.A.
Item 11. Executive Compensation
Information required by this item is incorporated herein by reference to the
Notice of 2000 Annual Meeting, Proxy Statement and 1999 Financial Information
dated March 30, 2000. Pages 7-14
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information required by this item is incorporated herein by reference to the
Notice of 2000 Annual Meeting, Proxy Statement and 1999 Financial Information
dated March 30, 2000. Pages 1 and 6
Item 13. Certain Relationships and Related Transactions
Information required by this item is incorporated herein by reference to the
Notice of 2000 Annual Meeting, Proxy Statement and 1999 Financial Information
dated March 30, 2000. Pages 9 and 10
62
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 34
Consolidated Statements of Retained Earnings for the
years ended December 31, 1999, 1998 and 1997 35
Consolidated Balance Sheets as of December 31, 1999 and 1998 36
Consolidated Statements of Cash Flows for the years
ended December 31, 1999, 1998 and 1997 37
Notes to Consolidated Financial Statements 38
Selected Consolidated Quarterly Financial Data (Unaudited) 17
Report of Independent Accountants 81
2. Financial Statement Schedules:
Schedule II - Valuation and Qualifying accounts - years ended December 31,
1999, 1998 and 1997. 78
3. Exhibits:
Refer to the exhibits listing beginning on the following page.
(b) Reports on Form 8-K:
None
63
NSTAR (Registrant)
INCORPORATION HEREIN BY REFERENCE
- ---------------------------------
2.1 Amended and Restated Agreement and Plan of Merger, dated as of
December 5, 1998, amended and restated as of May 4, 1999, by and among
BEC Energy, Commonwealth Energy System, NSTAR, BEC Acquisition LLC and
CES Acquisition LLC (incorporated by reference to Annex A to the Joint
Proxy Statement/Prospectus, Registration Statement on Form S-4 of
NSTAR (No. 333-78285)).
3.1 Declaration of Trust of NSTAR (incorporated by reference to Annex D to
the Joint Proxy Statement/Prospectus, which forms part of this
Registration Statement on Form S-4 of NSTAR (No. 333-78285)).
3.2 Bylaws of NSTAR (attached as Annex E to the Joint Proxy
Statement/Prospectus, which forms part of this Registration
Statement).
4.0 Instruments Defining the Rights of Security Holders, Including
Indentures. Management agrees to furnish to the Securities and
Exchange Commission, upon request, a copy of any other agreements or
instruments of the Registrant and its subsidiaries defining the rights
of holders of any long-term debt not exceed 10% of total assets.
4.1 Indenture dated as of January 12, 2000 between NSTAR and Bank One
Trust Company N.A. (incorporated by reference, Exhibit 4.1 to NSTAR
Registration Statement on Form S-3, File No. 333-94735)
FILED HEREIN
- ------------
21 Subsidiaries of Registrant.
27 Schedule UT.
BEC Energy and Subsidiaries of BEC
----------------------------------
FILED HEREIN
- ------------
10.13 License Agreement between Boston Edison Company and Becocom, Inc.,
June 17, 1997. Incorporated herein by Reference.
INCORPORATED HEREIN BY REFERENCE
- --------------------------------
10.14 Chilled Water Service Agreement between Northwind Boston LLC and
Prucenter Acquisition LLC, March 23, 1999.
3.1 Boston Edison Restated Articles of Organization (Form 10-Q for the
quarter ended June 30, 1994, File No. 1-2301).
3.2 Boston Edison Company Bylaws April 19, 1977, as amended January 22,
1987, January 28, 1988, May 28, 1988, and November 22, 1989 (Form 10-Q
for the quarter ended June 30, 1990, File No. 1-2301).
4.1 Medium-Term Notes Series A - Indenture dated September 1, 1988,
between Boston Edison Company and Bank of Montreal Trust Company (Form
10-Q for the quarter ended September 30, 1988, File No. 1-2301).
4.1.1 First Supplemental Indenture dated June 1, 1990 to Indenture dated
September 1, 1988 with Bank of Montreal Trust Company.
64
9 7/8% debentures due June 1, 2020. (Form 8-K dated June 28, 1990,
File No. 1-2301)
4.1.26 Indenture of Trust and Agreement among the City of Boston,
Massachusetts (acting by and through its Industrial Development
Financing Authority) and Harbor Electric Energy Company and Shawmut
Bank, N.A., as Trustee, dated November 1, 1991 (Form 10-K for the year
end December 31 1991, File No. 1-2301)
4.1.27 Votes of the Pricing Committee of the Board of Directors of Boston
Edison Company taken August 5, 1991 re 9 3/8% debentures due August
15, 2021 (Form 10-K for the year ended December 31, 1991, File No.
1-2301)
4.1.25 Votes of the Pricing Committee of the Board of Directors of Boston
Edison Company taken September 10, 1992 re 8 1/4% debentures due
September 15, 2022 (Form 10-K for the year ended December 31, 1997,
File No. 1-2301)
4.1.26 Votes of the Pricing Committee of the Board of Directors of Boston
Edison Company taken January 27, 1993 re 6/80% debentures due February
1, 2000 (Form 10-K for the year ended December 31, 1992, File No.
1-2301)
4.1.27 Votes of the Pricing Committee of the Board of Directors of Boston
Edison Company taken March 5, 1993 re 6/80% Debentures due March 15,
2003 and 7.80% debentures due March 15, 2023 (Form 10-K for the year
ended December 31, 1992, File No. 1-2301)
4.1.28 Votes of the Pricing Committee of the Board of Directors of Boston
Edison Company taken August 18,1993 re 6.05% debentures due August 15,
2000 (Form 10-K for year ended December 31, 1993, File No. 1-2301)
4.1.9 Votes of the Pricing Committee of the Board of Directors of Boston
Edison Company taken May 10, 1995 re 7.80% debentures due May 15, 2010
(Form 10-K for the year ended December 31, 1995, File No. 1-2301)
10.3.1 Key Executive Benefit Plan Standard Form of Agreement, May 1986, with
modifications (Form 10-K for the year ended December 31, 1991, File
No. 1-2301, File No. 1-2301)
10.5 Executive Annual Incentive Compensation Plan (Form 10-K for the year
ended December 31, 1988, File No. 1-2301)
65
10.1 Supplemental Executive Retirement Plan (Form 10-Q for the quarter
ended June 10, 1997, File No. 1-2301)
10.2 1997 Stock Incentive Plan (Form 10-Q for the quarter ended June 30,
1997, File No. 1-2301)
10.11 Boston Edison Company Deferred Fee Plan dated January 14, 1993 (Form
10-K for year ended December 31, 1992, File No. 1-2301)
10.10 Deferred Compensation Trust between Boston Edison Company and State
Street Bank and Trust Company dated February 2, 1993 (Form 10-K for
the year ended December 31, 1992, File No. 1-2301)
10.5.1 Amendment No. 1 to Deferred Compensation Trust dated March 31, 1994
(Form 10-K for the year ended December 31, 1994)
10.9 Boston Edison Company Deferred Compensation Plan, Amendment and
Restatement dated January 31, 1995 (Form 10-K for the year ended
December 31, 1994, File No. 1-2301)
10.10 Employment Agreement Applicable to Ronald A. Ledgett dated April 30,
1987 (Form 10-K for the year ended December 31, 1994, File No. 1-2301
10.3 Form of Change in Control Agreement applicable to Ronald A. Ledgett,
James J. Judge and certain other officers dated July 9, 1996
(Form 10-Q for the quarter ended June 30, 1996, File No. 1-2301)
10.12 Boston Edison Company Restructuring Settlement Agreement dated July
1997 (Form 10-K for the year ended December 31, 1997, File No. 1-2301)
10.1 Boston Edison Company and Sithe Energies, Inc. Purchase and Sale and
Transition Agreements dated December 10, 1997 (Form 10-Q for the
quarter ended March 31, 1998, File No. 1-2301)
10.11 Boston Edison Company Directors' Deferred Fee Plan Restatement
effective October 1, 1998 (Form 10-K for the year ended December 31,
1999, File No. 1-2301)
10.12 Boston Edison Company and Entergy Nuclear Generation Company Purchase
and Sale Agreement dated November 18, 1998 (Form 10-K for the year
ended December 31, 1999, File No. 1-2301)
21.1 Boston Edison Company (incorporated in Massachusetts), a wholly owned
subsidiary of BEC Energy
21.2 Boston Energy Technology Group, Inc. (incorporated in Massachusetts),
a wholly owned subsidiary of BEC Energy
66
21.3 Harbor Electric Energy Company (incorporated in Massachusetts), a
wholly owned subsidiary of Boston Edison Company.
99.1 Settlement Agreement between Boston Edison Company and Commonwealth
Electric Company, Montaup Electric Company and the Municipal Light
Department of the Town of Reading, Massachusetts, dated January 5,
1990 (Form 8-K dated December 21, 1989, File No. 1-2301).
99.2 Settlement Agreement between Boston Edison Company and City of Holyoke
Gas and City of Holyoke Gas and Electric Department et. al., dated
April 26, 1990 (Form 10-Q for the quarter ended March 31, 1990, File
No. 1-2301).
99.3 Information required by SEC Form 11-K for certain employee benefit
plans for the years ended December 31, 1997, 1996 and 1995 (Form
10-K/A Amendments to Form 10-K for the years December 31, 1997, 1996
and 1995 dated June 25, 1998, June 26, 1997 and June 27, 1996
respectively.
Commonwealth Energy System
--------------------------
INCORPORATED HEREIN BY REFERENCE
- --------------------------------
4.1.1 CES Note Agreement ($40 Million Privately Placed Senior Notes) dated
June 28, 1989 (Exhibit 1 to the CES Form 10-Q (September 1989), File
No. 1-7316).
Cambridge Electric Light Company
--------------------------------
INCORPORATED HEREIN BY REFERENCE
- --------------------------------
4.2.1 Original Indenture on Form S-1 (April, 1949) (Exhibit 7(a), File No.
2-7909).
4.2.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File No. 2-7909).
4.2.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File No. 2-7909).
4.2.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1, File No.
2-7909).
4.2.5 Seventh Supplemental on Form 10-Q (June 1992), (Exhibit 1, File No.
2-7909).
67
Commonwealth Gas Company
------------------------
INCORPORATED HEREIN BY REFERENCE
- --------------------------------
4.4.1 Original Indenture on Form S-1 (Feb., 1949) (Exhibit 7(a), File No.
2-7820).
4.4.2 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1, File No.
2-1647).
4.4.3 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2, File No.
2-1647).
4.4.4 Eighteenth Supplemental on Form 10-Q (March 1994) (Exhibit 1, File No.
2-1647).
4.4.5 Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1, File No.
2-1647).
10.1 Power contracts.
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL dated
December 1, 1965 (Exhibit 13(a)(1-4) to the CEC Form S-1,
File No. 2-30057).
68
10.1.2 Power contract between Yankee Atomic Electric Company (YAEC) and CEL
dated June 30, 1959, as amended April 1, 1975 (Refiled as Exhibit 1 to
the 1991 CEL Form 10-K, File No. 2-7909).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended October 1,
1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 2 to the
CEL Form 10-Q (June 1988), File No. 2-7909).
10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26, 1989 and July
1, 1989, respectively (Exhibit 1 to the CEL Form 10-Q (September
1989), File No. 2-7909).
10.1.3 Power Contract between YAEC and NBGEL dated June 30, 1959, as amended
April 1, 1975 (Refiled as Exhibit 2 to the 1991 CE Form 10-K, File No.
2-7749).
10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended October 1,
1980, April 1, 1985 and May 6, 1988, respectively (Exhibit 1 to the CE
Form 10-Q (June 1988), File No. 2-7749).
10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26, 1989 and July
1, 1989, respectively (Exhibit 3 to the CE Form 10-Q (September 1989),
File No. 2-7749).
10.1.4 Power Contract between Connecticut Yankee Atomic Power Company (CYAPC)
and CEL dated July 1, 1964 (Exhibit 13-K1 to the Parent's Form S-1,
(April 1967) File No. 2-25597).
10.1.4.1 Additional Power Contract providing for extension on contract term
between CYAPC and CEL dated April 30, 1984 (Exhibit 5 to the CEL Form
10-Q (June 1984), File No. 2-7909).
10.1.4.2 Second Supplementary Power Contract providing for decommissioning
financing between CYAPC and CEL dated April 30, 1984 (Exhibit 6 to the
CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.5 Power contract between Vermont Yankee Nuclear Power Corporation
(VYNPC) and CEL dated February 1, 1968 (Exhibit 3 to the CEL 1984 Form
10-K, File No. 2-7909).
10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and Second Amendment
dated April 15, 1983 (decommissioning financing) to 10.1.5 (Exhibits 1
and 2, respectively, to the CEL Form 10-Q (June 1984), File No.
2-7909).
10.1.5.2 Third Amendment dated April 1, 1985 and Fourth Amendment dated June 1,
1985 to 10.1.5 (Exhibits 1 and 2, respectively, to the CEL Form 10-Q
(June 1986), File No. 2-7909).
10.1.5.3 Fifth and Sixth Amendments to 10.1.5 dated February 1, 1968, both as
amended May 6, 1988 (Exhibit 1 to the CEL Form 10-Q (June 1988),
File No. 2-7909).
69
10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as amended June
15, 1989 (Exhibit 2 to the CEL Form 10-Q (September 1989), File No.
2-7909).
10.1.5.5 Additional Power Contract dated February 1, 1984 between CEL and VYNPC
providing for decommissioning financing and contract extension
(Refiled as Exhibit 1 to CEL 1993 Form 10-K, File No. 2-7909).
10.1.6 Power contract between Maine Yankee Atomic Power Company (MYAPC) and
CEL dated May 20, 1968 (Exhibit 5 to the Parent's Form S-7, File No.
2-38372).
10.1.6.1 First Amendment dated March 1, 1984 (decommissioning financing) and
Second Amendment dated January 1, 1984 (supplementary payments) to
10.1.6 (Exhibits 3 and 4 to the CEL Form 10-Q (June 1984), File No.
2-7909).
10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit 1 to the CEL
Form 10-Q (September 1984), File No. 2-7909).
10.1.7 Agreement between NBGEL and Boston Edison Company (BECO) for the
purchase of electricity from BECO's Pilgrim Unit No. 1 dated August 1,
1972 (Exhibit 7 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.7.1 Service Agreement between NBGEL and BECO for purchase of stand-by
power for BECO's Pilgrim Station dated August 16, 1978 (Exhibit 1 to
the CE 1988 Form 10-K, File No. 2-7749).
10.1.7.2 System Power Sales Agreement by and between CE and BECO dated July 12,
1984 (Exhibit 1 to the CE Form 10-Q (September 1984), File No.
2-7749).
10.1.7.3 Power Exchange Agreement by and between BECO and CE dated December 1,
1984 (Exhibit 16 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.7.4 Service Agreement for Non-Firm Transmission Service between BECO and
CEL dated July 5, 1984 (Exhibit 4 to the CEL 1984 Form 10-K, File No.
2-7909).
10.1.8 Agreement for Joint-Ownership, Construction and Operation of New
Hampshire Nuclear Units (Seabrook) dated May 1, 1973 (Exhibit 13(N) to
the NBGEL Form S-1 dated October 1973, File No. 2-49013 and as amended
below:
10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May 24, 1974, June
21, 1974, September 25, 1974, October 25, 1974 and January 31, 1975,
respectively (Exhibit 13(m) to the NBGEL Form S-1 (November 7, 1975),
File No. 2-54995).
10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended April 18, 1979,
April 25, 1979, June 8, 1979, October 11, 1979 and December 15, 1979,
respectively (Refiled as Exhibit 1 to the CEC 1989 Form 10-K, File No.
2-30057).
10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as amended May 16,
1980, December 31, 1980 and June 1, 1982, respectively (Filed as
Exhibits 1, 2, and 3 to the CE 1992 Form 10-K, File No. 2-7749).
70
10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended April 27, 1984
and June 15, 1984, respectively (Exhibit 1 to the CEC Form 10-Q (June
1984), File No. 2-30057).
10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985 (Exhibit 1 to
the CEC Form 10-Q (March 1985), File No. 2-30057).
10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986 (Exhibit 1 to
the CEC Form 10-Q (March 1986), File No. 2-30057).
10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986 (Exhibit 1 to
the CEC Form 10-Q (June 1986), File No. 2-30057).
10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19, 1986 (Exhibit 1
to the CEC 1986 Form 10-K, File No. 2-30057).
10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12, 1987 (Exhibit
1 to the CEC 1987 Form 10-K, File No. 2-30057).
10.1.8.10 Settlement Agreement and Twenty-Second Amendment to 10.1.8, both dated
January 13, 1989 (Exhibit 4 to the CEC 1988 Form 10-K, File No.
2-30057).
10.1.9 Purchase and Sale Agreement together with an implementing Addendum
dated December 31, 1981, between CE and CEC, for the purchase and sale
of the CE 3.52% joint-ownership interest in the Seabrook units, dated
January 2, 1981 (Refiled as Exhibit 4 to the CE 1992 Form 10-K, File
No. 2-7749).
10.1.10 Agreement to transfer ownership, construction and operational interest
in the Seabrook Units 1 and 2 from CE to CEC dated January 2, 1981
(Refiled as Exhibit 3 to the 1991 CE Form 10-K, File No. 2-7749).
10.1.11 Power Contract, as amended to February 28, 1990, superseding the Power
Contract dated September 1, 1986 and amendment dated June 1, 1988,
between CEC (seller) and CE and CEL (purchasers) for seller's entire
share of the Net Unit Capability of Seabrook 1 and related energy
(Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2-30057).
10.1.12 Agreement between NBGEL and Central Maine Power Company (CMP), for the
joint-ownership, construction and operation of William F. Wyman Unit
No. 4 dated November 1, 1974 together with Amendment No. 1 dated June
30, 1975 (Exhibit 13(N) to the NBGEL Form S-1, File No. 2-54955).
71
10.1.12.1 Amendments No. 2 and 3 to 10.1.12 as amended August 16, 1976 and
December 31, 1978 (Exhibit 5(a) 14 to the Parent's Form S-16 (June
1979), File No. 2-64731).
10.1.13 Agreement between the registrant and Montaup Electric Company (MEC)
for use of common facilities at Canal Units I and II and for
allocation of related costs, executed October 14, 1975 (Exhibit 1 to
the CEC 1985 Form 10-K, File No. 2-30057).
10.1.13.1 Agreement between the registrant and MEC for joint-ownership of Canal
Unit II, executed October 14, 1975 (Exhibit 2 to the CEC 1985 Form
10-K, File No. 2-30057).
10.1.13.2 Agreement between the registrant and MEC for lease relating to Canal
Unit II, executed October 14, 1975 (Exhibit 3 to the CEC 1985 Form
10-K, File No. 2-30057).
10.1.14 Contract between CEC and NBGEL and CEL, affiliated companies, for the
sale of specified amounts of electricity from Canal Unit 2 dated
January 12, 1976 (Exhibit 7 to the Parent's 1985 Form 10-K, File No.
1-7316).
10.1.15 Capacity Acquisition Agreement between CEC,CEL and CE dated September
25, 1980 (Refiled as Exhibit 1 to the 1991 CEC Form 10-K, File No.
2-30057).
10.1.15.1 Amendment to 10.1.15 as amended and restated June 1, 1993, henceforth
referred to as the Capacity Acquisition and Disposition Agreement,
whereby Canal Electric Company, as agent, in addition to acquiring
power may also sell bulk electric power which Cambridge Electric Light
Company and/or Commonwealth Electric Company owns or otherwise has the
right to sell (Exhibit 1 to Canal Electric's Form 10-Q (September
1993), File No. 2-30057).
10.1.16 Phase 1 Vermont Transmission Line Support Agreement and Amendment No.
1 thereto between Vermont Electric Transmission Company, Inc. and
certain other New England utilities, dated December 1, 1981 and June
1, 1982, respectively (Exhibits 5 and 6 to the CE 1992 Form 10-K, File
No. 2-7749).
10.1.16.1 Amendment No. 2 to 10.1.16 as amended November 1, 1982 (Exhibit 5 to
the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.16.2 Amendment No. 3 to 10.1.16 as amended January 1, 1986 (Exhibit 2 to
the CE 1986 Form 10-K, File No. 2-7749).
10.1.17 Power Purchase Agreement between Pioneer Hydropower, Inc. and CE for
the purchase of available hydro-electric energy produced by a facility
located in Ware, Massachusetts, dated September 1, 1983 (Refiled as
Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
72
10.1.18 Power Purchase Agreement between Corporation Investments, Inc. (CI),
and CE for the purchase of available hydro-electric energy produced by
a facility located in Lowell, Massachusetts, dated January 10, 1983
(Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.18.1 Amendment to 10.1.18 between CI and Boott Hydropower, Inc., an
assignee therefrom, and CE, as amended March 6, 1985 (Exhibit 8 to the
CE 1984 Form 10-K, File No. 2-7749).
10.1.19 Phase 1 Terminal Facility Support Agreement dated December 1, 1981,
Amendment No. 1 dated June 1, 1982 and Amendment No. 2 dated November
1, 1982, between New England Electric Transmission Corporation (NEET),
other New England utilities and CE (Exhibit 1 to the CE Form 10-Q
(June 1984), File No. 2-7749).
10.1.19.1 Amendment No. 3 to 10.1.19 (Exhibit 2 to the CE Form 10-Q (June 1986),
File No. 2-7749).
10.1.20 Preliminary Quebec Interconnection Support Agreement dated May 1,
1981, Amendment No. 1 dated September 1, 1981, Amendment No. 2 dated
June 1, 1982, Amendment No. 3 dated November 1, 1982, Amendment No. 4
dated March 1, 1983 and Amendment No. 5 dated June 1, 1983 among
certain New England Power Pool (NEPOOL) utilities (Exhibit 2 to the CE
Form 10-Q (June 1984), File No. 2-7749).
10.1.21 Agreement with Respect to Use of Quebec Interconnection dated December
1, 1981, Amendment No. 1 dated May 1, 1982 and Amendment No. 2 dated
November 1, 1982 among certain NEPOOL utilities (Exhibit 3 to the CE
Form 10-Q (June 1984), File No. 2-7749).
10.1.21.1 Amendatory Agreement No. 3 to 10.1.21 as amended June 1, 1990, among
certain NEPOOL utilities (Exhibit 1 to the CEC Form 10-Q (September
1990), File No. 2-30057).
10.1.22 Phase I New Hampshire Transmission Line Support Agreement between NEET
and certain other New England Utilities dated December 1, 1981
(Exhibit 4 to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.23 Agreement, dated September 1, 1985, with Respect To Amendment of
Agreement With Respect To Use Of Quebec Interconnection, dated
December 1, 1981, among certain NEPOOL utilities to include Phase II
facilities in the definition of "Project" (Exhibit 1 to the CEC Form
10-Q (September 1985), File No. 2-30057).
10.1.24 Agreement to Preliminary Quebec Interconnection Support Agreement -
Phase II among Public Service Company of New Hampshire (PSNH), New
England Power Co. (NEP), BECO and CEC whereby PSNH assigns a portion
of its interests under the original Agreement to the other three
parties, dated October 1, 1987 (Exhibit 2 to the CEC 1987 Form 10-K,
File No. 2-30057).
73
10.1.25 Preliminary Quebec Interconnection Support Agreement - Phase II among
certain New England electric utilities dated June 1, 1984 (Exhibit 6
to the CE Form 10-Q (June 1984), File No. 2-7749).
10.1.25.1 First, Second and Third Amendments to 10.1.25 as amended March 1,
1985, January 1, 1986 and March 1, 1987, respectively (Exhibit 1 to
the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.25.2 Fifth, Sixth and Seventh Amendments to 10.1.25 as amended October 15,
1987, December 15, 1987 and March 1, 1988, respectively (Exhibit 1 to
the CEC Form 10-Q (June 1988), File No. 2-30057).
10.1.25.3 Fourth and Eighth Amendments to 10.1.25 as amended July 1, 1987 and
August 1, 1988, respectively (Exhibit 3 to the CEC Form 10-Q
(September 1988), File No. 2-30057).
10.1.25.4 Ninth and Tenth Amendments to 10.1.25 as amended November 1, 1988 and
January 15, 1989, respectively (Exhibit 2 to the CEC 1988 Form 10-K,
File No. 2-30057).
10.1.25.5 Eleventh Amendment to 10.1.25 as amended November 1, 1989 (Exhibit 4
to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.25.6 Twelfth Amendment to 10.1.25 as amended April 1, 1990 (Exhibit 1 to
the CEC Form 10-Q (June 1990), File No. 2-30057).
10.1.26 Phase II Equity Funding Agreement for New England Hydro-Transmission
Electric Company, Inc. (New England Hydro) (Massachusetts), dated June
1, 1985, between New England Hydro and certain NEPOOL utilities
(Exhibit 2 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.27 Phase II Massachusetts Transmission Facilities Support Agreement dated
June 1, 1985, refiled as a single agreement incorporating Amendments 1
through 7 dated May 1, 1986 through January 1, 1989, respectively,
between New England Hydro and certain NEPOOL utilities (Exhibit 2 to
the CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.28 Phase II New Hampshire Transmission Facilities Support Agreement dated
June 1, 1985, refiled as a single agreement incorporating Amendments 1
through 8 dated May 1, 1986 through January 1, 1990, respectively,
between New England Hydro-Transmission Corporation (New Hampshire
Hydro) and certain NEPOOL utilities (Exhibit 3 to the CEC Form 10-Q
(September 1990), File No. 2-30057).
10.1.29 Phase II Equity Funding Agreement for New Hampshire Hydro, dated June
1, 1985, between New Hampshire Hydro and certain NEPOOL utilities
(Exhibit 3 to the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.29.1 Amendment No. 1 to 10.1.29 dated May 1, 1986 (Exhibit 6 to the CEC
Form 10-Q (March 1987), File No. 2-30057).
74
10.1.29.2 Amendment No. 2 to 10.1.29 as amended September 1, 1987 (Exhibit 3 to
the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.30 Phase II New England Power AC Facilities Support Agreement, dated June
1, 1985, between NEP and certain NEPOOL utilities (Exhibit 6 to the
CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.30.1 Amendments Nos. 1 and 2 to 10.1.30 as amended May 1, 1986 and February
1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q (March 1987),
File No. 2-30057).
10.1.30.2 Amendments Nos. 3 and 4 to 10.1.30 as amended June 1, 1987 and
September 1, 1987, respectively (Exhibit 5 to the CEC Form 10-Q
(September 1987), File No. 2-30057).
10.1.31 Agreement Authorizing Execution of Phase II Firm Energy Contract,
dated September 1, 1985, among certain NEPOOL utilities in regard to
participation in the purchase of power from Hydro-Quebec (Exhibit 8 to
the CEC Form 10-Q (September 1985), File No. 2-30057).
10.1.32 Agreements by and between Swift River Company and CE for the purchase
of available hydro-electric energy to be produced by units located in
Chicopee and North Willbraham, Massachusetts, both dated September 1,
1983 (Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-7749).
10.1.33 Power Purchase Agreement by and between SEMASS Partnership, as seller,
to construct, operate and own a solid waste disposal facility at its
site in Rochester, Massachusetts and CE, as buyer of electric energy
and capacity, dated September 8, 1981 (Exhibit 17 to the CE 1984 Form
10-K, File No. 2-7749).
10.1.33.1 Power Sales Agreement to 10.1.33 for all capacity and related energy
produced, dated October 31, 1985 (Exhibit 2 to the CE 1985 Form 10-K,
File No. 2-7749).
10.1.33.2 Amendment to 10.1.33 for all additional electric capacity and related
energy to be produced by an addition to the Original Unit, dated March
14, 1990 (Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2-7749).
10.1.33.3 Amendment to 10.1.33 for all additional electric capacity and related
energy to be produced by an addition to the Original Unit, dated May
24, 1991 (Exhibit 1 to CE Form 10-Q (June 1991), File No. 2-7749).
10.1.34 Power Sale Agreement by and between CE (buyer) and Northeast Energy
Associated, Ltd. (NEA) (seller) of electric energy and capacity, dated
November 26, 1986 (Exhibit 1 to the CE Form 10-Q (March 1987), File
No. 2-7749).
10.1.34.1 First Amendment to 10.1.34 as amended August 15, 1988 (Exhibit 1 to
the CE Form 10-Q (September 1988), File No. 2-7749).
75
10.1.34.2 Second Amendment to 10.1.34 as amended January 1, 1989 (Exhibit 2 to
the CE 1988 Form 10-K, File No. 2-7749).
10.1.34.3 Power Sale Agreement dated August 15, 1988 between NEA and CE for the
purchase of 21 MW of electricity (Exhibit 2 to the CE Form 10-Q
(September 1988), File No. 2-7749).
10.1.34.4 Amendment to 10.1.34.3 as amended January 1, 1989 (Exhibit 3 to the CE
1988 Form 10-K, File No. 2-7749).
10.1.35 Power Purchase Agreement and First Amendment, dated September 5, 1989
and August 3, 1990, respectively, by and between Commonwealth Electric
(buyer) and Dartmouth Power Associates Limited Partnership (seller),
whereby buyer will purchase all of the energy (67.6 MW) produced by a
single gas turbine unit (Exhibit 1 to the CE Form 10-Q (June 1992),
File No. 2-7749).
10.1.35.1 Second Amendment, dated June 23, 1994, to 10.1.50 by and between
Commonwealth Electric Company and Dartmouth Power Associates, L.P.
dated September 5, 1989 (Exhibit 4 to the CE Form 10-Q (June 1995),
File No. 2-7749).
10.1.36 Power Purchase Agreement by and between Masspower (seller) and
Com-monwealth Electric Company (buyer) for a 11.11% entitlement to the
electric capacity and related energy of a 240 MW gas-fired
cogen-eration facility, dated February 14, 1992 (Exhibit 1 to
Common-wealth Electric's Form 10-Q (September 1993), File No. 2-7749).
10.1.37 Power Sale Agreement by and between Altresco Pittsfield, L.P. (seller)
and Commonwealth Electric Company (buyer) for a 17.2% entitlement to
the electric capacity and related energy of a 160 MW gas-fired
cogeneration facility, dated February 20, 1992 (Exhibit 2 to
Commonwealth Electric's Form 10-Q (September 1993), File No. 2-7749).
10.1.37.1 System Exchange Agreement by and among Altresco Pittsfield, L.P.,
Cambridge Electric Light Company, Commonwealth Electric Company and
New England Power Company, dated July 2, 1993 (Exhibit 3 to
Commonwealth Electric's Form 10-Q (September 1993), File No 2-7749).
10.1.37.2 Power Sale Agreement by and between Altresco Pittsfield, L. P.
(seller) and Cambridge Electric Light Company (Cambridge Electric)
(buyer) for a 17.2% entitlement to the electric capacity and related
energy of a 160 MW gas-fired cogeneration facility, dated February 20,
1992 (Exhibit 1 to Cambridge Electric's Form 10-Q (September 1993),
File No. 2-7909).
10.1.37.3 First Amendment, dated November 7, 1994, to 10.1.37 by and between
Commonwealth Electric Company and Altresco Pittsfield, L.P. dated
February 20, 1992 (Filed as Exhibit 3 to Commonwealth Electric
Company's Form 10-Q (June 1995), File 2-7749).
76
10.1.37.4 First Amendment, dated November 7, 1994, to 10.1.37.2 by and between
Cambridge Electric Light Company and Altresco Pittsfield, L.P. dated
February 20, 1992 (Filed as Exhibit 2 to Cambridge Electric Light
Company's Form 10-Q (June 1995), File 2-7909).
10.2.1 Transportation Agreement between CNG and CG to provide for
transportation of natural gas on a daily basis from Steuben Gas
Storage Company to TGP (Exhibit 10 to the CG 1991 Form 10-K, File No.
2-1647).
10.3.1 Pension Plan for Employees of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1, 1993 (Exhibit
1 to CES Form 10-Q (September 1993), File No. 1-7316).
10.3.2 Employees Savings Plan of Commonwealth Energy System and Subsid-iary
Companies as amended and restated January 1, 1993 (Exhibit 2 to CES
Form 10-Q (September 1993), File No. 1-7316).
10.3.2.1 First Amendment to 10.3.2, effective October 1, 1994. (Exhibit 1 to
CES Form S-8 (January 1995), File No. 1-7316).
10.3.2.2 Second Amendment to 10.3.2, effective April 1, 1996 (Exhibit 1 to CES
Form 10-K/A Amendment No. 1 (April 30, 1996), File No. 1-7316).
10.3.2.3 Third Amendment to 10.3.2, effective January 1, 1997 (Exhibit 1 to CES
Form 10-K/A Amendment No. 1 (April 29, 1997), File No. 1-7316).
10.3.3 New England Power Pool Agreement (NEPOOL) dated September 1, 1971 as
amended through August 1, 1977, between NEGEA Service Corporation, as
agent for CEL, CEC, NBGEL, and various other electric utilities
operating in New England together with amendments dated August 15,
1978, January 31, 1979 and February 1, 1980. (Exhibit 5(c)13 to New
England Gas and Electric Association's Form S-16 (April 1980), File
No. 2-64731).
10.3.3.1 Thirteenth Amendment to 10.3.3 as amended September 1, 1981 (Refiled
as Exhibit 3 to the Parent's 1991 Form 10-K, File No. 1-7316).
10.3.3.2 Fourteenth through Twentieth Amendments to 10.3.3 as amended December
1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985,
August 15, 1985 and September 1, 1985, respectively (Exhibit 4 to the
CES Form 10-Q (September 1985), File No. 1-7316).
10.3.3.3 Twenty-first Amendment to 10.3.3 as amended to January 1, 1986
(Exhibit 1 to the CES Form 10-Q (March 1986), File No. 1-7316).
10.3.3.4 Twenty-second Amendment to 10.3.3 as amended to September 1, 1986
(Exhibit 1 to the CES Form 10-Q (September 1986), File No. 1-7316).
10.3.3.5 Twenty-third Amendment to 10.3.3 as amended to April 30, 1987 (Exhibit
1 to the CES Form 10-Q (June 1987), File No. 1-7316).
77
10.3.3.6 Twenty-fourth Amendment to 10.3.3 as amended March 1, 1988 (Exhibit 1
to the CES Form 10-Q (March 1989), File No. 1-7316).
10.3.3.7 Twenty-fifth Amendment to 10.3.3. as amended to May 1, 1988 (Exhibit 1
to the CES Form 10-Q (March 1988), File No. 1-7316).
10.3.3.8 Twenty-sixth Agreement to 10.3.3 as amended March 15, 1989 (Exhibit 1
to the CES Form 10-Q (March 1989), File No. 1-7316).
10.3.3.9 Twenty-seventh Agreement to 10.3.3 as amended October 1, 1990 (Exhibit
3 to the CES 1990 Form 10-K, File No. 1-7316).
10.3.3.10 Twenty-eighth Agreement to 10.3.3 as amended September 15, 1992
(Exhibit 1 to the CES Form 10-Q (September 1994), File No. 1-7316).
10.3.3.11 Twenty-ninth Agreement to 10.3.3 as amended May 1, 1993 (Exhibit 2 to
the CES Form 10-Q (September 1994), File No. 1-7316).
10.3.4 Guarantee Agreement by CEL (as guarantor) and MYA Fuel Company (as
initial lender) covering the unconditional guarantee of a portion of
the payment obligations of Maine Yankee Atomic Power Company under a
loan agreement and note initially between Maine Yankee and MYA Fuel
Company (Exhibit 3 to the CEL Form 10-K for 1985, File No. 2-7909).
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998, 1997
(Dollars in Thousands)
Additions
---------------------------
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 $14,158(a) $23,098 $5,260 $20,089 $22,427
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
(a) The beginning balance includes $5,092,000 that relates to COM/Energy's
reserve balance at the merger date of August 25, 1999.
78
FORM 10K NSTAR 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.
NSTAR
By: /s/ James J. Judge
---------------------------------------
James J. Judge
Senior Vice President, Chief
Financial Officer and Treasurer
Date: March 25, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934 this report
has been signed below by the following persons on behalf of the registrant and
in the capacities indicated on the 25th day of March 2000.
/s/ Thomas J. May Chairman of the Board
- ----------------------------------- and Chief Executive Officer
Thomas J. May
/s/ Robert J. Weafer, Jr. Vice President, Controller and
- ----------------------------------- Chief Accounting Officer
Robert J. Weafer, Jr.
/s/ Kevin C. Bryant Trustee
- -----------------------------------
Kevin C. Bryant
/s/ Sheldon A. Buckler Trustee
- -----------------------------------
Sheldon A. Buckler
/s/ Gary L. Countryman Trustee
- -----------------------------------
Gary L. Countryman
Trustee
- -----------------------------------
Peter H. Cressy
/s/ Thomas G. Dignan, Jr. Trustee
- -----------------------------------
Thomas G. Dignan, Jr.
79
Trustee
- -----------------------------------
Richard J. Egan
Trustee
- -----------------------------------
Betty L. Francis
/s/ Charles K. Gifford Trustee
- -----------------------------------
Charles K. Gifford
/s/ Nelson S. Gifford Trustee
- -----------------------------------
Nelson S. Gifford
/s/ Matina S. Horner Trustee
- -----------------------------------
Matina S. Horner
/s/ Franklin M. Hundley Trustee
- -----------------------------------
Franklin M. Hundley
/s/ Paul A. La Camera Trustee
- -----------------------------------
Paul A. La Camera
/s/ Thomas J. May Trustee
- -----------------------------------
Thomas J. May
/s/ William J. O'Brien Trustee
- -----------------------------------
William J. O'Brien
/s/ Sherry H. Penney Trustee
- -----------------------------------
Sherry H. Penney
Trustee
- -----------------------------------
Herbert Roth Jr.
Trustee
- -----------------------------------
Stephen J. Sweeney
/s/ Gerald L. Wilson Trustee
- -----------------------------------
Gerald L. Wilson
/s/ Russell D. Wright Trustee
- -----------------------------------
Russell D. Wright
80
Report of Independent Accountants
To the Board of Directors and Shareholders
of NSTAR:
In our opinion, the consolidated financial statements listed in the index
appearing under Item 14(a)(1) on page 63 and listed in the index appearing under
Item 14(a)(2) on page 63, respectively, present fairly, in all material
respects, the financial position of NSTAR and its subsidiaries at December 31,
1999 and 1998, and the 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)(1) on page 63 and listed in the index appearing under Item
14(a)(2) on page 63, respectively, 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 the
financial statement schedule based on our audits. We conducted our audits of
these statements and schedule 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
81
Selected Consolidated Financial Statistics (Unaudited)
1999(a) 1998 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------------------
Operating revenues (000) $ 1,851,427 $ 1,622,515 $ 1,776,233 $ 1,666,303 $ 1,628,503
Earnings available for
common (000) $ 140,503 $ 132,281 $ 131,493 $ 126,181 $ 96,739(b)
Per common share:
Earnings $ 2.77 $ 2.76 $ 2.71 $ 2.61(a) $ 2.08(b)
Dividends declared $ 1.955 $ 1.880 $ 1.880 $ 1.835 $ 1.775
Dividends paid $ 1.94 $ 1.88 $ 1.88 $ 1.82 $$1.76
Book value $ 26.25 $ 22.13 $ 21.37 $ 20.61 $ 20.11
Payout ratio 70% 68% 69% 72% 88%(b)
Return on average common
equity 11.7% 12.3% 12.4% 12.4% 10.0%
Year-end dividend yield 4.9% 4.7% 5.0% 7.0% 6.4%
Fixed charge coverage (SEC) 2.32 2.74 2.50 2.91 2.38
Capitalization:
Total debt 47% 48% 51% 52% 54%
Preferred equity 3% 4% 7% 8% 8%
Common equity 50% 48% 42% 40% 38%
Long-term debt (000) $ 986,843 $ 955,563 $ 1,057,076 $ 1,058,644 $ 1,160,223
Mandatory redeemable
preferred stock (000) $ 49,279 $ 49,040 $ 80,093 $ 83,465 $ 86,837
Total assets (000) $ 5,483,013 $ 3,213,899 $ 3,622,347 $ 3,729,291 $ 3,637,170
Internal generation after
dividends (000) $ 276,636 $ 116,002 $ 240,362 $ 257,446 $ 184,492
Plant expenditures (000) $ 154,295 $ 120,202 $ 114,110 $ 145,347 $ 180,822
Internal generation 174% 97% 211% 177% 102%
Common shares outstanding:
Weighted average 50,795,874 47,973,402 48,514,958 48,264,734 46,591,662
Year-end 58,059,646 47,184,073 48,514,973 48,509,537 48,003,178
Stock price:
High $44 5/8 $44 15/16 $38 3/8 $30 1/8 $29 1/2
Low $36 7/16 $35 1/16 $24 5/8 $21 3/4 $23 1/8
Year-end $40 1/2 $41 3/16 $37 7/8 $26 7/8 $29 1/2
Year-end market
value (000) $ 2,351,416 $ 1,943,394 $ 1,837,505 $ 1,303,694 $ 1,416,094
Trading volume
(shares) 20,131,700 33,574,000 37,732,900 41,105,700 23,078,900
Market/book ratio
(year-end) 1.52 1.85 1.71 1.26 1.43
Price/earnings ratio
(year-end) 14.6 14.9 14.0 10.3 14.2(b)
Number of utility employees
At year-end 3,381 2,919 3,227 3,362 3,812
(a) Due to the application of the purchase method of accounting, the results
for 1999 reflect 8 months of BEC energy and 4 months of NSTAR.
(b) Amounts excluding $34 million pre-tax restructuring charge:
Earnings available
for common (000) $ 117,403
Earnings $ 2.52
Payout ratio 72%
Return on average
common equity 12.2%
Price/earnings ratio 11.7
Certain reclassifications and recalculations were made to the data reported in
prior years to conform with the method of presentation used in 1997.