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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
----- -----
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
--------------------------- -----------------------------
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
--------------
(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
- --------------------------------------------------------------------------------
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%
===========================================================================
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
------ ------ ------
(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%
----------------------------------------
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
- --------------------------------------------
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.
12
(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