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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, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-14768
NSTAR
(Exact name of registrant as specified in its charter)
Massachusetts 04-3466300
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
800 Boylston Street, Boston, Massachusetts 02199
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on which
Title of each class registered
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 ]
Indicate by check mark whether the registrant is an
accelerated filer (as defined in Rule 12b-2 of the Act).
YES [ X ] NO [ ]
The aggregate market value of the 53,032,546 shares of voting
stock of the registrant held by non-affiliates of the registrant,
computed as the average of the high and low market prices of the
common shares as reported on the New York Stock Exchange
consolidated transaction reporting system for NSTAR Common Shares
as of the last business day of the registrant's most recently
completed second fiscal quarter: $2,353,319,229.
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 27, 2003
Common Shares, $1 par value 53,032,546 Shares
Documents Incorporated by Reference Part in Form 10-K
Portions of the Registrant's Definitive Parts I, II and III
Proxy Statement Dated March 27, 2003
(pages as specified herein)
List of exhibits begins on page 95 of this report.
NSTAR
Form 10-K Annual Report - December 31, 2002
Page
Part I
Item 1. Business 2
Item 2. Properties 10
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 12
Item 4A. Executive Officers of the Registrant 12
Part II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters 13
Item 6. Selected Consolidated Financial Data 14
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 15
Item 7A. Quantitative and Qualitative Disclosures About 50
Market Risk
Item 8. Financial Statements and Supplementary Financial 51
Information
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 93
Part III
Item 10. Trustees and Executive Officers of the Registrant 93
Item 11. Executive Compensation 93
Item 12. Security Ownership of Certain Beneficial Owners and 93
Management
Item 13. Certain Relationships and Related Transactions 94
Part IV
Item 14. Controls and Procedures 94
Item 15. Exhibits, Financial Statement Schedules and Reports 95
on Form 8-K
___________________________________
Signatures 102
Certification Statements 104
Part I
Item 1. Business
NSTAR makes available on its website at www.nstaronline.com
("Financial info, SEC filings"), its annual report on Form 10-K,
quarterly reports on Form 10-Q, current reports on Form 8-K,
and all amendments to those reports as soon as reasonably
practicable after such material is electronically filed with or
furnished to the Securities and Exchange Commission (SEC). NSTAR
provides this service free of charge.
(a) General Development of Business
NSTAR is an energy delivery company focusing its activities in
the transmission and distribution of energy. NSTAR serves
approximately 1.4 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 0.3 million gas customers in 51 communities. NSTAR is a
public utility holding company generally exempt from the
provisions of the Public Utility Holding Company Act of 1935.
NSTAR's retail utility subsidiaries are Boston Edison Company
(Boston Edison), Commonwealth Electric Company (ComElectric),
Cambridge Electric Light Company (Cambridge Electric) and NSTAR
Gas Company (NSTAR Gas). Its wholesale electric subsidiary is
Canal Electric Company (Canal). NSTAR's three retail electric
companies operate under the brand name "NSTAR Electric."
Reference in this report to "NSTAR" shall mean the registrant
NSTAR or one or more of its subsidiaries as the context requires.
Reference in this report to "NSTAR Electric" shall mean each of
Boston Edison, ComElectric and Cambridge Electric. NSTAR's non-
utility, unregulated operations include district energy
operations (Advanced Energy Systems, Inc. and NSTAR Steam
Corporation), telecommunications operations - NSTAR
Communications, Inc. (NSTAR Com) and a liquefied natural gas
service company (Hopkinton LNG Corp.). Utility operations
accounted for approximately 96% of revenues in 2002, 2001 and
2000.
NSTAR was created in 1999 through the merger of BEC Energy (BEC)
and Commonwealth Energy System (COM/Energy). An integral part of
the merger that created NSTAR was the rate plan of the retail
utility subsidiaries of BEC and COM/Energy that was approved by
the Massachusetts Department of Telecommunications and Energy
(MDTE) in an order issued on July 27, 1999. Significant elements
of the rate plan include a four-year distribution rate freeze
through August 2003, recovery of the acquisition premium
(goodwill) over 40 years and recovery of transaction and
integration costs (costs to achieve) over 10 years. Refer to the
"Retail Electric Rates" section in Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" for more information.
In 1998, Boston Edison completed the sale of all of its fossil
generating assets and in 1999 sold its Pilgrim Nuclear Generating
Station. COM/Energy sold substantially all of its fossil
generating assets in 1998 and Canal sold its 3.52% ownership
interest in the Seabrook Nuclear Power Station in November 2002.
Refer to the "Generating Assets Divestiture" section in Item 7,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" for more information.
(b) Financial Information about Industry Segments
NSTAR's principal operating segments are the electric and natural
gas utilities that provide energy delivery services in 107 cities
and towns in Massachusetts and its unregulated operations. Refer
to Note L of the Consolidated Financial Statements in Item 8,
"Financial Statements and Supplementary Financial Information"
for specific financial information related to NSTAR's electric
utility, gas utility and unregulated operating segments.
(c) Narrative Description of Business
Principal Products and Services
NSTAR Electric
NSTAR Electric's operating revenues and energy sales percentages
by customer class for the years 2002, 2001 and 2000 consisted of
the following:
Revenues ($) Energy Sales (kWh)
Retail: 2002 2001 2000 2002 2001 2000
Commercial 52% 51% 49% 56% 55% 55%
Residential 37% 33% 33% 29% 28% 28%
Industrial and other 8% 9% 10% 10% 11% 11%
Wholesale and contract 3% 7% 8% 5% 6% 6%
NSTAR Electric currently supplies electricity at retail to an
area of 1,702 square miles. The territory served includes the
City of Boston and 80 surrounding cities and towns including
Cambridge, New Bedford and Plymouth and the geographic area
comprising Cape Cod and Martha's Vineyard. The population of
this area is approximately 2.3 million. In 2002, NSTAR Electric
served approximately 1.1 million customers.
Retail Electric Rates
Unbundled delivery rates are established by the MDTE and 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 costs for
previously held investments in generating plants and current
costs related to above market power contracts), a transmission
charge (to collect the cost of moving the electricity over high
voltage lines from a generating plant), an energy conservation
charge (to collect costs for demand-side management programs) and
a renewable energy charge (to collect the cost to support the
development and promotion of renewable energy projects).
Electric distribution companies in Massachusetts are required to
obtain and resell power to retail customers through either
standard offer service or default service for those who choose
not to buy energy from a competitive energy supplier. Standard
offer service will be available to eligible customers through
February 2005 at prices approved by the MDTE, set at levels so as
to guarantee mandatory overall rate reductions provided by the
Massachusetts Electric Restructuring Act of 1997 (Restructuring
Act). New retail customers in the NSTAR Electric service
territories and other customers who are no longer eligible for
standard offer service and have not chosen to receive service
from a competitive supplier are provided default service. The
price of default service is intended to reflect the average
competitive market price for power. As of December 31, 2002 and
2001, customers of NSTAR Electric had approximately 27% and 16%,
respectively, of their load requirements provided by competitive
suppliers.
Sources and Availability of Electric Power Supply
NSTAR Electric expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the Restructuring Act and MDTE
orders. NSTAR Electric has existing long-term power purchase
agreements that are expected to supply approximately 80%-85% of
its standard offer service obligation for 2003. NSTAR Electric
has contracted with a third party supplier to provide 100% of its
standard offer supply obligation through December 31, 2003. In
connection with this arrangement, NSTAR Electric has assigned its
long-term power purchase agreements to this supplier through
December 31, 2003. NSTAR Electric is recovering its payments to
suppliers through MDTE approved rates billed to customers. NSTAR
Electric's existing portfolio of long-term power purchase
contracts supplied the majority of its standard offer (including
wholesale) energy requirements in 2002. Also during 2002, NSTAR
Electric entered into an agreement whereby all of its energy
supply resource entitlements were transferred to an independent
energy supplier, following which NSTAR Electric repurchased its
energy resource needs from this independent energy supplier for
NSTAR Electric's ultimate sale to standard offer customers.
NSTAR Electric has entered into a short-term power purchase
agreement to meet its entire default service supply obligation
for the period January 1, 2003 through June 30, 2003 and for 50%
of its obligation for the second-half of 2003. A Request for
Proposals will be issued in the second quarter of 2003 for the
remainder of the obligation. NSTAR Electric entered into
agreements ranging in length from five to twelve-months effective
January 1, 2002 through December 31, 2002 with suppliers to
provide full default service energy and ancillary service
requirements at contract rates approved by the MDTE.
NSTAR's electric load reached an all-time level peak demand of
4,501 megawatts (MW) on August 14, 2002 and surpassed the 2001
peak load by 1.1%.
Independent System Operator - New England (ISO-NE)
Prior to March 1, 2003, ISO-NE dispatched generating units based
on the lowest operating costs of available generation and
transmission. Under this structure, generators were required to
provide ISO-NE with market prices at which they sell short-term
energy supply. For each participant actively involved in the
power market, the imbalance in energy provided by a participant
and the energy consumed by such participant in each hour is
settled at a single real-time clearing hourly price for such
power. Pursuant to orders issued by the Federal Energy
Regulatory Commission (FERC) in September and December of 2002,
these markets have been further restructured into Standard Market
Design (SMD), which began on March 1, 2003. SMD provides an
additional market in which wholesale power costs can be hedged a
day in advance through binding financial commitments. Also,
under SMD, wholesale power clearing prices vary by location, with
prices increasing in areas where less efficient resources close
to the load are dispatched to meet the load requirements due to
the fact that the more efficient resources cannot be imported as
a result of transmission limitations. As part of the movement to
SMD, load-serving entities, like NSTAR, will be granted proceeds
from the auction of "financial transmission rights" that is
conducted by ISO-NE. Holders of these rights are essentially
entitled to the positive differences in the prices between the
locations specified for such rights and are subject to additional
costs for negative differences. NSTAR can either use these
proceeds to mitigate costs to customers directly or transfer them
to the suppliers of its energy resource needs to reduce the cost
to customers. Therefore, the impact of the change to SMD on
NSTAR's costs to meet its standard offer service and default
service obligations are mitigated somewhat.
NSTAR Gas
NSTAR Gas' operating revenues and energy sales percentages by
customer class for the years 2002, 2001 and 2000, consisted of
the following:
Revenues ($) Energy Sales (therms)
Gas Sales and 2002 2001 2000 2002 2001 2000
Transportation:
Residential 64% 58% 59% 42% 43% 41%
Commercial 21% 27% 24% 34% 34% 32%
Industrial and other 9% 10% 11% 19% 18% 17%
Off-System and contract sales 6% 5% 6% 5% 5% 10%
NSTAR Gas distributes natural gas to approximately 0.3 million
customers in 51 communities in central and eastern Massachusetts
covering 1,067 square miles and having an aggregate population of
1,176,000. Twenty-five of these communities are also served with
electricity by NSTAR Electric. Some of the larger communities
served by NSTAR Gas include Cambridge, Somerville, New Bedford,
Plymouth, Worcester, Framingham, Dedham and the Hyde Park area of
Boston.
Natural Gas Industry Restructuring and Rates
Effective November 1, 2000, the MDTE approved regulations that
expand the choice of gas supplier to all customers of local gas
distribution companies (LDCs) such as NSTAR Gas. The regulations
established a five-year transition period and a three-year review
of market conditions to determine whether the capacity market has
become sufficiently competitive to warrant removal or
modification of the LDC's service obligation with respect to
planning and procurement. To meet the requirements of the
restructuring regulations, NSTAR Gas has modified its billing,
customer and gas supply systems to accommodate full retail
choice. The MDTE previously had approved the compliance process
submitted by NSTAR Gas and other LDCs that implement the
unbundling of retail gas services to all customers. Among the
important provisions are: setting the LDC as the default service
provider, certification of competitive suppliers/marketers,
extension of the MDTE's consumer protection rules to residential
customers taking competitive service, requirement for LDCs to
provide suppliers/marketers with customer usage data, and
requirement for suppliers/marketers to disclose service terms to
potential customers. The MDTE has also ruled on requiring the
mandatory assignment of the LDC's upstream pipeline and storage
capacity and downstream peaking capacity to customers who elect a
competitive gas supply. This eliminates potential stranded cost
exposure for the LDCs.
NSTAR Gas generates revenues primarily through the sale and/or
transportation of natural gas. Gas sales and transportation
services are divided into two categories: firm, whereby NSTAR Gas
must supply gas and/or transportation services to customers on
demand; and interruptible, whereby NSTAR Gas may, generally
during colder months, temporarily discontinue service to high
volume commercial and industrial customers. Sales and
transportation of gas to interruptible customers do not
materially affect NSTAR Gas' operating income because
substantially the entire margin on such service is returned to
its firm customers as cost reductions.
In addition to delivery service rates, NSTAR Gas' tariffs include
a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local
Distribution Adjustment Clause (LDAC). The CGAC provides for the
recovery of all gas supply costs from firm sales customers or
default service customers. The LDAC provides for the recovery of
certain costs applicable to both sales and transportation
customers. The CGAC is filed semi-annually for approval by the
MDTE. The LDAC is filed annually for approval. In addition,
NSTAR Gas is required to file interim changes to its CGAC factor
when the actual costs of gas supply vary from projections by more
than 5%.
Gas Supply
NSTAR Gas maintains a flexible resource portfolio consisting of
gas supply contracts, transportation contracts on interstate
pipelines, market area storage and peaking services. In order to
control costs and to efficiently manage the gas supply needs of
its customers, NSTAR Gas optimizes its supply mix to ensure
maximum resource utilization.
NSTAR Gas purchases transportation, storage and balancing
services from Tennessee Gas Pipeline Company and Algonquin Gas
Transmission Company, as well as other upstream pipelines that
bring gas from major producing regions in the U.S., Gulf of
Mexico and Canada to the final delivery points in the NSTAR Gas
service area. NSTAR Gas purchases all of its gas supplies from
third-party vendors, primarily under firm contracts with terms of
less than one year. The vendors vary from small independent
marketers to major gas and oil producers. Based on its firm
pipeline transportation capacity entitlements, NSTAR Gas
contracts for up to 140,309 Million British thermal units (MMBtu)
per day of domestic production. In addition, NSTAR Gas has an
agreement for up to 4,500 MMBtu per day of Canadian supplies.
In addition to the firm transportation and gas supplies mentioned
above, NSTAR Gas utilizes contracts for underground storage and
liquefied natural gas (LNG) facilities to meet its winter peaking
demands. The LNG facilities, described below, are located within
NSTAR Gas' distribution system and are used to liquefy and store
pipeline gas during the warmer months for use during the heating
season. The underground storage contracts are a combination of
existing and new agreements that are the result of FERC Order 636
service unbundling. During the summer injection season, excess
pipeline capacity is used to deliver and store gas in market area
storage facilities, located in the New York and Pennsylvania
region. Stored gas is withdrawn during the winter season to
supplement pipeline supplies in order to meet firm heating
demand. NSTAR Gas has firm storage capacity entitlements of over
7.5 billion cubic feet (Bcf).
A portion of the storage of gas supply for NSTAR Gas during the
winter heating season is provided by Hopkinton LNG Corp.
(Hopkinton), a wholly-owned unregulated subsidiary of NSTAR. The
facility in Hopkinton, Massachusetts consists of a liquefaction
and vaporization plant and three above ground cryogenic storage
tanks having an aggregate capacity of 3 Bcf 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 0.5 Bcf of natural
gas that are filled with LNG trucked from Hopkinton or purchased
from third parties.
Based upon information presently available regarding projected
growth in demand and estimates of availability of future supplies
of pipeline gas, NSTAR Gas believes that its present sources of
gas supply are adequate to meet existing load and allow for
future growth in sales.
Franchises
Through their charters, which are unlimited in time, NSTAR
Electric and NSTAR Gas have the right to engage in the business
of distributing and selling electricity and natural gas and 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 pipelines are obtained from municipal and other
state authorities which, in granting these locations, act as
agents for the state. In some cases the actions of these
authorities are subject to appeal to the MDTE. The rights to
these locations are not limited in time and are subject to the
action of these authorities and the legislature. No other entity
shall provide distribution service within NSTAR's territory
without the written consent of NSTAR Electric and/or NSTAR Gas.
This consent must be filed with the MDTE and the municipality so
affected.
Unregulated Operations
NSTAR's unregulated operations segment engages in businesses that
include district energy operations, telecommunications and
liquefied natural gas service. District energy operations are
principally provided through its Advanced Energy Systems, Inc.
(AES) facility that generates chilled water, steam and
electricity for use by hospitals and teaching facilities located
in Boston's Longwood Medical Area. AES is expanding its Medical
Area Total Energy Plant (MATEP) facility in 2003 to provide
additional capacity. NSTAR Steam also supplies steam customers
in Cambridge and Boston. Telecommunications services are
provided through NSTAR Com, which installs, owns, operates and
maintains a wholesale transport network for other
telecommunications service providers in the metropolitan Boston
area to deliver voice, video, data and internet services to
customers. Liquefied natural gas service is provided by
Hopkinton LNG Corp. In 2000, NSTAR's subsidiary Northwind Boston
LLC (Northwind) notified its chilled water customers of its
decision to exit the business and that service ceased effective
September 30, 2002, in accordance with its contractual
obligations.
RCN Joint Venture and Investment Conversion
NSTAR Com participated in a telecommunications venture with RCN
Telecom Services, Inc. of Massachusetts, a subsidiary of RCN
Corporation (RCN), prior to the conversion of its equity interest
into common shares of RCN, as further discussed below. NSTAR Com
accounted for its investment in the joint venture using the
equity method of accounting. As part of the Joint Venture
Agreement, NSTAR Com had the option to exchange portions of its
joint venture interest for common shares of RCN at specified
periods. As of December 31, 2002, NSTAR Com no longer
participates in the joint venture but holds 11.6 million common
shares of RCN. The investment in these common shares is
accounted for as marketable securities in accordance with
Statement of Financial Accounting Standards (SFAS) No. 115,
"Accounting for Certain Investments in Debt and Equity
Securities" (SFAS 115). Under SFAS 115, NSTAR has classified its
investment in RCN securities as available for sale.
NSTAR Com recognized impairments of its investment in RCN in the
first quarter of 2001 and in the second and fourth quarters of
2002. For a further discussion, refer to the "Investments -
Available for Sale Securities" section in Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of
Operations."
Regulation
NSTAR Electric, NSTAR Gas, and Boston Edison's wholly owned
regulated subsidiary, Harbor Electric Energy Company, 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 Electric and NSTAR Gas utility businesses, including rates
for electricity and natural gas sold at wholesale, facilities
used for the transmission or sale of that energy, certain
issuances of short-term debt and regulation of the accounting.
NSTAR is a holding company exempt from the provisions of the
Public Utility Holding Company Act of 1935, as amended, except
Section 9(c)(2) relating to SEC approval of certain acquisitions
of securities of public utility or public utility holding
companies.
Capital Expenditures and Financings
The most recent estimates of capital expenditures and long-term
debt maturities requirements for the years 2003 through 2007 are
as follows:
2003 2004 2005 2006 2007
(in thousands)
Capital expenditures $286,000 $250,000 $202,000 $178,000 $180,000
Long-term debt $212,746 $ 78,659 $177,562 $ 98,024 $ 83,218
Management continuously reviews its capital expenditure and
financing programs. These programs and, therefore, the estimates
included in this Form 10-K are subject to revision due to changes
in regulatory requirements, operating requirements, environmental
standards, availability and cost of capital, interest rates and
other assumptions.
Plant expenditures in 2002 were $368.1 million and consisted
primarily of additions to NSTAR's distribution and transmission
systems. The majority of these expenditures were for system
reliability and performance improvements, customer service
enhancements and capacity expansion to meet long-range growth in
the NSTAR service territory.
Refer to the "Liquidity and Capital Resources" section of Item 7,
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" for more information regarding capital
resources to fund NSTAR's construction programs.
Seasonal Nature of Business
NSTAR Electric 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. NSTAR Gas' sales are
positively impacted by colder weather because a substantial
portion of its customer base uses natural gas for space heating
purposes. Refer to the "Selected Consolidated Quarterly
Financial Data" section in Item 6, "Selected Consolidated
Financial Data" for specific financial information by quarter for
2002 and 2001.
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 marketplace
by combining the resources of its utility subsidiaries activities
in the transmission and distribution of energy.
Environmental Matters
NSTAR's 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. Refer to the "Contingencies - Environmental Matters"
section in Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" for more
information.
Management believes that its facilities are in substantial
compliance with currently applicable statutory and regulatory
environmental requirements.
Number of Employees
As of December 31, 2002, NSTAR had approximately 3,300 employees,
including approximately 2,400, or 73% of whom are represented by
three collective bargaining units covered by separate contracts.
Local 369 of the Utility Workers Union of America, AFL-CIO,
represents approximately 2,075 employees with a five-year
contract that expires on May 15, 2005.
A collective bargaining unit contract representing approximately
260 employees expired on March 31, 2002. On March 24, 2002,
Local 12004, United Steelworkers of America, AFL-CIO-CLC,
ratified a new four-year contract that expires on March 31, 2006.
Approximately 70 employees of Advanced Energy Systems' MATEP
subsidiary are represented by Local 877, the International Union
of Operating Engineers, AFL-CIO, through a labor agreement that
expires on September 30, 2006.
Management believes it has satisfactory relations with its
employees.
(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
NSTAR Electric properties include an integrated system of
distribution lines and substations, an office building and other
structures such as garages and service centers that are located
primarily in eastern Massachusetts.
At December 31, 2002, the NSTAR Electric primary and secondary
transmission and distribution system consisted of approximately
20,300 circuit miles of overhead lines, approximately 8,500
circuit miles of underground lines, 266 substation facilities and
approximately 1,121,000 active customer meters.
NSTAR Electric's high-tension transmission lines are generally
located on land either owned or subject to perpetual and
exclusive easements in its favor. Its low-tension distribution
lines are located principally on public property under permission
granted by municipal and other state authorities.
NSTAR, through its Canal subsidiary, sold its 3.52% ownership
interest (40.5 MW of capacity) in the Seabrook Nuclear Generating
Station on November 1, 2002.
NSTAR Gas' principal natural gas properties consist of
distribution mains, services and meters necessary to maintain
reliable service to customers. At December 31, 2002, the gas
system included approximately 2,900 miles of gas distribution
lines, approximately 176,300 services and approximately 270,700
customer meters together with the necessary measuring and
regulating equipment. In addition, NSTAR (through Hopkinton LNG
Corp.) 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 Bcf of
natural gas. NSTAR Gas owns an office and service building in
Southborough, Massachusetts, three district office buildings and
several natural gas receiving and take stations.
In 2002, NSTAR purchased a 370,000 square foot office building
(the Summit) sited on 33 acres in the Boston suburb of Westwood,
Massachusetts. This site is centrally located in NSTAR's service
area and houses central administrative offices including customer
care, finance, human resources, sales, engineering, and
information technology.
District energy operations primarily consist of the MATEP
facility located in the Longwood Medical Area of Boston. MATEP
provides steam, chilled water and electricity to over 9 million
square feet of medical and teaching facilities. NSTAR Steam's
distribution system consists primarily of approximately 3.5 miles
of high pressure steam lines to customers in Cambridge and
Boston.
Item 3. Legal Proceedings
Merger Rate Plan Appeal
On December 16, 2002, the Massachusetts Supreme Judicial Court
(SJC) affirmed the MDTE's 1999 decision to allow for the merger
of BEC and COM/Energy as originally structured. The SJC decision
finalized the resolution of all issues relating to this appeal
and did not have any impact on NSTAR's 2002 or prior periods'
consolidated financial position, cash flows or results of
operations. The 1999 MDTE order approving the rate plan
associated with the merger of BEC and COM/Energy, was appealed to
the SJC by the Massachusetts Attorney General (AG) and a separate
group that consisted of The Energy Consortium (TEC) and Harvard
University (Harvard). TEC and Harvard alleged that, in approving
the rate plan and merger proposal, the MDTE committed errors of
law in the following areas: (1) in adopting a public interest
standard, the MDTE applied the wrong standard of review, and
failed to investigate the propriety of rates and to determine
that the resulting rates of Boston Edison, Cambridge Electric,
ComElectric and NSTAR Gas were just and reasonable; (2) that in
permitting Cambridge Electric and ComElectric to adjust their
rates by $49.8 million to reflect demand-side management costs,
the MDTE failed to determine whether such an adjustment was
warranted in light of other cost decreases; (3) that the MDTE's
approval results in an arbitrary and unjustified sharing of
benefits and costs between ratepayers and shareholders; and (4)
that the MDTE's approval of the rate plan guarantees shareholders
recovery of future costs without any future demonstration of
customer savings. The AG made similar arguments in each of these
areas and added that, in allowing recovery of the acquisition
premium, the MDTE improperly deviated from a cost basis in
setting approved rates and the ratemaking policies in other
jurisdictions.
Other Legal Matters
In the normal course of its business, NSTAR and its subsidiaries
are involved in certain legal matters, including civil lawsuits.
Management is unable to fully determine a range of reasonably
possible court-ordered damages, settlement amounts, and related
litigation costs ("legal liabilities") that would be in excess of
amounts accrued. Based on the information currently available,
NSTAR does not believe that it is probable that any such
additional legal liability will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal liabilities that may result from
changes in estimates could have a material impact on its results
of operations for a reporting period.
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 2002.
Item 4A. Executive Officers of Registrant
Identification of Executive Officers
Age at
December 31,
Name of Officer Position and Business Experience 2002
Thomas J. May Chairman, President (since 2002), 55
Chief Executive Officer and a
Trustee (since 1999); formerly
Chairman, President and Chief
Executive Officer and a Trustee
(1998-1999), BEC Energy, and
Chairman, President and Chief
Executive Officer and a Director
(1995-1999), Boston Edison
Company; Director, FleetBoston
Financial; Liberty Mutual Holding
Company Inc.; New England Business
Services, Inc. and RCN
Corporation.
Douglas S. Horan Senior Vice President - Strategy, 53
Law and Policy, Secretary and
General Counsel (since 2000);
formerly Senior Vice President -
Strategy, Law and Policy (1999-
2000); Senior Vice President -
Strategy and Law and General
Counsel, BEC Energy (1998-1999)
and Boston Edison Company (1995-
1999).
James J. Judge Senior Vice President, Treasurer 46
and Chief Financial Officer (since
2000); formerly Senior Vice
President and Chief Financial
Officer (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).
Timothy R. Manning Senior Vice President - Human 51
Resources (since 2002); formerly
Vice President Human Resources
(2001); Director of Employee and
Labor Relations (1999-2001);
Director of Human Resources,
Boston Edison Company (1998-1999).
Age at
December 31,
Name of Officer Position and Business Experience 2002
Joseph R. Nolan, Jr. Senior Vice President - Customer 39
Care and Corporate Relations
(since 2002); formerly Senior Vice
President - Corporate Relations
(2000-2002); Vice President of
Government Affairs (1999-2000);
Director of Regulatory Relations,
BEC Energy (1998-1999); Manager of
Legislative Affairs, Boston Edison
Company (1994-1998).
Werner J. Schweiger Senior Vice President - Operations 43
(since 2002); formerly Vice
President, Office of Electric
Operations/Transmission and
Distribution Management, Keyspan
Energy Corporation (1997-2002).
Eugene J. Zimon Senior Vice President - 54
Information Technology (since
2001); formerly Vice President,
Business Development for
Utilities, Oracle Corporation
(2000-2001); Vice President,
Information Services, Boston Gas
Company (1996-2000).
Robert J. Weafer, Jr. Vice President, Controller and 55
Chief Accounting Officer (since
1999); formerly Vice President,
Controller and Chief Accounting
Officer, BEC Energy (1998-1999)
and Boston Edison Company (1991-
1998).
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. NSTAR's closing market price at December 31, 2002
was $44.39 per share.
The high and low market values per common share as reported by
the New York Stock Exchange composite transaction reporting
system for each of the quarters in 2002 and 2001 were as follows:
2002 2001
High Low High Low
First quarter $46.00 $42.30 $42.69 $33.94
Second quarter $48.20 $43.66 $43.85 $36.78
Third quarter $45.17 $34.00 $45.05 $39.50
Fourth quarter $44.70 $36.90 $45.24 $40.10
(b) Holders
As of December 31, 2002, there were 28,262 holders of NSTAR
common shares.
(c) Dividends
Dividends declared per common share for each of the quarters in
2002 and 2001 were as follows:
2002 2001
First quarter $0.53 $0.515
Second quarter $0.53 $0.515
Third quarter $0.53 $0.515
Fourth quarter $0.54 $0.53
Item 6. Selected Consolidated Financial Data
The following table summarizes five years of selected
consolidated financial data.
(in thousands, except per share data)
2002 2001 2000 1999(c) 1998(d)
Operating revenues $2,719,067 $3,191,836 $2,692,762 $1,851,427 $1,622,515
Net income (a) $ 163,667 $ 3,201 $ 180,962 $ 146,463 $ 141,046
Earnings (loss) per share
of common stock:
Basic (a) $ 3.05 $ (0.05) $ 3.19 $ 2.77 $ 2.76
Diluted (a) $ 3.03 $ (0.05) $ 3.18 $ 2.76 $ 2.75
Total assets $6,123,275 $5,328,191 $5,547,715 $5,466,143 $3,204,036
Long-term debt (b) $1,645,465 $1,377,899 $1,440,431 $ 986,843 $ 955,563
Transition property
securitization (b) $ 445,890 $ 513,904 $ 584,130 $ 646,559 $ -
Redeemable preferred
stock of subsidiary (b) $ 43,000 $ 43,000 $ 43,000 $ 92,279 $ 92,040
Cash dividends declared
per common share $ 2.13 $ 2.075 $ 2.015 $ 1.955 $ 1.895
(a) 2002 and 2001 include non-cash, after-tax charges oF $17.7 million
and $173.9 million, or $0.33 per share and $3.28 per share,
respectively, related to NSTAR's investment in RCN Corporation.
(b) Excludes the current portion of long-term debt and preferred stock.
(c) Due to the application of the purchase method of accounting, the
results for 1999 reflect eight months of BEC Energy and four months
of NSTAR.
(d) Results for 1998 reflect only BEC Energy.
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
Earnings
(Loss) Earnings
Net Available (Loss)
Income for Common Per Basic
Operating Operating (Loss) Shareholders Common Share
Revenues Income (a) (a) (a)
2002
First quarter $722,865 $ 76,715 $ 34,794 $ 34,304 $ 0.65
Second quarter $600,446 $ 69,061 $ 5,690 $ 5,200 $ 0.10
Third quarter $701,001 $117,141 $ 73,717 $ 73,227 $ 1.38
Fourth quarter $694,755 $ 74,680 $ 49,466 $ 48,976 $ 0.92
2001
First quarter $864,822 $ 89,268 $(132,256) $(133,746) $ (2.52)
Second quarter $732,273 $ 81,677 $ 37,710 $ 36,220 $ 0.68
Third quarter $890,748 $114,983 $ 68,636 $ 67,146 $ 1.27
Fourth quarter $703,993 $ 64,833 $ 29,111 $ 27,954 $ 0.52
(a) The second quarter of 2002 includes a non-cash, after-tax impairment
charge of $27.6 million, or $0.52 per share, related to NSTAR's
investment in RCN Corporation common stock.
The fourth quarter of 2002 includes a net gain of $9.9 million,
or $0.19 per share, that reflects the recognition of tax benefits
of $19.6 million, or $0.37 per share, related to NSTAR's investment
in RCN Corporation offset, in part, by an additional non-cash,
after-tax impairment charge of $9.7 million, or $0.18 per share,
associated with the RCN investment.
The first quarter of 2001 includes a non-cash, after-tax
charge of $173.9 million, or $3.28 per share, related to the
RCN investment.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations (MD&A)
Overview
NSTAR is an energy delivery company focusing its activities in
the transmission and distribution of energy. NSTAR serves
approximately 1.4 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 0.3 million gas customers in 51 communities. NSTAR is a
public utility holding company generally exempt from the
provisions of the Public Utility Holding Company Act of 1935.
NSTAR's retail utility subsidiaries are Boston Edison Company
(Boston Edison), Commonwealth Electric Company (ComElectric),
Cambridge Electric Light Company (Cambridge Electric) and NSTAR
Gas Company (NSTAR Gas). Its wholesale electric subsidiary is
Canal Electric Company (Canal). NSTAR's three retail electric
companies operate under the brand name "NSTAR Electric."
Reference in this report to "NSTAR" shall mean the registrant
NSTAR or one or more of its subsidiaries as the context requires.
Reference in this report to "NSTAR Electric" shall mean each of
Boston Edison, ComElectric and Cambridge Electric. NSTAR's non-
utility, unregulated operations include district energy
operations (Advanced Energy Systems, Inc. and NSTAR Steam
Corporation), telecommunications operations - NSTAR
Communications, Inc. (NSTAR Com) and a liquefied natural gas
service company (Hopkinton LNG Corp.). Utility operations
accounted for approximately 96% of revenues in 2002, 2001 and
2000.
Cautionary Statement
This MD&A contains certain forward-looking statements such as
forecasts and projections of expected future performance or
statements of management's plans and objectives. These forward-
looking statements may also be contained in other filings with
the SEC, in press releases and oral statements. You can identify
these statements by the fact that they do not relate strictly to
historical or current facts. They use words such as
"anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe" and other words and terms of similar meaning in
connection with any discussion of future operating or financial
performance. These statements are based on the current
expectations, estimates or projections of management and are not
guarantees of future performance. Some or all of these forward-
looking statements may not turn out to be what NSTAR expected.
Actual results could potentially differ materially from these
statements. Therefore, no assurance can be given that the
outcomes stated in such forward-looking statements and estimates
will be achieved.
The impact of continued cost control procedures on operating
results could differ from current expectations. NSTAR's revenues
from its electric and gas sales are sensitive to weather, the
economy and other variable conditions. Accordingly, NSTAR's sales
in any given period reflect, in addition to other factors, the
impact of weather, with colder winter temperatures generally
resulting in increased gas sales and warmer summer temperatures
generally resulting in increased electric sales. NSTAR
anticipates that these sensitivities to seasonal and other
weather conditions will continue to impact its sales forecasts in
future periods. The effects of changes in weather, economic
conditions, tax rates, interest rates, technology, and prices and
availability of operating supplies could materially affect the
projected operating results.
NSTAR's forward-looking information is based in large measure on
prevailing governmental policies and regulatory actions,
including those of the MDTE and the FERC, with respect to allowed
rates of return, rate structure, continued recovery of regulatory
assets, financings, purchased power and cost of gas recovery,
acquisition and disposition of assets, operation and construction
of facilities, changes in tax laws and policies and changes in
and compliance with environmental and safety laws and policies.
The impacts of various environmental, legal, and regulatory
matters could differ from current expectations. New regulations
or changes to existing regulations could impose additional
operating requirements or liabilities other than expected. The
effects of changes in specific hazardous waste site conditions
and the specific cleanup technology could affect the estimated
cleanup liabilities. The impacts of changes in available
information and circumstances regarding legal issues could affect
any estimated litigation costs.
NSTAR undertakes no obligation to publicly update forward-looking
statements, whether as a result of new information, future
events, or otherwise. You are advised, however, to consult all
further disclosures NSTAR makes in its filings to the SEC. Also
note that NSTAR provided in the above paragraphs a cautionary
discussion of risks and other uncertainties relative to its
business. These are factors that could cause its actual results
to differ materially from expected and historical performance.
Other factors in addition to those listed here could also
adversely affect NSTAR. This report also describes material
contingencies and critical accounting policies and estimates
in this section and in the accompanying Notes to Consolidated
Financial Statements, and NSTAR encourages a review of these
Notes.
Critical Accounting Policies and Estimates
NSTAR's discussion and analysis of its financial condition,
results of operations and cash flows are based upon the
accompanying Consolidated Financial Statements, which have been
prepared in accordance with accounting principles generally
accepted in the United States of America (GAAP). The preparation
of these Consolidated Financial Statements required management to
make estimates and judgments that affect the reported amount of
assets and liabilities, revenues and expenses, and related
disclosure of contingent assets and liabilities at the date of
the Consolidated Financial Statements. Actual results may differ
from these estimates under different assumptions or conditions.
Critical accounting policies and estimates are defined as those
that are reflective of significant judgment and uncertainties,
and potentially may result in materially different outcomes under
different assumptions and conditions. NSTAR believes that its
accounting policies and estimates that are most critical to the
reported results of operations, cash flows and financial position
are described below.
a. Revenue Recognition
Utility revenues are based on authorized rates approved by the
MDTE and FERC. Estimates of transmission, distribution and
transition revenues for electricity and natural gas delivered to
customers but not yet billed are accrued at the end of each
accounting period. The determination of unbilled revenues
requires management to estimate the volume and pricing of
electricity and gas delivered to customers prior to actual meter
readings.
Revenues related to the sale, transmission and distribution of
energy are generally recorded when service is rendered or energy
is delivered to customers. However, the determination of the
energy sales to individual customers is based on the reading of
their meters that are read on a systematic basis throughout the
month. Meters which are not read during a given month are
estimated and trued-up in a future period. At the end of each
month, amounts of energy delivered to customers since the date of
the last billing date are estimated and the corresponding
unbilled revenue is estimated. This unbilled electric revenue is
estimated each month based on daily generation volumes (territory
load), line losses and applicable customer rates. Unbilled
natural gas revenues are estimated based on estimated purchased
gas volumes and tariffed rates in effect. Accrued unbilled
revenues recorded in the accompanying Consolidated Balance Sheets
as of December 31, 2002 and 2001 were $47 million and $51
million, respectively.
NSTAR's non-utility revenues are recognized when services are
rendered or when the energy is delivered. Revenues are based,
for the most part, on long-term contractual rates.
b. Regulatory Accounting
NSTAR follows accounting policies prescribed by GAAP, the FERC
and the MDTE. As a rate-regulated company, NSTAR is subject to
the Financial Accounting Standards Board, Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation" (SFAS 71). The application of
SFAS 71 results in differences in the timing of recognition of
certain revenues and expenses from that of other businesses and
industries. NSTAR's energy delivery business remains subject to
rate-regulation and continues to meet the criteria for
application of SFAS 71. This ratemaking process results in the
recording of regulatory assets based on the probability of
current and future cash inflows. Regulatory assets represent
incurred costs that have been deferred because they are probable
of future recovery in customer rates. As of December 31, 2002
and 2001, NSTAR has recorded regulatory assets of $2 billion
and $1 billion, respectively. This increase is primarily the
result of the recognition of certain purchased power costs.
NSTAR continuously reviews these assets to assess their ultimate
recoverability within the approved regulatory guidelines. NSTAR
expects to fully recover these regulatory assets in its rates.
If future recovery of costs ceases to be probable, NSTAR would be
required to charge these assets to current earnings. However,
impairment risk associated with these assets relates to
potentially adverse legislative, judicial or regulatory actions
in the future. Regulatory assets related to the generation
business are recovered through the transition charge.
c. Derivative Instruments - Power Contracts
Typically, the electric power industry contracts to buy and sell
electricity under option contracts, which allow the buyer some
flexibility in determining when to take electricity and in what
quantity to match fluctuating demand. These contracts would
normally meet the definition of a derivative requiring mark-to-
market accounting. However, because electricity cannot be stored
and an entity is obligated to maintain sufficient capacity to
meet the electricity needs of its customer base, an option
contract for the purchase of electricity typically qualifies for
the normal purchases and sales exception described in SFAS No.
133, "Accounting for Derivative Instruments and Hedging
Activities" and Derivative Implementation Group (DIG) Issue No.
C15, "Scope Exceptions: Normal Purchases and Normal Sales
Exception for Option-Type Contracts and Forward Contracts in
Electricity."
NSTAR Electric has long-term purchased power agreements that are
used primarily to meet its standard offer obligation. The
majority of these agreements are above-market but are not
reflected on the accompanying Consolidated Balance Sheets as they
qualify for the normal purchases and sales exception. However,
in Issue C15, the DIG concluded that contracts with a pricing
mechanism that are subject to future adjustment based on a
generic index that is not specifically related to the contracted
service commodity generally would not qualify for the normal
purchases and sales exception. NSTAR has six purchased power
contracts that contain components with pricing mechanisms that
are based on a pricing index, such as the GNP or CPI. Although
these factors are only applied to certain ancillary pricing
components of these agreements, as required by the interpretation
of DIG Issue C15, NSTAR began recording these contracts at fair
value on its Consolidated Balance Sheets during 2002. This
action resulted in the recognition of a liability for the fair
value of the above-market portion of these contracts at December
31, 2002 of approximately $701 million and is reflected as a
component of Deferred credits - Power contracts on the
accompanying Consolidated Balance Sheets.
These contracts are valued using a discounted cash flow model and
a 10% discount rate. The market value assumption used was
provided by a third party who determines such pricing for the New
England power market. Had management used an alternative
assumption, the value of these contracts at December 31, 2002
would have changed significantly. A one percent increase or
decrease to the discount rate would change the above market value
by approximately $27 million from what is presently recorded.
NSTAR Electric recovers all of its electricity supply costs,
including the above-market costs. The recovery of its above-
market costs occurs through 2016 for Boston Edison, through 2023
for ComElectric and through 2011 for Cambridge Electric. These
recovery periods coincide with the contractual terms of these
purchased power agreements. Therefore, in addition to the
liability recorded, NSTAR also recorded a corresponding
regulatory asset representing the future recovery of these actual
costs.
d. Pension and Other Postretirement Benefits
NSTAR's pension and other postretirement benefits costs are
dependent upon several factors and assumptions, such as employee
demographics, the level of cash contributions made to the plans,
earnings on the plans' assets, the discount rate, the expected
long-term rate of return on the plans' assets and health care
cost trends.
In accordance with SFAS No. 87, "Employers' Accounting for
Pensions" (SFAS 87) and SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106), changes
in pension and postretirement benefit obligations other than
pensions (PBOP) associated with these factors may not be
immediately recognized as pension and PBOP costs in the
statements of income, but generally are recognized in future
years over the remaining average service period of the plans'
participants.
There were no changes to NSTAR's pension plan benefits in 2002,
2001 and 2000 that had a significant impact on recorded pension
costs. As further described in Note G to the accompanying
Consolidated Financial Statements, NSTAR has revised the discount
rate in 2002 as compared to 2001 and 2000. In addition, NSTAR
revised the expected long-term rate of return on its pension and
PBOP plan assets for 2003 to 8.4% and 8%, respectively, reduced
from 9.4% and 9% in 2002, respectively. These changes will have
a significant impact on reported pension costs in future years in
accordance with the cost recognition approach of SFAS 87
described above. This impact will be mitigated, to an extent,
through NSTAR's regulatory accounting treatment of pension and
PBOP costs. (See further discussion of regulatory accounting
treatment below). In determining pension obligation and cost
amounts, these assumptions may change from period to period, and
such changes could result in material changes to recorded pension
and PBOP costs and funding requirements.
NSTAR's Pension Plan (the Plan) assets, which partially consist
of equity investments, have been affected by significant declines
in the equity markets in the past three years. Fluctuations in
equity market returns may result in increased or decreased
pension costs in future periods. These conditions impacted the
funded status of the Plan at December 31, 2002, and therefore,
will also impact pension costs for 2003.
The following chart reflects the projected benefit obligation and
cost sensitivities associated with a change in certain actuarial
assumptions by the indicated percentage. Each sensitivity below
reflects an evaluation of the change based solely on a change in
that assumption.
(in thousands) Impact on
Projected
Benefit Impact on 2002 Cost
Actuarial Assumption Change in Assumption Obligation (Increase)/Decrease
Pension:
Increase in discount rate 50 basis points $ (48,693) $ (3,220)
Decrease in discount rate 50 basis points $ 52,580 $ 3,410
Increase in expected long-term
rate of return on plan assets 50 basis points NA $ 3,935
Decrease in expected long-term
rate of return on plan assets 50 basis points NA $ (3,935)
Other Postretirement Benefits:
Increase in discount rate 50 basis points $ (37,289) $ (2,235)
Decrease in discount rate 50 basis points $ 41,695 $ 2,723
Increase in expected long-term
rate of return on plan assets 50 basis points NA $ 1,164
Decrease in expected long-term
rate of return on plan assets 50 basis points NA $ (1,164)
NA-not applicable
NSTAR's discount rate is based on rates of high quality corporate
bonds as published by nationally recognized rating agencies.
In determining the expected long-term rate of return on plan
assets, NSTAR considers past performance and economic forecasts
for the types of investments held by the Plan. In 2003, NSTAR
reduced the expected long-term rate of return on plan assets from
9.4% to 8.4% as a result of the prevailing outlook for equity
market returns. Reported pension costs will increase in 2003 and
future years as a result of this changed assumption. However, as
a result of the MDTE Accounting Order (Accounting Order)
discussed below, this increase will not have a material impact on
NSTAR's results of operations.
The unfavorable market conditions have impacted the value of Plan
assets. As a result of the negative investment performance, the
Plan's accumulated benefit obligation (ABO) exceeded Plan assets
at December 31, 2002. The ABO represents the present value of
benefits earned without considering future salary increases.
Since the fair value of its Plan assets is less than the ABO,
NSTAR is required to record this difference as an additional
minimum pension liability on the accompanying Consolidated
Balance Sheets.
Under SFAS 87, NSTAR is also required to eliminate its prepaid
pension balance. The additional minimum pension liability
adjustment is equal to the sum of the minimum pension liability
and the prepaid pension that would be recorded, net of taxes, as
a non-cash charge to Other Comprehensive Income (OCI) on the
accompanying Consolidated Statements of Comprehensive Income.
The fair value of Plan assets and the ABO are measured at each
year-end balance sheet date. The minimum liability will be
adjusted each year to reflect this measurement. At such time
that the Plan assets exceed the ABO, the minimum liability would
be reversed.
In November 2002, NSTAR filed a request with the MDTE seeking an
accounting ruling to mitigate the impact of the non-cash charge
to OCI in 2002 and the increases in expected pension and PBOP
costs in 2003. On December 20, 2002, the MDTE approved the
Accounting Order. Based on this Accounting Order and an opinion
from legal counsel regarding the probability of recovery of these
costs in the future, NSTAR recorded a regulatory asset in lieu of
taking a charge to OCI at December 31, 2002. In addition, the
Accounting Order permits NSTAR to defer, as a regulatory asset or
liability, the difference between the level of pension and PBOP
expenses that are included in rates and the amounts that are
required to be recorded under SFAS 87 and SFAS 106 beginning in
2003.
The regulatory asset of $426 million, recorded as a result of
this Accounting Order, consists of the prepaid pension asset
($257 million) related to the qualified pension plan and the
minimum liability ($169 million) incurred at December 31, 2002.
The regulatory asset is shown separately in Deferred debits on
the accompanying Consolidated Balance Sheets.
NSTAR's utility subsidiaries anticipate filing with the MDTE,
during 2003, a specific mechanism designed to address pension and
PBOP costs. It is NSTAR's goal to eliminate the volatility of
these costs.
The Plan currently meets the minimum funding requirements of the
Employee Retirement Income Security Act of 1974. While not
required to make contributions to the Plan, NSTAR anticipates
increasing the level of its cash contributions to the Plan in
2003 to mitigate the projected adverse impact. Such cash
contributions may be material to its consolidated cash flows from
operations. NSTAR believes it has adequate access to capital
resources to support these contributions.
e. Investments - Available for Sale Securities
NSTAR classifies its investments in marketable securities as
available for sale. As of December 31, 2002, these investments
include 11.6 million common shares of RCN Corporation (RCN) and
represent approximately 10.6% of RCN's outstanding common shares.
As of December 31, 2001, these investments included 4.1 million
common shares of RCN, 148,400 common shares of John Hancock
Financial Services, Inc. (John Hancock), and 141,300 common
shares of MetLife, Inc. (MetLife). During 2002, NSTAR sold all
of its common shares in John Hancock and MetLife for a gain of
$4.9 million. This gain is recorded as part of Other Income, net
in the accompanying Consolidated Statements of Income.
In accordance with its accounting policies, NSTAR continuously
evaluates the carrying value of its investment in RCN common
shares to assess whether any decline in the market value below
its carrying value is deemed to be "other-than-temporary."
Consistent with the performance of the telecommunications sector
as a whole, the market value of RCN's common shares decreased
significantly during the later part of 2000 and continued to
decrease through 2002. As a result, in 2001 and 2002, management
determined that this decline in market value was "other-than-
temporary" in accordance with SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities."
NSTAR recognized non-cash, after-tax impairment charges in 2002
and 2001 on its investment in RCN common shares of $17.7 million
and $173.9 million, respectively. These charges are reported on
the accompanying Consolidated Statements of Income as "Write-down
of RCN Investment, net."
The total carrying value of the 11.6 million RCN common shares is
included in Other investments on the accompanying Consolidated
Balance Sheets at its estimated fair value of approximately $6.1
million at December 31, 2002. The fair value of the 11.6 million
shares held may increase or decrease as a result of changes in
the market value of RCN common shares. As of December 31, 2002
and 2001, the market value per share of RCN was $0.53 and $2.93,
respectively. The unrealized gain or loss associated with these
shares will fluctuate due to the changes in fair value of these
securities during each period and is reflected, net of associated
income taxes, as a component of Other comprehensive income, net
on the accompanying Consolidated Statements of Comprehensive
Income. The cumulative increase or decrease in fair value of
these shares including the impact of the write-down adjustments
of these shares are included in Accumulated other comprehensive
income on the accompanying Consolidated Balance Sheets.
f. Decommissioning Cost Estimates
The accounting for decommissioning costs of nuclear power plants
involves significant estimates related to costs to be incurred
many years in the future. Changes in these estimates will not
affect NSTAR's results of operations or cash flows because these
costs will be collected from customers through NSTAR's transition
charge filings with the MDTE.
While NSTAR no longer directly owns any nuclear power plants,
NSTAR Electric collectively owns, through its equity investments,
14% of Connecticut Yankee Atomic Power Company (CYAPC), 14% of
Yankee Atomic Electric Company (YAEC), and 4% of Maine Yankee
Atomic Power Company, (the "Yankee Companies"). Periodically,
NSTAR obtains estimates from the management of the Yankee
Companies on the cost of decommissioning the Connecticut Yankee
nuclear unit (CY), the Yankee Atomic nuclear unit (YA), and the
Maine Yankee nuclear unit (MY). These nuclear units are
completely shut down and are currently conducting decommissioning
activities.
Based on estimates from the Yankee Companies' management as of
December 31, 2002, the total remaining cost for decommissioning
each nuclear unit is approximately as follows: $248 million for
CY, $225 million for YA and $166 million for MY. Of these
amounts, NSTAR Electric is obligated to pay $34.7 million towards
the decommissioning of CY, $31.5 million toward YA, and $6.6
million toward MY. These estimates are recorded in the
accompanying Consolidated Balance Sheets as Power contract
liabilities with a correspond- ing regulatory asset. These
estimates may be revised from time to time based on information
available to the Yankee Companies regarding future costs.
NSTAR expects the Yankee Companies to seek recovery of these
costs and any additional increases to these costs in rate
applications with the FERC, with any resulting adjustments being
charged to their respective sponsors, including NSTAR Electric.
NSTAR Electric would recover its share of any allowed increases
from customers through the transition charge.
g. Asset Impairment Assessment
NSTAR evaluates its assets for impairment whenever indicators of
impairment exist, but at least annually. Accounting standards
require that if the sum of the undiscounted expected future cash
flows from a company's asset is less than the carrying value of
the asset, an asset impairment must be recognized in the
financial statements. The amount of impairment recognized is
calculated by subtracting the fair value of the asset from the
carrying value of the asset.
As discussed in the accompanying Notes to Consolidated Financial
Statements, NSTAR has three operating segments, one of which is
its unregulated operations that includes the telecommunications
operations. Based on the current market performance of the
telecommunications sector, NSTAR has reviewed and assessed for
impairment, in accordance with SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," its unregulated
telecommunications assets. NSTAR's judgments used in its
assessment include, but are not limited to, future anticipated
revenue streams and future operating costs. NSTAR has
determined, based on its probability assessment, that the total
of the undiscounted expected future cash flows exceeded the
carrying value of its unregulated telecommunications assets;
therefore, no impairment loss was recognized as of December 31,
2002. Although management believes that its estimates of future
revenues and expenses are reasonable, it cannot assure the
precision of such estimates. Should a further and continued
deterioration of this business sector occur, NSTAR may be
required to write-down its carrying value of these assets.
In estimating future sales and operating costs of
telecommunications services, NSTAR uses internal forecasts.
NSTAR develops these forecasts based on recent sales activity for
these services in conjunction with anticipated economic patterns
and planned and scheduled customer commitments for services.
For each assumption used in the analysis, NSTAR applied a
probability factor to each of the future cash flow scenarios.
The probability factors used were determined based on
management's experience in the telecommunications sector and the
likelihood of a change in the economic environment.
New Accounting Standards
See Note A, "New Accounting Standards," to the accompanying
Consolidated Financial Statements.
Generating Assets Divestiture
a. Seabrook Nuclear Power Station
On November 1, 2002, FPL Group, Inc. purchased 88% of the
majority ownership interest in the Seabrook Nuclear Power
Station, including Canal's 3.52% ownership interest, for $799.4
million, net of closing adjustments. FPL Group assumed
responsibility for the ultimate decommissioning of the facility
and received the Seabrook decommissioning funds of approximately
$226.9 million at the closing. Canal's portion of the sale
proceeds amounted to $31.9 million, of which $3.5 million was
paid into the decommissioning trust as a final top-off and $1.3
million was used for other transaction costs. The net proceeds
of $27.1 million were less than Canal's remaining investment in
Seabrook. The difference of approximately $16.7 million will be
included as a component of Cambridge Electric's and ComElectric's
transition cost recovery and is expected to be collected from
ComElectric's and Cambridge Electric's customers in 2003 through
the transition charge. As part of this sale, all purchased power
agreements were terminated. The Seabrook sale did not have an
impact on NSTAR's current results of operations. The future
impact of the sale will not have a material effect on results of
operations, cash flow or financial position.
b. Blackstone Station
On August 1, 2002, Cambridge Electric reached a tentative
agreement to sell Blackstone Station to Harvard University
(Harvard) for $14.6 million that will be used to reduce Cambridge
Electric's transition charge. At the same time, NSTAR Steam
signed an agreement with Harvard to sell its Blackstone steam
assets and contracts to Harvard for $3 million. The sale is
subject to the approval of the MDTE. A filing with the MDTE for
regulatory approval for this transaction was made on November 21,
2002. Under terms of this agreement, NSTAR Steam will continue
to manage the day-to-day operations of the steam plant on this
site for one year after the sale. Cambridge Electric is
divesting its electric generating assets consistent with the
provisions of the Massachusetts Electric Restructuring Act of
1997 (Restructuring Act). Cambridge Electric divested the
majority of its non-nuclear generating facilities in 1998. NSTAR
anticipates completing the Blackstone Station sale in the second
quarter of 2003.
Rate and Regulatory Proceedings
a. Distribution Rate Proceedings
On February 14, 2003, NSTAR notified the MDTE that it is in the
process of reviewing the 2002 test-year cost of service for its
utility subsidiaries in order to determine whether to request a
general base rate increase. This assessment coincides with the
expiration of NSTAR's four-year rate freeze presently in effect
as part of the Merger Rate Plan that created NSTAR. If NSTAR
decides not to seek a general base rate increase, NSTAR will
request a specific rate recovery mechanism relating to pension
and PBOP costs in conjunction with the MDTE Accounting Order
dated December 20, 2002. Management intends to finalize its
decision on the appropriate regulatory proceedings during the
second quarter of 2003.
b. Merger Rate Plan
An integral part of the merger of BEC and COM/Energy that created
NSTAR was the rate plan of the retail utility subsidiaries that
was approved by the MDTE on July 27, 1999 and affirmed by the SJC
in December 2002 as further discussed below. Significant
elements of the rate plan included a four-year distribution rate
freeze, recovery of the acquisition premium (goodwill) over 40
years and recovery of transaction and integration costs (costs to
achieve) over 10 years. Refer to the "Retail Electric Rates"
section of this MD&A for more information on retail rates and
cost recovery.
On December 16, 2002, the SJC affirmed the MDTE's 1999 decision
to allow for the merger of BEC and COM/Energy as originally
structured. The SJC's decision finalized the resolution of all
issues relating to the appeal, as described below. This decision
did not have an impact on NSTAR's 2002 or prior periods'
consolidated financial position, cash flows or results of
operations. The 1999 MDTE order, which approved the rate plan
associated with the merger, was appealed to the SJC by the
Massachusetts Attorney General (AG) and a separate group that
consisted of The Energy Consortium (TEC) and Harvard University
(Harvard). The AG, TEC and Harvard alleged that, in approving
the rate plan and merger proposal, the MDTE committed errors of
law in the following areas: (1) in adopting a public interest
standard, the MDTE applied the wrong standard of review, and
failed to investigate the propriety of rates and to determine
that the resulting rates of Boston Edison, Cambridge Electric,
ComElectric and NSTAR Gas were just and reasonable; (2) that in
permitting Cambridge Electric and ComElectric to adjust their
rates by $49.8 million to reflect demand-side management costs,
the MDTE failed to determine whether such an adjustment was
warranted in light of other cost decreases; (3) that the MDTE's
approval results in an arbitrary and unjustified sharing of
benefits and costs between ratepayers and shareholders; and (4)
that the MDTE's approval of the rate plan guarantees shareholders
recovery of future costs without any future demonstration of
customer savings. The AG's brief included similar arguments in
each of these areas and added that, in allowing recovery of the
acquisition premium, the MDTE improperly deviated from a cost
basis in setting approved rates and the ratemaking policies in
other jurisdictions.
c. Goodwill and Costs to Achieve
The merger that created NSTAR was accounted for using the
purchase method of accounting. In accordance with the MDTE's
approval of a four-year rate plan, the premium (Goodwill)
associated with the acquisition was approximately $490 million,
while the original estimate of transaction and integration costs
to achieve the merger was $111 million. The merger premium is
reflected on the accompanying Consolidated Balance Sheets as
Goodwill. This premium will continue to be amortized over 40
years and amounts to approximately $12.2 million annually, while
the costs to achieve (CTA) are being amortized over 10 years.
CTA are the costs incurred to execute the merger including the
employee costs for a voluntary severance program, costs of
financial advisers, legal costs, and other transaction and
systems integration costs. CTA is being amortized at an annual
rate of $11.1 million based on the original rate plan. NSTAR
will reconcile the actual CTA costs incurred with the original
estimate in a future rate proceeding. This reconciliation will
include a final accounting of the deductibility for income tax
purposes of each component of CTA. The total CTA is
approximately $143 million. This increase from the original
estimate is partially mitigated by the fact that the portion of
CTA that is not deductible for income tax purposes is
approximately $20 million lower than the original estimate.
NSTAR anticipates that these incremental costs are probable of
recovery in future rates. The CTA and Goodwill amounts were
filed and approved as part of the rate plan.
d. Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric
and NSTAR Gas filed proposed service quality plans for each
company with the MDTE. The service quality plans established
performance benchmarks effective January 1, 2002 for certain
identified measures of service quality relating to customer
service and billing performance, customer satisfaction, and
reliability and safety performance. The companies are required
to report annually concerning their performance as to each
measure and are subject to maximum penalties of up to two percent
of transmission and distribution revenues should performance fail
to meet the applicable benchmarks. Concurrently, NSTAR Electric
and NSTAR Gas filed with the MDTE a report of their performance
on the identified service quality measures for the two twelve-
month periods ended August 31, 2000 and 2001. This report
included a calculation of penalties in accordance with MDTE
guidelines. On March 22, 2002, following hearings on the matter,
the MDTE issued an order imposing a service quality penalty of
approximately $3.25 million on NSTAR Electric that was refunded
to customers as a credit to their bills during the month of May
2002. This refund had no material effect on NSTAR's consolidated
financial position, cash flows or results of operations in 2002.
For the four-month period ended December 31, 2001, the MDTE
determined that NSTAR's performance relative to service quality
measures did not warrant a penalty assessment.
On February 28, 2003, NSTAR Electric and NSTAR Gas filed their
2002 Service Quality Reports with the MDTE that reflected
significant improvements in reliability and performance and
indicate that no penalty will be assessed for this period. NSTAR
accounts for its service quality penalties pursuant to SFAS No.
5, "Accounting for Contingencies." Accordingly, these penalties
are monitored on a monthly basis to determine NSTAR's contingent
liability, and if NSTAR determines it is probable that a
liability has been incurred and is estimable, NSTAR would then
accrue an appropriate liability. Annually, each NSTAR utility
subsidiary makes a service quality performance filing with the
MDTE. Any settlement or rate order that would result in a
different liability (or credit) level from what has been accrued
would be adjusted in the period an agreement is reached with the
MDTE.
e. Retail Electric Rates
The Restructuring Act requires electric distribution companies to
obtain and resell power to retail customers through either
standard offer service or default service for those who choose
not to buy energy from a competitive energy supplier. Standard
offer service will be available to eligible customers through
February 2005 at prices approved by the MDTE, set at levels so as
to guarantee mandatory overall rate reductions provided by the
Restructuring Act. New retail customers in the NSTAR Electric
service territories and other customers who are no longer
eligible for standard offer service and have not chosen to
receive service from a competitive supplier are provided default
service. The price of default service is intended to reflect the
average competitive market price for power. As of December 31,
2002 and 2001, customers of NSTAR Electric had approximately 27%
and 16%, respectively, of their load requirements provided by
competitive suppliers.
In December 2002, NSTAR Electric filed proposed transition rate
adjustments for 2003, including a preliminary reconciliation of
transition, transmission, standard offer and default service
costs and revenues through 2002. The MDTE subsequently approved
tariffs for each retail electric subsidiary effective January 1,
2003. The filings were updated in February 2003 to include final
costs and revenues for 2002.
On November 14, 2002, Boston Edison and the AG received approval
of a Settlement Agreement from the MDTE resolving issues in
Boston Edison's reconciliation of costs and revenues for the year
2001. Among other issues, the Settlement Agreement includes an
adjustment relating to the reconciliation of costs relating to
securitization and efforts to mitigate costs incurred in relation
to a purchased power agreement with Hydro Quebec. As a result of
this Settlement Agreement with the AG, Boston Edison recognized
approximately $11.4 million in additional transition charge
revenues in 2002. This benefit was significantly offset by
several other regulatory true-up adjustments.
In December 2001, NSTAR Electric filed proposed transition rate
adjustments for 2002, including a preliminary reconciliation of
costs and revenues through 2001. The MDTE subsequently approved
tariffs for each retail electric subsidiary effective January 1,
2002. The filings were updated in February 2002 to include final
costs for 2001. The MDTE approved the reconciliation of costs
and revenues for Boston Edison through 2000 in its approval on
November 16, 2001 of a Settlement Agreement between Boston Edison
and the AG resolving all outstanding issues in Boston Edison's
prior reconciliation filings. As a part of this settlement,
Boston Edison agreed to reduce the costs sought to be collected
through the transition charge by approximately $2.9 million as
compared to the amounts that were originally sought. This
settlement did not have a material adverse effect on NSTAR's
consolidated financial position, results of operations or cash
flows.
On June 1, 2001, the MDTE issued its final orders on the
reconciliation of ComElectric and Cambridge Electric's
transition, standard offer service, default service and
transmission costs and revenues for 1998. ComElectric and
Cambridge Electric reached a settlement with the AG regarding the
1999 and 2000 reconciliation proceedings. Under this settlement,
the companies' future recovery of transition costs would be
reduced by approximately $7.8 million. This settlement was
approved by the MDTE on June 5, 2002 and did not have a material
adverse effect on NSTAR's 2002 consolidated financial position,
cash flows or results of operations.
During 2000, NSTAR Electric's accumulated costs to provide
default and standard offer service were in excess of the revenues
it was allowed to bill customers by approximately $242.7 million.
On January 1 and July 1, 2001, NSTAR Electric was permitted by
the MDTE to increase its rates to customers for standard offer
and default service to collect this shortfall. Furthermore, when
combined with the reduction in energy supply costs experienced in
2001 and through the first half of 2002, rates were reduced on
January 1, 2002, April 1, 2002, July 1, 2002 and January 1, 2003.
As a result, NSTAR reflected a regulatory asset of approximately
$45.4 million and $30.4 million at December 31, 2001 and 2002,
respectively, that are reflected as components of Regulatory
assets - other on the accompanying Consolidated Balance Sheets.
In December 2000, the MDTE approved a standard offer fuel index
of 1.321 cents per kilowatt-hour (kWh) that was added to each
NSTAR Electric company's standard offer service rates for the
first half of 2001. In June 2001, the MDTE approved an
additional increase of 1.23 cents per kWh effective July 1, 2001
based on a fuel adjustment formula contained in its standard
offer tariffs to reflect the prices of natural gas and oil. In
December 2001, the MDTE approved a decrease in this fuel index of
1.125 cents to 1.426 cents per kWh for the first quarter of 2002
due to a decrease in the cost of fuel. Effective April 1, 2002,
each NSTAR Electric company's fuel index was set to zero. The
MDTE has ruled that these fuel index adjustments are excluded
from the 15% rate reduction requirement under the Restructuring
Act.
f. Standard Market Design
Effective March 1, 2003, the wholesale electric energy market in
the Northeast has been restructured into what is known as
"Standard Market Design" (SMD) in conjunction with FERC orders
issued in September and December of 2002. SMD provides an
additional market in which wholesale power costs can be hedged a
day in advance through binding financial commitments. Also,
under SMD, wholesale power clearing prices vary by location, with
prices increasing in areas where less efficient resources close
to the load are dispatched to meet the load requirements due to
the fact that the more efficient resources cannot be imported as
a result of transmission limitations. SMD is not expected to
have an impact on NSTAR's results of operations because of the
recovery mechanism for wholesale energy costs approved by the
MDTE.
g. Natural Gas Industry Restructuring and Rates
NSTAR Gas generates revenues primarily through the sale and/or
transportation of natural gas. Gas sales and transportation
services are divided into two categories: firm, whereby NSTAR Gas
must supply gas and/or transportation services to customers on
demand; and interruptible, whereby NSTAR Gas may, generally
during colder months, temporarily discontinue service to high
volume commercial and industrial customers. Sales and
transportation of gas to interruptible customers do not
materially affect NSTAR Gas' operating income because
substantially the entire margin on such service is returned to
its firm customers as rate reductions.
In addition to delivery service rates, NSTAR Gas' tariffs include
a seasonal Cost of Gas Adjustment Clause (CGAC) and a Local
Distribution Adjustment Clause (LDAC). The CGAC provides for the
recovery of all gas supply costs from firm sales customers or
default service customers. The LDAC provides for the recovery of
certain costs applicable to both sales and transportation
customers. The CGAC is filed semi-annually for approval by the
MDTE. The LDAC is filed annually for approval. In addition,
NSTAR Gas is required to file interim changes to its CGAC factor
when the actual costs of gas supply vary from projections by more
than 5%.
Due to significant declines in wholesale natural gas prices,
NSTAR Gas received six consecutive approvals from the MDTE
effective March 1, 2001 through October 31, 2002 to reduce the
CGAC factor and pass those savings on to customers. In October
2002, due to the increase in wholesale natural gas prices, NSTAR
Gas was allowed by the MDTE to increase the CGAC factor for the
period from November 1, 2002 through January 1, 2003 to recover
the higher costs of gas.
In both 2002 and 2001, the CGAC was revised on four occasions to
reflect the changes in the cost of gas caused by varying market
conditions. In 2002, the CGAC ranged from $0.3828 per therm to
$0.6139 while the range for 2001 was $0.5261 per therm to
$1.1123.
Other Legal Matters
In the normal course of its business, NSTAR and its subsidiaries
are involved in certain legal matters, including civil lawsuits.
Management is unable to fully determine a range of reasonably
possible court-ordered damages, settlement amounts, and related
litigation costs ("legal liabilities") that would be in excess of
amounts accrued. Based on the information currently available,
NSTAR does not believe that it is probable that any such
additional legal liability will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal liabilities that may result from
changes in estimates could have a material impact on its results
of operations for a reporting period.
Income Tax Issues
a. Tax Valuation Allowance
SFAS 109 prohibits the recognition of all or a portion of
deferred income tax benefits if it is more likely than not that
the deferred tax asset will not be realized. NSTAR had
determined that it was more likely than not that a current or
future income tax benefit would not be realized relating to the
write-downs of its RCN investment that were recorded in the
second and fourth quarters of 2002 and previously in the first
quarter of 2001. These write-downs resulted from the significant
declines in the market value of the telecommunications sector,
including RCN. As a result of this uncertainty, NSTAR recorded a
$77.6 million tax valuation allowance on the entire tax benefit
associated with these write-downs. During 2002, as a result of
previously unanticipated capital gain transactions, NSTAR
recognized $3.9 million of this tax benefit.
Additionally, based on the Internal Revenue Service (IRS) review
of NSTAR's 1999 and 2000 federal income tax returns, NSTAR
determined that it was more likely than not that it would
ultimately recognize the tax benefits relating to the incremental
operating losses from the joint venture. The returns are
currently being audited by the IRS as part of their normal review
of NSTAR's consolidated federal income tax returns. The tax
valuation allowance included reserves relating to the tax
treatment of these losses through June 19, 2002. Each of the tax
returns filed for 1999 through 2001 claimed operating losses.
The return to be filed for 2002 will also claim the remaining
portion of these operating losses. The issues involving the
operating loss deductions recorded on the tax returns for the
years 2001 and 2002 are substantially similar to those that had
concerned NSTAR regarding the tax treatment of that item on the
1999 and 2000 returns. Based on the IRS examining agent's
current review, no adjustment for the years under audit is
proposed. A determination of this issue was arrived at in the
fourth quarter of 2002 and, as a result, NSTAR applied the
treatment of these operating losses for all years on a consistent
basis, allowing a reduction to its valuation allowance of
approximately $19.7 million as a net credit to income tax expense
included as a component of the write-down.
NSTAR has and will continue to research potential transactions
that improve the operational efficiencies of NSTAR while
maximizing the utilization of these potential tax benefits.
Should NSTAR be successful in its tax and operational planning to
allow a portion of the remaining tax benefit to be ultimately
realized, NSTAR will reflect a credit to its income tax expense.
Future earnings could be positively impacted by the outcome of
this strategy. The maximum potential positive future earnings
impact is currently estimated at $53 million. Management is
currently unable to determine when, whether, or the extent to
which NSTAR will be able to recognize this potential benefit.
b. Tax Gain on Generating Assets
The cost of transitioning to retail open access was mitigated, in
part, by the sale of Commonwealth Energy System's (COM/Energy)
(now a wholly owned subsidiary of NSTAR) non-nuclear generating
assets. COM/Energy completed the sale of substantially all of
its non-nuclear generating assets in 1998. Proceeds from the
sale of these assets amounted to approximately $453.9 million, or
6.1 times their book value of approximately $74.2 million. The
proceeds from the sale, net of book value, transaction costs and
certain other adjustments amounted to $358.6 million and are
required to be used for the benefit of COM/Energy customers under
MDTE rate setting policies. In this instance, the amount was
used to reduce transition costs of Cambridge Electric and
ComElectric related to electric industry restructuring.
COM/Energy determined that this transaction was not a taxable
event because it did not provide an economic benefit to its
shareholders. The amount, if not for this treatment, that would
otherwise have been paid in taxes is approximately $136 million.
Should COM/Energy ultimately lose this issue, tax deductions
resulting in tax savings of approximately $136 million would be
realized by COM/Energy over a period of years. During the second
quarter of 2002, NSTAR was notified that the IRS intended to file
a Request for Technical Advice with the IRS National Office with
regard to COM/Energy's tax treatment of this item. As of
December 31, 2002, the Request for Technical Advice had not yet
been filed.
The IRS is in the process of completing its audit of COM/Energy's
tax returns for the years 1997, 1998 and 1999. The audit will
not be closed at the examination level until the issue described
above has been resolved either by the IRS closing the audit with
no adjustment for the item or by providing COM/Energy with a tax
deficiency notice. Should COM/Energy be issued a deficiency
notice it must then decide to either contest the notice (at IRS
Appellate or in a court of law) or concede the issue. It is
expected that once the Request for Technical Advice is filed, a
National Office decision would be made within two months. Should
NSTAR's position be challenged, it is probable that NSTAR will
make a tax payment of approximately $60 million in order to stop
the accrual of interest on the potential remaining tax deficiency
for all years involved through 2002. NSTAR intends to vigorously
defend its position, which is supported by an opinion from an
independent tax advisor, relative to this transaction and
anticipates pursuing a refund of any amounts paid plus interest.
In addition, NSTAR would pursue regulatory rate recovery for the
interest on tax deficiencies should any amounts ultimately be
incurred as a result of this transaction. The MDTE has provided
written acknowledgements to NSTAR indicating: (1) its
understanding of the issue; and (2) COM/Energy's ability to seek
recovery of costs relating to the tax deficiency that may be
incurred. NSTAR believes that recovery from customers is
probable in view of the MDTE's position and its understanding of
the monetary benefits to be realized by COM/Energy's customers
should it be successful in defending its position. However, if
NSTAR is unsuccessful with the IRS and unsuccessful in getting
favorable regulatory treatment, it is possible that it could have
an adverse impact on NSTAR's results of operations, cash flows
and financial position.
Results of Operations
The following section of MD&A compares the results of operations
for each of the three fiscal years ended December 31, 2002, 2001
and 2000 and should be read in conjunction with the accompanying
Consolidated Financial Statements and the accompanying Notes to
Consolidated Financial Statements included elsewhere in this
report.
2002 compared to 2001
NSTAR's energy delivery businesses continue to be subject to
traditional utility accounting and ratemaking principles since
NSTAR earns a regulated equity return on its investments in those
businesses.
Earnings (loss) per common share were as follows:
Years Ended December 31,
2002 2001 % Change
Basic -
After RCN charge $3.05 $(0.05) NM
Before RCN charge $3.38 $ 3.23 4.6
Diluted -
After RCN charge $3.03 $(0.05) NM
Before RCN charge $3.37 $ 3.22 4.7
NM-not meaningful
Management believes that earnings before the RCN charge is a
meaningful measure of earnings and is reflective of its internal
earnings assessment and controls. In addition, it is also more
representative of NSTAR's prior and future performance.
Earnings were $161.7 million, or $3.05 and $3.03 per basic and
diluted common share, respectively, for 2002. Earnings for 2002
were $179.4 million, or $3.38 and $3.37 per basic and diluted
common share, respectively, before total non-cash, after-tax
charges of $17.7 million, or $0.33 per basic share, related to
NSTAR's investment in RCN Corporation (RCN) that is further
discussed below. For 2001, NSTAR reported a loss of $2.4 million
or $0.05 per basic and diluted common share. Results for 2001
were $171.5 million, or $3.23 per basic and $3.22 per diluted
common share, before a non-cash, after-tax charge of $173.9
million, or $3.28 per basic share, related to NSTAR's investment
in RCN.
Absent the RCN charges in both years, 2002 earnings increased by
$7.9 million ($0.15 per share), or 4.6%, primarily due to
increased kWh and firm gas sales and transportation and favorable
adjustments related to regulatory orders, lower preferred
dividend requirements and interest savings offset by higher
operations and maintenance expenses. Operations and maintenance
reflects higher pension and other postretirement benefits
expenses and increased maintenance on the electric system in
connection with the System Improvement Program. Cash flows from
operations increased by over $261 million due to the higher level
of earnings, improved accounts receivable collections, lower
regulatory cost deferrals, and income tax payments. Other
positive factors during the current year included lower bad debt
expense of $4.5 million and a $3.9 million deferred tax benefit
resulting from an adjustment to NSTAR's tax valuation allowance.
NSTAR's return on equity was 12.6% despite the downturn in the
current economic environment. NSTAR and subsidiaries maintained
their credit ratings with all rating agencies. In addition,
NSTAR increased its common dividend rate by $0.04 or 1.9% per
share to $2.16 on an annual basis.
Capital spending in 2002 significantly exceeded the prior year's
level due to an increase in the allocation of critical capital
resources to improve electric system reliability and customer
service. As an indication of this progress, key electric and gas
operating performance results were greatly improved in 2002 over
those of 2001. Electric customer outage hours were reduced by
35% and the length of those outages was reduced by 27%. These
dramatic improvements were accomplished during record-breaking
summer heat and an unprecedented demand for electricity. Also
contributing to this increase was additional capital spending
related to NSTAR's non-regulated subsidiaries, primarily Advanced
Energy Systems' generation expansion project.
On June 19, 2002, NSTAR received an additional 7.5 million shares
from the third and final exchange of its investment in the RCN
joint venture pursuant to an amended Joint Venture Agreement.
The market value of RCN common shares continued to decline during
2002 and did not close above NSTAR's previously adjusted carrying
value of $3.75 per share since November 27, 2001. As a result,
NSTAR recognized impairment charges totaling $37.3 million,
reducing the carrying value of its 11.6 million RCN shares to
$0.53 per share as of December 31, 2002. These charges were
offset by the recognition of $19.6 million in tax benefits
relating to joint venture operating losses. Combined, the
impairment charges and tax benefits amounted to $17.7 million, or
$0.33 per share in 2002. Similarly, in 2001, due to a
significant decrease in the market value of RCN common shares,
NSTAR recorded a non-cash, after-tax charge of $173.9 million.
Management determined that these declines in market value were
"other-than-temporary" in accordance with SFAS 115, "Accounting
for Certain Investments in Debt and Equity Securities."
Operating revenues
Operating revenues for 2002 decreased 15% from 2001 as follows:
(in thousands)
Retail electric revenues $ (375,130)
Wholesale electric revenues (22,702)
Gas sales revenues (65,203)
Other revenues (9,734)
Decrease in operating revenues $ (472,769)
==========
The decrease in operating revenues was significantly impacted by
the decline in standard offer and default service rates charged
to customers beginning in January 2002 that reflected lower
purchased power and gas costs.
Retail electric revenues were $2,122.3 million in 2002 compared
to $2,497.5 million in 2001, a decrease of $375.2 million, or
15%. The change in retail revenues includes the significantly
lower cost of purchased energy supply (discussed below) that
contributed to the lower rates implemented in January, April and
July 2002 for standard offer and default services. Components of
the total decrease in retail revenues includes lower revenues
attributable to standard offer and default services of $263.8
million and $163.9 million, respectively, lower revenue related
to demand-side management and renewable energy programs of $8.4
million due to the reconciliation of program costs, an increase
in incentive adjustments and the timing of program expenditures.
Transition revenues increased by $36.1 million due to higher
rates for transition cost recovery offset by an $8 million
decline in mitigation incentive revenues that are allowed for
successfully lowering transition charges. Mitigation incentive
revenues will continue to decrease over the transition period
extending over time from 2009 through 2026. Transmission
revenues increased by $30.8 million primarily as a result of rate
increases and the absence in 2002 of a $6.7 million reduction in
2001 revenues that reflected an MDTE-approved transmission
reconciliation filing. The change in NSTAR's retail revenues
related to standard offer, default services and demand-side
management and renewable energy are reconciled to the costs
incurred.
The 1.2% increase in retail kWh sales in 2002 reflects, by
customer sectors, an improvement of 2% in residential and 1.8% in
commercial offset somewhat by the continued sales decline of 5.5%
in the industrial sector. The overall increase in sales is
attributable to the warmer summer period, as compared to the
prior year. 2002 was the tenth warmest year in 132 years.
However, the economic downturn continues to have an negative
impact on sales as indicated by the high Boston office vacancy
rate. Business spending continues to be depressed as firms
appear reluctant to commit to increased employment and expansion
of office space. The unemployment rate in Boston was
approximately 4.4% through December 2002 as compared to
approximately 3% in the same period last year. NSTAR Electric's
sales to residential and commercial customers were approximately
29% and 56%, respectively, of its total retail sales mix for 2002
and provided 37% and 52% of total revenues, respectively.
Industrial sales declined due primarily to a slowdown in economic
conditions that led to reduced production or facility closings.
The industrial and other retail sales sector comprises
approximately 10% of NSTAR's energy sales and 8% of distribution
revenue.
NSTAR forecasts its electric and gas sales based on normal
weather conditions. Actual results may differ from those
projected due to actual weather conditions above or below these
normal weather levels. Due to a challenging economic environment
ahead, unit sales of electricity in 2003 are expected to grow at
approximately 1%.
Weather conditions greatly impact the change in electric sales
and, to a greater extent, gas sales and revenues in NSTAR's
service area. The first quarter of 2002 was significantly warmer
than the same period in 2001, followed by slightly below normal
temperatures for the second quarter, above-normal temperatures in
the third quarter and colder than prior year and normal
conditions in the fourth quarter of 2002. Below is comparative
information on heating and cooling degree-days for 2002 and 2001
and the number of degree-days in a "normal" year as represented
by a 30-year average. A "degree-day" is a unit measuring how
much the outdoor mean temperature falls below (for heating) or
rises above (for cooling) a base of 65 degrees. Each degree
below or above the base, is measured in one degree day.
Normal
30-Year
2002 2001 Average
Heating degree-days 5,658 5,644 5,942
Percentage change from prior year -% (8.3)%
Percentage change from 30-year average (4.8)% (5.1)%
Cooling degree-days 972 822 777
Percentage change from prior year 18.2% 39.8%
Percentage change from 30-year average 25.1% 5.8%
The heating degree-days experienced during 2002 were virtually
the same level with heating degree-days in 2001. However, in the
first quarter of 2002, heating degree-days totaled 2,522, a
decline of 16% from the prior year of 3,007 and 15% below a
normal level of 2,975. Heating degree-days for the fourth
quarter were 2,172, an increase of 28% as compared to 2001 and 8%
greater than normal. The warmer than normal conditions in early
2002 significantly impacted earnings for gas operations due to
the relatively short winter period when there is potential
heating demand.
The higher cooling degree-days experienced during 2002 positively
impacted electric distribution revenues. The above normal
cooling degree-days impacted air conditioning usage of our
customers and resulted in higher electric distribution revenues
than would otherwise have been recorded during a more moderate
summer period.
Wholesale electric revenues were $64.2 million in 2002 compared
to $86.9 million in 2001, a decrease of $22.7 million, or 26%.
This decrease in wholesale revenues reflects the expiration of
two municipal power supply contracts on May 31, 2002, and another
municipal contract on October 31, 2002, and a decline in rates
due to the lower cost of purchased power. After October 31,
2005, NSTAR will no longer have contracts for the supply of
wholesale power. Amounts collected from wholesale customers are
credited to retail customers through the transition charge.
Therefore, the expiration of these contracts has no impact on
results of operations. In 2003, wholesale electric sales are
forecasted to decrease due to the expiration of contracts with
several municipalities.
Gas sales revenues were $323.2 million in 2002 compared to $388.4
million in 2001, a decrease of $65.2 million, or 17%. The
decrease in revenues is primarily attributable to a 26% decline
in the cost of gas from suppliers compared to the same period
last year, slightly offset by a 0.6% increase in firm unit sales.
Other revenues were $209.4 million in 2002 compared to $219.1
million in 2001, a decrease of $9.7 million, or 4%. This
decrease primarily reflects lower revenues from non-utility
operations due to lower steam sales that reflect warmer weather
during the early part of 2002, lower billing rates, and the loss
of a large customer, partially offset by higher chilled water
revenues due to the warmer summer period and higher demand rates.
Operating expenses
Purchased power costs were $1,260.7 million in 2002 compared to
$1,673.5 million in 2001, a decrease of $412.8 million, or 25%.
The decrease in expense reflects a decline in prices of natural
gas and oil and a 22% decrease in wholesale sales due to the
expiration of three municipal power supply contracts. Partially
offsetting the impact of these decreases was a 1.2% increase in
retail electric sales and an increase in transmission costs.
Included in 2002 and 2001 was $31.3 million and $215.9 million,
respectively, that related to the recognition of previously
deferred standard offer and default service supply costs
resulting from the current period collection of previously
deferred costs. NSTAR adjusts its electric rates to collect the
costs related to energy supply from customers on a reconciling
basis. Due to the rate adjustment mechanism, a change in the
amount of energy supply expense does not have an impact on
earnings. NSTAR Electric satisfied most of its standard offer
service through existing long-term power purchase agreements that
were assigned to an independent party, and entered into shorter-
term agreements for the remaining requirement.
The cost of gas sold, representing NSTAR Gas' supply expense, was
$176.5 million in 2002 compared to $239.5 million in 2001, a
decrease of $63 million, or 26%, reflecting the lower cost of gas
supply and the significant reduction in sales due to milder
weather conditions in the first quarter of 2002. These expenses
are also reconciled to the current level of revenues collected.
Operations and maintenance expense was $431.7 million in 2002
compared to $417.1 million in 2001, an increase of $14.6 million,
or 4%. This increase primarily reflects incremental expenditures
incurred relating to improvements to NSTAR's electric delivery
system that were substantially completed as of September 30,
2002, an increase of approximately $17.7 million and $5.6 million
in pension-related and postretirement benefits expense (net of
amounts capitalized), respectively, resulting primarily from a
downturn in the equity market rates and a $2.3 million loss
incurred that related to an insurance settlement adjustment. The
increase in pension costs and other postretirement benefit costs
are anticipated to continue through 2003, as a result of the
declines in the equity markets over the past three years. These
factors were somewhat offset by the absence of $3.7 million in
storm costs incurred in the first quarter of 2001 and a decline
in bad debt expense of $4.5 million. In 2003, despite a
projected $11 million increase in pension and PBOP expense, total
operations and maintenance expense is expected to remain flat.
Depreciation and amortization expense was $239.2 million in 2002
compared to $231 million in 2001, an increase of $8.2 million, or
4%. This increase was primarily due to increases in capital
spending during 2002 in connection with system reliability
improvements as well as the accelerated amortization of
regulatory assets associated with the Seabrook sale of
approximately $7.3 million. This increase was offset by the
absence of depreciation on NSTAR's district energy facility,
Northwind in 2002. In 2001 Northwind's assets were written down
by $5 million.
Demand side management (DSM) and renewable energy programs
expense was $69 million in 2002 compared to $70.1 million in
2001, a decrease of $1.1 million, or 2%, primarily due to a
reduction of DSM programs which is consistent with the collection
of conservation and renewable energy revenues. These costs are
in accordance with program guidelines established by the MDTE and
are collected from customers on a fully reconciling basis. In
addition, NSTAR earns revenue incentive amounts in return for
increased customer participation. In 2002 and 2001, these
incentives amounted to approximately $3 million.
Property and other taxes were $97.2 million in 2002 compared to
$96.5 million in 2001, an increase of $0.7 million, or 1%. This
increase was due to higher tax rates and assessments,
particularly for the City of Boston of $2.2 million offset by
lower payments in lieu of taxes to the Town of Plymouth under
NSTAR's agreement with the town.
Income taxes from operations were $107.1 million in 2002 compared
to $113.4 million in 2001, a decrease of $6.3 million, or 6%.
The decrease in income tax expense is primarily the result of tax
benefits relating to certain customer refunds, which reduced
income tax expense by approximately $4 million. In addition,
this decrease also reflects the tax benefit of deducting NSTAR's
common dividends paid to the NSTAR Savings Plan. These items
resulted in a decrease in the effective tax rate for 2002 to
37.3% from 40.2% for 2001.
Other income, net
Other income was $22.4 million in 2002 compared to $6.9 million
in 2001, an increase in income of $15.5 million. The increase
was due primarily to $7.3 million in accelerated amortization of
ITC resulting from the sale of Seabrook, deferred tax valuation
allowance adjustments of $3.9 million, a $3.2 million net
increase in interest income primarily related to a reversal of a
previously established interest reserve and the absence in 2002
of $1.1 million related to system development costs. Other
income in 2002 also reflects $1.2 million related to transaction
fees.
Other deductions, net
Other deductions were $2 million in both 2002 and in 2001.
Deductions in 2002 reflect the absence of a $5 million accrual
for shutdown costs recorded in 2001 for the Northwind district
energy facility as compared to $2 million in 2002 for an
additional charge for expected equipment removal costs and a $0.6
million decline in expense for the minority interest related to
this facility. Other deductions also include increased
charitable contributions of $0.9 million, offset by $1.5 million
in lower miscellaneous deductions, including applicable income
tax benefits for total other deductions.
Interest charges
Interest on long-term debt and transition property securitization
certificates was $152.6 million in 2002 compared to $158.4
million in 2001, a decrease of $5.8 million, or 4%. The decrease
in interest expense reflects the retirement of $24.3 million in
Boston Edison's 9.375% Debentures in August 2001, Boston Edison's
early redemption of 8.25% Debentures of $60 million in September
2002, NSTAR Gas' 8.99% Series I Bonds of $3.5 million in December
2001, Cambridge Electric's 7.75% Series D Notes of $2.1 million
in June 2002 and ComElectric's 9.3% $30 million Term Loan in
January 2002, additional sinking fund payments and the reduction
in transition property securitization certificates outstanding of
$68.4 million that resulted in reduced interest expense of $4.3
million. Securitization interest represents interest on debt
collateralized by the future income stream associated with the
stranded costs of the Pilgrim Unit divestiture. These
certificates are non-recourse to Boston Edison. Partially
offsetting these decreases in interest expense was the impact of
the October 15, 2002 Boston Edison issuance of $400 million of
4.875% 10-year debentures and $100 million of 3-year floating
rate debentures (2.275% in 2002) priced at three month LIBOR plus
50 basis points. The net proceeds were used to repay
consolidated outstanding short-term debt. These new debentures
increased interest expense by $5 million in 2002.
Short-term and other interest expense was $26.9 million in 2002
compared to $25.3 million in 2001, an increase of $1.6 million,
or 6%. This increase was due to a $14.4 million increase in the
carrying charges associated with reductions in the level of under-
collection of regulatory deferrals, particularly carrying charges
related to deferred transition costs. Short-term and other
interest costs reflected a significant reduction in borrowing
rates and a $62.2 million lower average level of debt outstanding
in 2002, that resulted in an interest savings of approximately
$19 million. Short-term borrowing rates averaged approximately
1.9% in 2002 as compared to approximately 4.1% in 2001.
Partially offsetting this decrease in short-term expense was a
$5.9 million increase in interest costs associated for the most
part with now resolved tax matters.
The decrease in AFUDC is primarily due to a reduction in the
AFUDC rate reflecting the overall decline in short-term debt
rates. The 2002 rate was 2.26% compared to 4.31% in 2001. Also
contributing to this decrease was the absence in the current
period of capitalized interest on the construction of the Summit
facility of approximately $3.3 million. These reductions were
partially offset by higher capital project balances during 2002
primarily as a result of electric system infrastructure upgrades.
2001 compared to 2000
Earnings (loss) per common share were as follows:
Years Ended December 31,
2001 2000 % Change
Basic -
After RCN charge $(0.05) $3.19 (101.6)
Before RCN charge $ 3.23 $3.19 1.3
Diluted -
After RCN charge $(0.05) $3.18 (101.6)
Before RCN charge $ 3.22 $3.18 1.3
Management believes that earnings before the RCN charge is a
meaningful measure of earnings and is reflective of its internal
earnings assessment and controls. In addition, it is also more
representative of NSTAR's prior and future performance.
For 2001 NSTAR reported a loss of $2.4 million or $0.05 per basic
and diluted common share, compared to earnings for 2000 of $175
million, or $3.19 and $3.18 per basic and diluted common share,
respectively. Earnings for 2001 were $171.5 million, or $3.23
and $3.22 per basic and diluted common share, respectively,
before a non-cash, after-tax charge of $173.9 million, or $3.28
per basic share, recorded in the first quarter related to NSTAR's
investment in RCN. Factors that contributed to the $3.5 million,
or 2%, decline in earnings before the non-cash, after-tax charge
included a decline in firm gas sales (in BBTU) of 11%, a refund
of $3.9 million to electric customers in conjunction with NSTAR's
service quality plan, the accrual of costs associated with the
shutdown of Northwind's district energy facility of $7.5 million
and a decline in the return on equity on the plant investment
base of the Seabrook facility. Positive factors included a
slight increase in retail kWh sales of 0.6%, a lower regulatory
interest expense adjustment due to a reconciliation filing of
deferred standard offer and default service costs that resulted
in additional interest expense recorded in 2000, a settlement of
revenues due NSTAR from a former Pilgrim Unit customer and a one-
time gain associated with the receipt of equity securities issued
in conjunction with the demutualization of two mutual insurance
companies that provide coverage to NSTAR subsidiaries. For 2001,
a decrease of approximately 1.9 million average common shares
outstanding that resulted from the repurchase of shares during
2000 had a positive impact on earnings per share of approximately
$0.11.
As of December 31, 2001, NSTAR finalized the process of
converting its joint venture investment in RCN into shares of RCN
common stock. NSTAR's investment in RCN included 4.1 million
common shares that it held at that time and 7.5 million common
shares that were ultimately received in June 2002 for its
remaining interest in the joint venture. Consistent with the
performance of the telecommunications sector as a whole, the
market value of RCN's common shares decreased significantly
during the latter part of 2000 and continued in 2001. As a
result, NSTAR recognized an impairment of its investment in RCN
in the first quarter of 2001 per SFAS 115.
Operating Revenues
Operating revenues for 2001 increased 19% from 2000 as follows:
(in thousands)
Retail electric revenues $ 432,058
Wholesale electric revenues 8,969
Gas sales revenues 19,725
Other revenues 38,322
Increase in operating revenues $ 499,074
=========
Retail electric revenues were $2,497.5 million in 2001 compared
to $2,065.4 million in 2000, an increase of $432.1 million, or
21%. The change in retail revenues included a 0.6% increase in
retail kWh sales, higher rates implemented in January and July
2001 for standard offer and default services, which increased
retail revenues by $250.2 million and $257.5 million,
respectively and the absence in 2001 of a $30.8 million fuel
charge refund to customers in 2000. These revenue increases were
partially offset by lower transition revenues of $88.1 million
due to a decline in rates, a decline in transmission revenues of
$6.5 million and a decline of $1.9 million for demand-side
management and other revenues. The increase in NSTAR's retail
revenues related to standard offer and default services are fully
reconciled to the costs incurred and have no impact on net
income.
The 0.6% increase in 2001 retail kWh sales primarily reflected
growth in the residential and commercial sectors of 1.1% and
1.7%, respectively. NSTAR Electric's sales to residential and
commercial customers were approximately 30% and 59%,
respectively, of its total retail sales mix for 2001 and provided
41% and 51% of distribution revenue, respectively. Industrial
sector sales declined 7.8% due primarily to a slowdown in
economic conditions that resulted from reduced production or
facility closings. The industrial sector comprises approximately
10% of NSTAR's energy sales and 6% of distribution revenue.
The summer period of 2001 was significantly warmer than the same
period in 2000, and this abnormal pattern continued into the
fourth quarter heating season of 2001 with above normal
temperatures. Below is comparative information on cooling and
heating degree-days in 2001 and 2000 and the number of degree-
days in a "normal" year as represented by a 30-year average.
30-Year
2001 2000 Average
Heating degree days 5,644 6,147 5,942
Percentage change from prior year (8.2)% 11.7%
Percentage change from 30-year average (5.0)% 3.5%
Cooling degree days 822 588 777
Percentage change from prior year 39.8% (34.0)%
Percentage change from 30-year average 5.8% (24.3)%
Wholesale electric revenues were $86.9 million in 2001 compared
to $77.9 million in 2000, an increase of $9 million, or 12%.
This increase in wholesale revenues primarily reflected increased
demand from a public transit authority and municipal contracts.
Gas sales revenues were $388.4 million in 2001 compared to $368.7
million in 2000, an increase of $19.7 million, or 5%. The
increase in revenues was primarily attributable to the recovery
of increased gas costs, partially offset by an 11% decline in
firm sales and transportation due to the impact of the economic
slowdown on the commercial and industrial sectors. This was the
case during the fourth quarter of 2001 when firm gas sales
declined 31.2% from the prior year and were significantly
impacted by the 24.6% decline in heating-degree days.
As indicated above, heating degree-days in 2001 were 8.2% below
2000 and 5% below normal and contributed to the decrease in firm
sales and transportation. NSTAR Gas' firm BBTU sales to
residential and commercial customers were approximately 65% and
27%, respectively, of total 2001 firm sales.
Other revenues were $219.1 million in 2001 compared to $180.8
million in 2000, an increase of $38.3 million, or 21%. This
change reflected higher ISO-New England related transmission
revenues and higher revenues realized from district energy
operations.
Operating Expenses
Purchased power and cost of gas sold expense was $1,913 million
in 2001, compared to $1,385.7 million in 2000, an increase of
$527.3 million, or 38%. The purchased power component of these
costs was $1,673.5 million in 2001 compared to $1,172.9 million
in 2000, an increase of $500.6 million, or 43%. The increase in
purchased power expense reflected the impact of the recognition
of previously deferred standard offer and default service supply
costs resulting from collection of these costs in 2001. Also
impacting this increase were increases in purchased power
requirements due to a 0.6% increase in retail sales and a 2.2%
increase in wholesale sales, partially offset by lower costs that
reflect the prices of natural gas and oil. Further contributing
to the increase in total expense was the cost of gas sold,
representing NSTAR Gas' supply expense, which was $239.5 million
for 2001 compared to $212.8 million in 2000, an increase of $26.7
million, or 13%, due primarily to the higher gas supply costs in
2001. These expenses are also fully reconciled to the current
level of revenues collected.
Operations and maintenance expense was $417.1 million in 2001
compared to $415.8 million in 2000, an increase of $1.3 million,
or 0.3%. This slight increase reflected higher electric
distribution weather-related maintenance costs related to a major
late-winter storm in March and severe summer weather during 2001
and higher maintenance costs incurred in connection with NSTAR's
unregulated subsidiary activities. Other factors that increased
expenses were higher bad debt expense primarily due to the
increased sales and higher costs related to postretirement and
other benefits. Offsetting this increase was the absence of non-
recurring computer system implementations costs incurred during
2000.
Depreciation and amortization expense was $231 million in 2001
compared to $238.6 million in 2000, a decrease of $7.6 million,
or 3%. The decrease primarily reflected the buy-down of the
Seabrook investment in November 2000 utilizing the majority of
the proceeds from the sale of Canal's generating units. Further
contributing to this decrease was the write-down of the remaining
assets of the Northwind district energy facility in 2000 and
decreased amortization of software-related costs, partially
offset by a slightly higher level of system-wide depreciable
plant-in-service.
DSM and renewable energy programs expense was $70.1 million in
2001 compared to $78.8 million in 2000, a decrease of $8.7
million, or 11%, primarily due to timing of DSM expense. These
costs are in accordance with program guidelines established by
regulators and are collected from customers on a fully
reconciling basis. In addition, NSTAR earns incentive amounts in
return for increased customer participation.
Property and other taxes were $96.5 million in 2001 compared to
$82.1 million in 2000, an increase of $14.4 million, or 18%. The
increase was due to the fact that during 2000, Boston Edison was
reimbursed for the majority of its payments in lieu of property
taxes to the Town of Plymouth by Entergy. Entergy purchased the
Pilgrim Unit from Boston Edison in 1999.
Income taxes from operations were $113.4 million in 2001 compared
to $117.4 million in 2000, a decrease of $4 million, or 3%,
reflecting the impact of lower pre-tax operating income.
Other Income, net
Other income was $6.9 million in 2001 compared to $8.9 million in
2000, a decrease of $2 million. The decrease was due to a $4.6
million reduction in the settlement of claims primarily related
to the Pilgrim wholesale contract buyout and a $2 million net
reduction in other miscellaneous income items and taxes related
to other income, recognized in 2000. Offsetting these declines
in other income was the impact of $4.5 million of income
associated with the receipt of common stock in connection with
the demutualization of two insurance companies, recognized in
2001.
Other Deductions, net
Other deduction items were $2 million in 2001 compared to income
of $3.1 million in 2000, an increase in deductions of $5.1
million due primarily to the $3.8 million recognition in 2001,
for the accrual of costs associated with the shutdown of the
Northwind unregulated district energy facility, offset by a $1.4
million net increase in other miscellaneous income items,
primarily minority interest adjustment, and income tax related to
other deductions.
Interest Charges
Interest on long-term debt and transition property securitization
certificates was $158.4 million in 2001 compared to $154.8
million in 2000, an increase of $3.6 million, or 2%. This change
in long-term interest costs included $15.3 million that reflected
a full-year of debt outstanding from the issuance of $300 million
and $200 million of NSTAR 8% Notes in February and October of
2000, respectively, offset somewhat by a decrease of $7.6 million
that reflected the retirement of $199 million in Boston Edison
debt and the pay down of other subsidiary company debt of $7.4
million throughout 2000 as compared to retirements and pay downs
in 2001 of $24.3 million and $10.1 million, respectively. Long-
term debt interest in 2001 also reflected a reduction of
securitization certificates interest of $4 million due to the
partial retirement of this debt.
Interest on short-term and other obligations was $25.3 million in
2001 compared to $55.2 million in 2000, a decrease of $29.9
million, or 54%. This decrease was primarily due to a
reconciliation adjustment of regulatory deferrals in conjunction
with an MDTE reconciliation that resulted in the recognition of
interest expense in 2000, and the positive impact of
approximately $4 million resulting from lower interest rates that
included the impact of higher average short-term borrowing levels
from banks. The increase in borrowing was primarily the result
of financing long-term debt and preferred stock retirements with
short-term borrowing and other working capital requirements.
Further contributing to the lower interest expense in 2001 was an
offset to previously accrued interest expense on Internal Revenue
Service tax matters that were settled in 2001.
Liquidity and Capital Resources
During 2002, 2001 and 2000, internal generation of cash provided
81%, 103% and 188%, 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 2003 is $286 million,
consisting of approximately $267 million for electric and gas
operations and $19 million for capital requirements of non-
utility ventures. The capital spending level over the following
four years is forecasted to aggregate approximately $810 million.
Management continuously reviews its capital expenditure and
financing programs. These programs and, therefore, the estimates
included in this Form 10-K are subject to revision due to changes
in regulatory requirements, operating requirements, environmental
standards, availability and cost of capital, interest rates and
other assumptions.
NSTAR has long-term debt principal payments, minimum lease
commitments, electric capacity charge obligations under contracts
and natural gas contractual agreements at December 31, 2002, for
each of the years presented below:
Years
(in millions) 2003 2004 2005 2006 2007 Thereafter
Long-term debt $ 172 $ 10 $ 110 $ 29 $ 15 $1,482
Transition property
securitization 41 69 68 69 69 172
Leases 22 20 17 14 11 46
Electric capacity
obligations 149 156 159 160 162 911
Gas contractual
obligations 50 50 49 46 35 154
$ 434 $ 305 $ 403 $ 318 $ 292 $2,765
====== ====== ====== ====== ====== ======
NSTAR's short-term debt decreased by $426.2 million to $198.6
million at December 31, 2002 as compared to $624.8 million at
December 31, 2001. The decrease resulted primarily from the use
of proceeds from Boston Edison's $500 million financing
(described below) that was completed on October 15, 2002. In
addition, sources of cash from operating activities provided
$586.3 million. of cash This source of cash was used to fund
NSTAR's investing activities of $331.8 million.
The net cash provided by 2002 operating activities of $586.3
million was partially attributable to net earnings of $163.7
million, which, when adjusted for depreciation and amortization,
deferred income taxes and investment tax credits, provided $390.2
million of operating cash as compared to $204.9 million in 2001.
The $15.9 million change in deferred income taxes and investment
tax credits primarily reflects the deferred tax impact of changes
in regulatory deferrals year to year and the impact of
adjustments to the tax valuation account. In addition, a 2002
change in the tax laws that allows for an additional 30%
acceleration of tax depreciation on current year additions, as
well as the impact of accelerated depreciation on normal capital
additions resulted in approximately $21 million in deferred
income tax expense. Correspondingly, these items significantly
impact the level of required estimated federal and state income
tax payments. For the year 2001, approximately $198 million was
paid for income taxes as compared to $96 million in 2002. Also
contributing to operating cash was a decrease in receivables of
$162.8 million, and an increase in payables of $21.1 million.
Included in the decrease in receivables was the receipt of $65
million associated with the non-recurring construction financing
of NSTAR's new corporate office building. In 2001, NSTAR funded
the construction of this facility.
Net working capital, excluding short-term borrowings and the
current portion of long-term debt, increased by $283.1 million to
$121.7 million for 2002 as compared to a shortfall of $161.4
million for 2001. This increase is primarily due to the improved
accounts receivable collection activity, lower power supply
payments to vendors and a reduction in estimated income tax
payments in 2002 of approximately $102 million that represent the
impact of timing differences on current income tax expense
described under the caption of deferred income taxes. Refer to
the recent change in tax laws noted above.
The net cash used in investing activities of $331.8 million was
utilized primarily for capital expenditures related to
transmission and distribution systems and included $36 million
expended on NSTAR's corporate office facility. The net cash used
in financing activities of $212.8 million was primarily the
result of repayments of short-term borrowings of $426.2 million,
long-term debt redemptions and sinking fund payments of $166.9
million and dividends paid of $114.4 million.
NSTAR's primary estimated future uses of cash for 2003 include
capital expenditures, dividend payments and debt reductions.
The IRS is in the process of completing its audit of COM/Energy's
tax returns for the years 1997, 1998 and 1999. Before completion
of these audits, and before the end of the second quarter of
2003, it is expected that the IRS National Office will provide a
response to a Request for Technical Advice to be filed by the IRS
examining agents. Should NSTAR's position be challenged as a
result of the IRS Request for Technical Advice, it is probable
that NSTAR will make a payment to the IRS of approximately $60
million in order to stop the accrual of interest on the potential
tax deficiency. NSTAR intends to vigorously defend its position,
which is supported by an opinion from an independent tax advisor,
relative to this transaction and anticipates pursuing a refund of
the amount paid plus interest. Refer to "Income Tax Issues" in
this MD&A for additional information.
For 2002, actual capital spending was approximately $368 million
including the System Improvement Program that was essentially
complete as of September 30, 2002, $36 million in connection with
a new corporate office building, customer growth projects
incurred by NSTAR Gas and expenditures in connection with
Advanced Energy Systems' generation expansion project. In order
to continue to deliver the highest possible service levels to
customers, capital investments in 2003 are expected to be
approximately $286 million.
Future capital spending programs and the related estimates
included in this report are subject to revision due to changes in
regulatory requirements, changes in transmission and distribution
system requirements, environmental standards, availability and
cost of capital, interest rates and other assumptions.
Management continuously reviews its capital expenditure and
financing programs.
On October 15, 2002, Boston Edison sold $400 million of 4.875%
ten-year debentures and $100 million of three-year floating note
debentures priced at three month LIBOR plus 50 basis points. The
net proceeds were used to repay outstanding short-term debt
balances.
Additionally, in 2002, debt financing activities included the
retirement of: $68.4 million in securitization certificates,
ComElectric's 9.3% $30 million Term Loan in January, Cambridge
Electric's 7.75% $2.1 million Series D Notes in June and $60
million for the early redemption of Boston Edison's 8.25%
Debentures in September. In the fiscal year 2001, financing
activities included redemptions of securitization certificates of
$62 million, redemption of all 500,000 shares outstanding of
Boston Edison's Cumulative Preferred Stock - 8% Series, at the
mandatory redemption price of $100 per share, Boston Edison's
early redemption of $24.3 million 9.375% debentures, and other
scheduled sinking fund payments.
Sources of Additional Capital and Financial Covenant
Requirements
NSTAR and Boston Edison have no financial covenant requirements
under their respective long-term debt arrangements. ComElectric,
Cambridge Electric and NSTAR Gas have financial covenant
requirements under their long-term debt arrangements and were in
compliance at December 31, 2002 and 2001. NSTAR's long-term debt
other than the Mortgage Bonds of NSTAR Gas is unsecured.
The Transition Property Securitization Certificates held by
Boston Edison's subsidiary, BEC Funding, LLC, is collaterized
with a securitized regulatory asset with a balance of $493.6
million as of December 31, 2002. Boston Edison, as servicing
agent for BEC Funding, collected $105.7 million in 2002. These
collected funds are remitted daily to the trustee of BEC Funding.
These Certificates are non-recourse to Boston Edison.
NSTAR had a $450 million revolving credit agreement with a group
of banks effective through November 2002. NSTAR lowered this
credit facility to $350 million that consists of a three year,
$175 million revolving credit agreement that expires on November
14, 2005 and a 364-day, $175 million agreement that expires on
November 14, 2003. At December 31, 2002 and 2001, there were no
amounts outstanding under these revolving credit agreements.
These arrangements serve as backup to NSTAR's $350 million
commercial paper program that, at December 31, 2002 and 2001, had
$63.5 million and $315.5 million outstanding, respectively. In
October 2002, following receipt of the proceeds of Boston
Edison's $500 million debt issue, previously referenced, the
proceeds were used to pay down short-term debt balances. Under
the terms of this credit agreement, NSTAR is required to maintain
a maximum total consolidated debt to total capitalization ratio
of not greater than 65% at all times, excluding Transition
Property Securitization Certificates, and excluding Accumulated
other comprehensive income(loss) from Common equity, and to
maintain a ratio of consolidated earnings before interest and
taxes to consolidated total interest expense of not less than 2
to 1 for each period of four consecutive fiscal quarters.
Commitment fees must be paid on the total agreement amount. At
December 31, 2002 and 2001, NSTAR was in full compliance with all
of the aforementioned covenants.
Boston Edison had approval from the FERC to issue up to $350
million of short-term debt until December 31, 2002. On May 31,
2002, Boston Edison received FERC authorization to issue short-
term debt securities from time to time on or before December 31,
2004, with maturity dates no later than December 31, 2005, in
amounts such that the aggregate principal does not exceed $350
million at any one time. Boston Edison had a $300 million
revolving credit agreement with a group of banks effective
through December 2002. Boston Edison replaced this credit
facility with a 364-day, $350 million revolving credit agreement
that expires on November 14, 2003. At December 31, 2002 and
2001, there were no amounts outstanding under these revolving
credit agreements. These arrangements serve as backup to Boston
Edison's $350 million commercial paper program that had no
outstanding balance at December 31, 2002 and had an outstanding
balance of $191.5 million at December 31, 2001. In October 2002,
following receipt of the proceeds of its $500 million debt issue
previously referenced, its short-term debt balance was reduced to
zero. Under the terms of this agreement, Boston Edison is
required to maintain a maximum total consolidated debt to total
capitalization of not greater than 60% at all times, excluding
Transition Property Securitization Certificates and excluding
Accumulated other comprehensive income(loss) from Common equity.
Commitment fees must be paid on the total agreement amount. At
December 31, 2002 and 2001, Boston Edison was in full compliance
with all of the aforementioned covenants.
On September 16, 2002, Boston Edison retired the $60 million
8.25% Series Debentures, due 2022. A $2.3 million redemption
premium was paid; this transaction had minimal impact on
earnings.
In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $170 million available under several lines of
credit and had $135.1 million and $117.8 million outstanding
under these lines of credit at December 31, 2002 and 2001,
respectively. ComElectric had approval from FERC to issue short-
term debt in an amount not exceeding $100 million until November
29, 2002. On May 31, 2002, ComElectric and Cambridge Electric
received FERC authorization to issue short-term debt securities
from time to time on or before November 30, 2004 and June 27,
2004, with maturity dates no later than November 29, 2005 and
June 26, 2005, respectively, in amounts such that the aggregate
principal does not exceed $125 million and $60 million,
respectively, at any one time. NSTAR Gas is not required to seek
approval from FERC to issue short-term debt.
On November 24, 2002, the MDTE issued an order approving
ComElectric's request for long-term debt financing up to a
maximum level of $150 million to be issued from time-to-time on
or before December 31, 2004. However, the order established the
maximum financing level at $141.9 million until March 2003 when
ComElectric's $15 million, 7.43% Term Loan is retired. At that
time, the maximum financing level will increase to $150 million.
NSTAR and its subsidiary companies' debt credit ratings services
are provided by Moody's Investors Service, Standard & Poor's
Rating Services and Fitch Ratings. All ratings carry a stable
outlook and are as follows:
Moody's S&P Fitch
NSTAR A2 A A
Boston Edison Company A1 A AA-
Commonwealth Electric Company Not rated A A
Cambridge Electric Light Company Not rated A A
NSTAR Gas Company Not rated A A
Historically, NSTAR and its subsidiaries have had a variety of
external sources of financing available , as indicated above, at
favorable rates and terms to finance its external cash
requirements. However, the availability of such financing at
favorable rates and terms depends heavily upon prevailing market
conditions and NSTAR's or its subsidiaries' financial condition
and credit ratings. During 2002, all of NSTAR's debt credit
rating agencies listed above reaffirmed their ratings of NSTAR
and its subsidiaries.
An adverse change in NSTAR's or its subsidiaries' credit ratings
or market conditions could have an adverse impact on the terms
and conditions upon which NSTAR or its subsidiaries have access
to capital markets. NSTAR has no provisions in financial
guarantees, commitments, debt or lease agreements that affirm
that a change in its credit rating would trigger a change in
terms and conditions, such as acceleration of payment
obligations. However, NSTAR's subsidiaries could be required to
provide additional security for power supply contract
performance, such as a letter of credit for their pro-rata share
of the remaining value of such contracts. Refer to "Performance
Assurances from Electricity and Gas Supply Agreements" and
"Financial and Performance Guarantees" further discussed below.
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.
Performance Assurances from Electricity and Gas Supply Agreements
NSTAR Electric has entered into a series of purchased power
agreements to meet its default and standard offer service supply
obligations through December 31, 2003. These agreements are
generally for a term of six to twelve months. NSTAR Electric
currently is recovering payments it is making to suppliers from
its customers. Most of NSTAR Electric's power suppliers are
subsidiaries of larger companies with investment grade or better
credit ratings. NSTAR has financial assurances and guarantees
that include letters of credit in place with the parent company
of the supplier, to minimize NSTAR Electric risk in the event the
supplier encounters financial difficulties or otherwise fails to
perform. In addition, under these agreements, in the event that
the supplier (or its parent guarantor) fails to maintain an
investment grade credit rating, it is required to provide
additional security for performance of its obligations. NSTAR
Electric's policy is to enter into power supply arrangements only
if the supplier (or its parent guarantor) has an investment grade
or better credit rating. In view of current volatility in the
energy supply industry, NSTAR Electric is unable to determine
whether its suppliers (or their parent guarantors) will become
subject to financial difficulties, or whether these financial
assurances and guarantees are sufficient. In the event, the
supplier (or its guarantor) may not be in a position to provide
the required additional security, NSTAR Electric may then
terminate the agreement. Some of these agreements include a
reciprocal provision, where in the event that an NSTAR Electric
distribution company receives a credit rating below investment
grade, that company could be required to provide additional
security for performance, such as a letter of credit.
Virtually all of NSTAR Gas' firm gas supply agreements are short-
term (less than one year) and utilize market-based, monthly
indexed pricing mechanisms so the financial risk to the Company
would be minimal if a supplier were to fail to perform. However,
in the event that a firm supplier does fail to perform under its
firm gas supply agreement pricing provisions, the Company would
be entitled to any positive difference between the monthly supply
price and the cost of replacement supplies.
The cost of gas procured for firm gas sales customers is
recovered through a regulatory semi-annual cost of gas adjustment
mechanism. Under MDTE regulations, interim adjustments to the
cost of gas may also be requested if market volatility causes
swings in the price of gas.
NSTAR Gas continually evaluates the financial stability of
current and prospective gas suppliers. Firm suppliers are
required to have and maintain investment grade credit ratings and
the firm gas supply agreements allow either party to require
financial assurances, or, if necessary, contract termination in
the event that either party is downgraded below investment level.
Financial and Performance Guarantees
On a limited basis, NSTAR and certain of its subsidiaries may
enter into agreements providing financial assurance to third
parties. Such agreements include letters of credit, surety
bonds, and other guarantees.
At December 31, 2002, outstanding guarantees totaled $34.2
million as follows:
(in thousands)
Letters of Credit $ 5,527
Surety Bonds 15,709
Other Guarantees 13,000
Total Guarantees $ 34,236
========
The $5.5 million letter of credit is for the benefit of a third
party, as trustee in connection with the 6.924% Notes of one of
its subsidiaries. The letter of credit is available if its
subsidiary has insufficient funds to pay the debt service
requirements. As of December 31, 2002, there have been no
amounts drawn under this letter of credit.
At December 31, 2002, certain of NSTAR's subsidiaries have
purchased a total of $1 million of performance surety bonds for
the purpose of obtaining licenses, permits and rights-of-way in
various municipalities. In addition, NSTAR has purchased
approximately $14.7 million in worker's compensation self-insurer
bonds. These bonds support the guarantee by NSTAR to the
Commonwealth of Massachusetts required as part of NSTAR's
worker's compensation self-insurance program.
NSTAR and its subsidiaries have also issued $13 million of
residual value guarantees related to its equity interest in the
Hydro-Quebec transmission companies.
Management believes the likelihood NSTAR would be required to
perform or otherwise incur any significant losses associated with
any of these guarantees is remote.
Preferred Stock Dividends and Redemptions
Preferred dividends of Boston Edison were approximately $2
million, $5.6 million and $6 million in 2002, 2001 and 2000,
respectively. On December 3, 2001, Boston Edison redeemed all
500,000 shares outstanding of its Cumulative Preferred Stock, 8%
Series, at the mandatory redemption price of $100 per share, plus
accrued dividends from November 1, 2001 to December 1, 2001.
Contingencies
Environmental Matters
As of December 31, 2002, NSTAR's subsidiaries were involved in 21
state-regulated properties ("Massachusetts Contingency Plan, or
"MCP" sites") where oil or other hazardous materials were
previously spilled or released. On February 4, 2003, NSTAR
closed-out one of these sites and filed the required information
with the Massachusetts Department of Environmental Protection.
The NSTAR subsidiaries are required to clean up or otherwise
remediate these properties in accordance with specific state
regulations. There are uncertainties associated with the
remediation costs due to the final selection of the specific
cleanup technology and the particular characteristics of the
different sites. In addition to the MCP sites, NSTAR
subsidiaries also face possible liability as a result of
involvement in multi-party disposal sites or third party claims
associated with contamination remediation. NSTAR generally
expects to have only a small percentage of the total potential
liability for these sites. Estimates of approximately $4.2
million and $5.8 million are included as liabilities in the
accompanying Consolidated Balance Sheets at December 31, 2002 and
2001, respectively, and are the total amount of NSTAR's estimated
environmental clean-up obligations. Accordingly, this amount has
not been reduced by any potential rate recovery treatment of
these costs or any potential recovery from NSTAR's insurance
carriers. Prospectively, should NSTAR be allowed regulatory rate
recovery of these specific costs, it would record an offsetting
regulatory asset and record a credit to operating expenses equal
to previously expensed costs. Based on its assessments of the
specific site circumstances, management does not believe that it
is probable that any such additional costs will have a material
impact on NSTAR's consolidated financial position.
NSTAR Gas is participating in the assessment of six 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 NSTAR Gas may be responsible for
remedial action. The MDTE has approved recovery of costs
associated with MGP sites over a 7-year period, without carrying
costs. As of December 31, 2002 and 2001, NSTAR Gas has recorded
a liability of $4.8 million and $6.7 million, respectively, as an
estimate for site cleanup costs for several MGP sites for which
NSTAR Gas was previously cited as a potentially responsible
party. A corresponding regulatory asset has been recorded that
reflects the future rate recovery for these costs.
Estimates related to environmental remediation costs are reviewed
and adjusted periodically as further investigation and assignment
of responsibility occurs and as either additional sites are
identified or NSTAR's responsibilities for such sites evolve or
are resolved. NSTAR's ultimate liability for future
environmental remediation costs may vary from these estimates.
Although, 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
consolidated financial position or results of operations for a
reporting period.
Employees and Employee Relations
As of December 31, 2002, NSTAR had approximately 3,300 employees,
including approximately 2,400, or 73% of whom are represented by
three collective bargaining units covered by separate contracts.
Local 369 of the Utility Workers Union of America, AFL-CIO,
represents approximately 2,075 employees with a five-year
contract that expires on May 15, 2005.
A collective bargaining unit contract representing approximately
260 employees expired on March 31, 2002. On March 24, 2002,
Local 12004, United Steelworkers of America, AFL-CIO-CLC,
ratified a new four-year contract that expires on March 31, 2006.
Approximately 70 employees of Advanced Energy Systems' MATEP
subsidiary are represented by the Local 877, International Union
of Operating Engineers, AFL-CIO, through a labor agreement that
expires on September 30, 2006.
Management believes it has satisfactory relations with its
employees.
Interest Rate Risk
NSTAR is exposed to changes in interest rates primarily based on
levels of short-term debt outstanding. The weighted average
interest rates for long-term indebtedness, including current
maturities were 6.81% and 7.50% in 2002 and 2001, respectively.
Carrying amounts and fair values of long-term indebtedness
(excluding notes payable, including current maturities) as of
December 31, 2002 and 2001, were as follows:
2002 2001
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Long-term indebtedness $2,304,101 $2,422,440 $1,970,451 $2,076,190
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk
Although NSTAR has material commodity purchase contracts, these
instruments are not subject to market risk. NSTAR's electric and
gas distribution subsidiaries have rate-making mechanisms that
allow for the recovery of fuel costs from customers. Customers
have the option of continuing to buy power from the retail
electric distribution businesses at standard offer prices through
February 2005. The cost of providing standard offer service
includes fuel and purchased power costs. Default service is the
electricity that is supplied by the local distribution company
when a customer is not receiving power from standard offer
service. The market prices for standard offer and default
service will fluctuate based on the average market price for
power. Amounts collected through standard offer and default
service are recovered on a fully reconciling basis.
On October 15, 2002, Boston Edison issued $100 million of 3-year
floating rate debentures priced at LIBOR plus 50 basis points.
An immediate change of one percent for these variable rate
debentures would cause a change in interest expense of
approximately $1 million per year.
Item 8. Financial Statements and Supplementary Financial
Information
NSTAR
Consolidated Statements of Income
Years ended December 31,
2002 2001 2000
(in thousands, except earnings per share)
Operating revenues $2,719,067 $3,191,836 $2,692,762
Operating expenses:
Purchased power and cost of gas sold 1,437,194 1,912,991 1,385,724
Operations and maintenance 431,740 417,141 415,806
Depreciation and amortization 239,233 230,949 238,608
Demand side management and renewable
energy programs 68,986 70,093 78,774
Property and other taxes 97,204 96,489 82,136
Income taxes 107,113 113,412 117,420
Total operating expenses 2,381,470 2,841,075 2,318,468
Operating income 337,597 350,761 374,294
Other income (deductions):
Write-down of RCN investment, net (17,677) (173,944) -
Other income, net 22,364 6,923 8,939
Other deductions, net (1,994) (1,951) 3,122
Total other income (deductions), net 2,693 (168,972) 12,061
Interest charges:
Long-term debt 115,473 116,939 109,299
Transition property securitization 37,135 41,475 45,505
Short-term and other 26,890 25,268 55,182
Allowance for borrowed funds used during
construction (AFUDC) (2,875) (5,094) (4,593)
Total interest charges 176,623 178,588 205,393
Net income 163,667 3,201 180,962
Preferred stock dividends of subsidiary 1,960 5,627 5,960
Earnings (loss) available for common
shareholders $ 161,707 $ (2,426) $ 175,002
========== ========== ==========
Weighted average common shares outstanding:
Basic 53,033 53,033 54,887
Diluted 53,297 53,216 55,045
Earnings (loss) per common share:
Basic $ 3.05 $ (0.05) $ 3.19
Diluted $ 3.03 $ (0.05) $ 3.19
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Statements of Comprehensive Income
Years ended December 31,
2002 2001 2000
(in thousands)
Net income $ 163,667 $ 3,201 $ 180,962
Other comprehensive income (loss), net:
Unrealized loss on investments (17,819) (7,789) (90,532)
Reclassification adjustment for
loss included in net income 15,110 66,836 -
Additional minimum pension liability (12,470) 1,004 (1,004)
Deferred income taxes 5,927 (24,146) 37,277
Comprehensive income $ 154,415 $ 39,106 $ 126,703
========= ========= ==========
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Statements of Retained Earnings
Years ended December 31,
2002 2001 2000
(in thousands)
Balance at the beginning of the year $ 334,138 $ 446,587 $ 389,989
Add:
Net income 163,667 3,201 180,962
Subtotal 497,805 449,788 570,951
Deduct:
Dividends declared:
Common shares 112,959 110,042 109,315
Preferred stock 1,960 5,627 5,960
Subtotal 114,919 115,669 115,275
Provision for preferred stock redemption - (19) 239
Common share repurchase programs - - 8,850
Balance at the end of the year $ 382,886 $ 334,138 $ 446,587
========= ========= =========
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Balance Sheets
December 31,
(in thousands)
2002 2001
Assets
Utility plant in service, at original cost $4,090,843 $3,853,295
Less: accumulated depreciation 1,309,270 $2,781,573 1,300,868 $2,552,427
Construction work in progress 66,047 72,957
Net utility plant 2,847,620 2,625,384
Non-utility property, net 129,918 106,007
Goodwill 451,374 463,626
Equity investments 19,845 22,560
Other investments 32,391 73,104
Current assets:
Cash and cash equivalents 53,438 11,655
Restricted cash 33,899 47,441
Accounts receivable, net of allowance of
$24,379 and $29,763, respectively 298,428 461,212
Accrued unbilled revenues 47,420 51,061
Inventory, at average cost 58,555 69,396
Other 14,886 506,626 17,479 658,244
Deferred debits:
Regulatory assets - other 875,038 1,026,241
Regulatory assets - power contract 701,084 -
Regulatory assets - pension costs 425,755 -
Prepaid pension costs - 218,713
Other 133,624 134,312
Total assets $6,123,275 $5,328,191
========== ==========
Capitalization and Liabilities
Common equity:
Common shares, par value $1 per share,
100,000,000 shares authorized;
53,032,546 shares issued
and outstanding $ 53,033 $ 53,003
Premium on common shares 870,877 873,664
Retained earnings 382,886 334,138
Accumulated other comprehensive
(loss) income (7,491) $1,299,305 1,761 $1,262,596
Cumulative non-mandatory redeemable
preferred stock of subsidiary 43,000 43,000
Long-term debt 1,645,465 1,377,899
Transition property securitization 445,890 513,904
Current liabilities:
Long-term debt 172,191 37,676
Transition property securitization 40,555 40,972
Notes payable 198,600 624,847
Property taxes and other 9,826 14,703
Deferred income taxes 4,692 41,985
Accounts payable 230,939 209,821
Accrued interest 38,811 49,874
Dividends payable 28,964 28,434
Accrued expenses 94,418 109,655
Other 67,141 886,137 105,532 1,263,499
Deferred credits:
Accumulated deferred income taxes and
unamortized investment tax credits 675,881 654,620
Power contracts 773,922 53,041
Pension liability 177,675 -
Other 176,000 159,632
Commitments and contingencies
Total capitalization and liabilities $6,123,275 $5,328,191
========== ==========
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Statements of Cash Flows
Years ended December 31,
(in thousands)
2002 2001 2000
Operating activities:
Net income $ 163,667 $ 3,201 $ 180,962
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 239,800 230,949 240,576
Deferred income taxes and investment tax credits (13,311) (29,250) 54,835
Loss on RCN investment 37,343 168,376 -
Demutualization income - (4,537) -
Allowance for borrowed funds used during
construction (2,875) (5,094) (4,593)
Power contract buyout (12,741) (12,741) (11,679)
Net changes in:
Accounts receivable and accrued unbilled revenues 166,425 19,483 (124,417)
Fuel, materials and supplies, at average cost 9,554 ( 8,617) 4,097
Other current assets 17,422 1,367 115,437
Accounts payable 33,859 (53,216) 93,250
Other current liabilities (105,582) (120,407) 7,317
Deferred debits and credits 68,165 92,907 (287,653)
Change in other miscellaneous operating activities (15,399) 42,766 (98,482)
Net cash provided by operating activities 586,327 325,187 169,650
Investing activities:
Plant expenditures (excluding AFUDC) (368,084) (229,867) (184,306)
Proceeds from sale of nuclear asset 26,866 - -
Other investments 9,445 3,231 (53,843)
Net cash used in investing activities (331,773) (226,636) (238,149)
Financing activities:
Redemptions:
Preferred stock - (50,000) -
Long-term debt (166,917) (99,728) (257,853)
Financing costs (5,218) - (2,100)
Issuances/(repurchases):
Common shares - - (212,611)
Long-term debt 500,000 - 500,000
Net change in notes payable (426,247) 156,500 10,347
Dividends paid (114,389) (115,541) (116,010)
Net cash used in financing activities (212,771) (108,769) (78,227)
Net increase (decrease) in cash and cash equivalents 41,783 (10,218) (146,726)
Cash and cash equivalents at the beginning of the year 11,655 21,873 168,599
Cash and cash equivalents at the end of the year $ 53,438 $ 11,655 $ 21,873
========= ========= =========
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 155,265 $ 177,239 $ 166,072
Income taxes (refund) $ 95,980 $ 198,326 $ (11,441)
Supplemental disclosure of investing activity:
Investment in common shares - $ 4,537 -
The accompanying notes are an integral part of the consolidated
financial statements.
Notes to Consolidated Financial Statements
Note A. Business Organization and Summary of Significant
Accounting Policies
1. About NSTAR
NSTAR is an energy delivery company focusing its activities in
the transmission and distribution of energy. NSTAR serves
approximately 1.4 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 0.3 million gas customers in 51 communities. NSTAR is a
public utility holding company generally exempt from the
provisions of the Public Utility Holding Company Act of 1935.
NSTAR's retail utility subsidiaries are Boston Edison Company
(Boston Edison), Commonwealth Electric Company (ComElectric),
Cambridge Electric Light Company (Cambridge Electric) and NSTAR
Gas Company (NSTAR Gas). Its wholesale electric subsidiary is
Canal Electric Company (Canal). NSTAR's three retail electric
companies operate under the brand name "NSTAR Electric."
Reference in this report to "NSTAR" shall mean the registrant
NSTAR or one or more of its subsidiaries as the context requires.
Reference in this report to "NSTAR Electric" shall mean each of
Boston Edison, ComElectric and Cambridge Electric. NSTAR's non-
utility, unregulated operations include district energy
operations (Advanced Energy Systems, Inc. and NSTAR Steam
Corporation), telecommunications operations - NSTAR
Communications, Inc. (NSTAR Com) and a liquefied natural gas
service company (Hopkinton LNG Corp.).
2. Basis of Consolidation and Accounting
The accompanying Consolidated Financial Statements reflect the
results of operations, comprehensive income, retained earnings,
financial position and cash flows of NSTAR and its subsidiaries.
All significant intercompany transactions have been eliminated in
consolidation. Certain reclassifications have been made to prior
year amounts to conform to the current year's presentation.
NSTAR's utility subsidiaries follow accounting policies
prescribed by the Federal Energy Regulatory Commission (FERC) and
the Massachusetts Department of Telecommunications and Energy
(MDTE). In addition, NSTAR and its subsidiaries are subject to
the accounting and reporting requirements of the Securities and
Exchange Commission (SEC). The accompanying Consolidated
Financial Statements conform to accounting principles generally
accepted in the United States of America (GAAP). The utility
subsidiaries are subject to the Financial Accounting Standards
Board (FASB) Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of
Regulation" (SFAS 71). The application of SFAS 71 results in
differences in the timing of recognition of certain expenses from
that of other businesses and industries. The distribution
business remains subject to rate-regulation and continues to meet
the criteria for application of SFAS 71. Refer to Note D to
these Consolidated Financial Statements for more information on
regulatory assets.
The preparation of financial statements in conformity with GAAP
requires management of NSTAR and its subsidiaries to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from these estimates.
3. Revenues
Utility revenues are based on authorized rates approved by the
MDTE and FERC. Estimates of transmission, distribution and
transition revenues for electricity and natural gas delivered to
customers but not yet billed are accrued at the end of each
accounting period.
Revenues for NSTAR's non-utility subsidiaries are recognized when
services are rendered or when the energy is delivered.
4. Utility Plant
Utility plant is stated at original cost of construction. The
costs of replacements of property units are capitalized.
Maintenance and repairs and replacements of minor items are
expensed as incurred. The original cost of property retired, net
of salvage value, and the related costs of removal are charged to
accumulated depreciation.
5. Non-Utility Plant
Non-utility property is stated at cost or its net realizable
value. The following is a summary of non-utility property and
equipment, at cost less accumulated depreciation, at December 31:
(in thousands) 2002 2001
Land $ 15,700 $ 15,987
Energy production equipment 71,333 66,729
Telecommunications equipment 37,856 33,065
Gas storage 42,701 42,701
Buildings and improvements 2,992 2,992
170,582 161,474
Less: accumulated depreciation (68,238) (59,747)
102,344 101,727
Construction work in progress 27,574 4,280
$129,918 $106,007
======== ========
Depreciation expense on non-utility property and equipment was
$8.5 million for 2002 and $21.8 million for 2001.
6. Depreciation
Depreciation of utility plant is computed on a straight-line
basis using composite rates based on the estimated useful lives
of the various classes of property. The composite rates are
subject to the approval of the MDTE and FERC. The overall
composite depreciation rates for utility property were 3.26%,
3.02% and 3.06% in 2002, 2001 and 2000, respectively.
Depreciation of non-utility property is computed on a straight-
line basis over the estimated life of the asset. The estimated
depreciable service lives of the major components of non-utility
property and equipment at December 31, 2002 are as follows:
Depreciable
Plant Component Life
Energy production equipment 25-35
Telecommunications equipment 10
Liquefied gas storage facilities 28
Buildings and improvements 40
7. Costs Associated with Issuance and Redemption of Debt and
Preferred Stock
Consistent with the recovery in utility rates, discounts,
redemption premiums and related costs associated with the
issuance and redemption of long-term debt and preferred stock are
deferred. The costs related to long-term debt are recognized as
an addition to interest expense over the life of the original or
replacement debt. Consistent with an accounting order received
from the FERC, costs related to preferred stock issuances and
redemptions are reflected as a direct reduction to retained
earnings upon redemption or over the average life of the
replacement preferred stock series as applicable.
8. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant
construction. In accordance with regulatory accounting, AFUDC is
included as a cost of utility plant and a reduction of current
interest charges. Although AFUDC is not a current source of cash
income, the costs are recovered from customers over the service
life of the related plant in the form of increased revenues
collected as a result of higher depreciation expense. Average
AFUDC rates in 2002, 2001 and 2000 were 2.26%, 4.31% and 6.16%,
respectively, and represented only the cost of short-term debt
and excludes the impact of capitalized interest.
9. Cash, Cash Equivalents and Restricted Cash
Cash, cash equivalents and restricted cash are comprised of
liquid securities with maturities of 90 days or less when
purchased. Restricted cash primarily represents the net proceeds
from the sale of Canal's generation assets that are required to
be used to reduce the transition costs that otherwise would be
billed to customers and funds held by a trustee in connection
with Advanced Energy System's 6.924% Note Agreement.
10. Equity Method of Accounting
NSTAR uses the equity method of accounting for investments in
corporate joint ventures in which it does not have a controlling
interest. Under this method, it records as income or loss the
proportionate share of the net earnings or losses of the joint
ventures with a corresponding increase or decrease in the
carrying value of the investment. The investment is reduced as
cash dividends are received. NSTAR participates in several
corporate joint ventures in which it has investments, principally
its 14.5% equity investment in two companies that own and operate
transmission facilities to import electricity from the Hydro-
Quebec System in Canada, and its equity investments ranging from
2.5% to 14% in three regional nuclear facilities that are
currently being decommissioned.
11. Goodwill and Costs to Achieve
The merger that created NSTAR was accounted for using the
purchase method of accounting. The premium (Goodwill) associated
with the acquisition was approximately $490 million, while the
original estimate of transaction and integration costs to achieve
the merger was $111 million. The merger premium is reflected on
the accompanying Consolidated Balance Sheets as Goodwill. In
accordance with the MDTE's settlement agreement, this premium
will continue to be amortized over 40 years and amounts to
approximately $12.2 million annually, while the costs to achieve
(CTA) are being amortized over 10 years. CTA are the costs
incurred to execute the merger including the employee costs for a
voluntary severance program, costs of financial advisers, legal
costs, and other transaction and systems integration costs. CTA
is being amortized at an annual rate of $11.1 million based on
the original rate plan. NSTAR will reconcile the actual CTA
costs incurred with the original estimate in a future rate
proceeding. This reconciliation will include a final accounting
of the deductibility for income tax purposes of each component of
CTA. The total CTA is approximately $143 million. This increase
from the original estimate is partially mitigated by the fact
that the portion of CTA that is not deductible for income tax
purposes is approximately $20 million lower than the original
estimate. NSTAR anticipates that these incremental costs are
probable of recovery in future rates. The CTA and Goodwill
amounts were filed and approved as part of the rate plan. Refer
to SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS
142) in the "New Accounting Standards" section to follow for a
further discussion.
12. Stock Option Plan
NSTAR's Share Incentive Plan is a stock-based employee
compensation plan, and is described more fully in the
accompanying Note H to Consolidated Financial Statements. NSTAR
applies the recognition and measurement principles of APB Opinion
No. 25, "Accounting for Stock Issued to Employees" (APB 25) and
related Interpretations in accounting for this plan. No stock-
based employee compensation expense for option grants is
reflected in net income as all options granted under those plans
had an exercise price equal to the market value of the underlying
common stock on the date of grant. The following table
illustrates the effect on net income and earnings per share if
NSTAR had applied the fair value recognition provisions of SFAS
No. 123, "Accounting for Stock-Based Compensation" (SFAS 123) to
stock-based employee compensation.
Years Ended December 31,
(in thousands, except per share amounts) 2002 2001 2000
Net income, as reported $163,667 $ 3,201 $180,962
Add: Stock-based employee compensation
expense included in reported net
income, net of related tax effects 1,642 1,241 1,030
Deduct: Total stock-based employee
compensation expense determined under
fair value method for all awards, net
of related tax effects (2,489) (1,972) (1,755)
Pro forma net income $162,820 $ 2,470 $180,237
Earnings (loss) per share:
Basic - as reported $3.05 $(.05) $3.19
Basic - pro forma $3.03 $(.06) $3.18
Diluted - as reported $3.03 $(.05) $3.18
Diluted - pro forma $3.02 $(.06) $3.17
13. Other Income (Deductions), net
Major components of other income were as follows:
Years ended December 31,
(in thousands) 2002 2001 2000
Equity earnings, dividends and other
investment income $ 2,667 $ 2,258 $ 2,279
Gain on demutualized securities 4,928 4,461 -
Interest and rental income 5,025 5,829 5,716
Tax valuation allowance adjustment 3,849 - -
Investment tax credit 7,272 - -
Settlement of claims - 1,818 6,382
Miscellaneous other income,(includes
applicable income tax expense for
total other income) (1,377) (7,443) (5,438)
$22,364 $ 6,923 $ 8,939
======= ======== =======
Major components of other deductions were as follows:
Years ended December 31,
(in thousands) 2002 2001 2000
Shutdown costs of unregulated business $(2,000) $(5,000) $ -
Charitable contributions (1,175) (237) (1,175)
Miscellaneous other deductions, (includes
applicable income tax benefit for total
other deductions) 656 2,210 806
Minority interest 525 1,076 3,491
$(1,994) $(1,951) $ 3,122
======= ======= =======
14. New Accounting Standards
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142). This Statement, which was
effective for NSTAR on January 1, 2002, establishes accounting
and reporting standards for acquired goodwill and other
indefinite lived intangible assets. It prohibits entities from
continuing amortization of these assets. Instead, goodwill and
other intangible assets are subject to review for impairment.
However, in accordance with provisions of SFAS 142 and a revised
amendment to SFAS 71, NSTAR will continue amortizing goodwill
over its estimated regulatory recovery period. Goodwill on
NSTAR's Consolidated Balance Sheets is subject to impairment in
accordance with provisions under SFAS 71. NSTAR has determined
that its regulatory rate structure, resulting from the merger and
approved by the MDTE, supports the continued amortization of
goodwill over 40 years, the period it is collected from its
customers.
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143). This Statement, which
is effective for NSTAR on January 1, 2003, establishes accounting
and reporting standards for obligations associated with the
retirement of tangible long-lived assets and the associated asset
retirement costs. It applies to legal obligations associated
with the retirement of long-lived assets that result from the
acquisition, construction, development and/or the normal
operation of a long-lived asset, except for certain obligations
of lessees. SFAS 143 requires entities to record the fair value
of a liability for an asset retirement obligation in the period
in which it is incurred. When the liability is initially
recorded, the entity capitalizes the cost by increasing the
carrying amount of the related long-lived asset. Over time, the
liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity
either settles the obligation for its recorded amount or incurs a
gain or loss upon settlement. Management is currently assessing
the impact of SFAS 143 in light of its regulatory and accounting
requirements. In its assessment, management has identified
several minor long-lived assets, including obligations under
lease and easement arrangements, and has determined that it is
legally responsible to remove such property and comply with the
requirements of this standard. However, based on NSTAR's
assessment of its potential liability and rate regulatory
treatment for certain identified assets, the adoption of SFAS 143
will not have a material effect on NSTAR's results of operations,
cash flows, or financial position.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-
Lived Assets" (SFAS 144), was effective January 1, 2002, and
addresses accounting and reporting for the impairment or disposal
of long-lived assets. SFAS 144, among other things, expands the
reporting of discontinued operations to include all components of
an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. NSTAR has
reviewed and assessed for impairment certain of its non-utility
assets and based on its assessment, it has determined as of
December 31, 2002, that the implementation of SFAS 144 had no
effect on NSTAR's results of operations or financial position.
The FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" (SFAS 146), that requires
entities to record a liability for costs related to exit or
disposal activities when the costs are incurred. Previous
accounting guidance required the liability to be recorded at the
date of commitment to an exit or disposal plan. NSTAR is
required to comply with SFAS 146 beginning January 1, 2003.
NSTAR anticipates that the implementation of this standard will
not have an impact on its financial position or results of
operations.
In November 2002, FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (the
Interpretation). The Interpretation elaborates on the
disclosures to be made by a guarantor in its interim and annual
financial statements about its obligations under certain
guarantees it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of a guarantee, a
liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and initial
measurement provisions of this Interpretation are applicable on a
prospective basis to guarantees issued or modified after December
31, 2002. For NSTAR, disclosure requirements are effective with
the 2002 Consolidated Financial Statements contained in this
report. Refer to Note O, "Commitments and Contingencies," for
more discussion. The application of this Interpretation is
not expected to materially impact the financial condition,
results of operations, and cash flows of NSTAR.
15. Purchases and Sales Transactions with Independent System
Operator - New England (ISO-NE)
During 2001, as part of NSTAR Electric's normal business
operations in order to meet its energy obligation to its standard
offer customers, NSTAR Electric entered into hourly transactions
to purchase or sell energy supply to its ISO-NE. The NSTAR
Electric transactions with the ISO-NE have been treated as the
ISO-NE servicing the incremental needs of NSTAR Electric, that
is, transactions with ISO-NE associated with the difference
between NSTAR Electric's resource needs compared to NSTAR
Electric's resource availability. NSTAR Electric records the net
effect of transactions with the ISO-NE as an adjustment to
purchased power expense.
During 2002, NSTAR Electric entered into an agreement whereby all
of its energy supply resource entitlements are transferred to an
independent energy supplier, following which NSTAR Electric
repurchases its energy resource needs from this independent
energy supplier for NSTAR Electric's ultimate sale to its
standard offer customers. This transaction has been and will
continue to be recorded as a net purchase, similar to those
transactions with ISO-NE during 2001.
Note B. Earnings Per Common Share
Basic earnings per common share (EPS) is calculated by dividing
net income, after deductions for preferred dividends, by the
weighted average common shares outstanding during the year. SFAS
No. 128, "Earnings per Share," requires the disclosure of diluted
EPS. Diluted EPS is similar to the computation of basic EPS
except that the weighted average common shares is increased to
include the number of potential dilutive common shares. Diluted
EPS reflects the impact on shares outstanding of the deferred
(nonvested) shares and stock options granted under the NSTAR
Share Incentive Plan.
The following table summarizes the reconciling amounts between
basic and diluted EPS:
(in thousands, except per share amounts) 2002 2001 2000
Earnings (loss) available for common shareholders $161,707 $(2,426) $175,002
Basic EPS $ 3.05 $ (0.05) $ 3.19
Diluted EPS $ 3.03 $ (0.05) $ 3.18
Weighted average common shares outstanding for
basic EPS 53,033 53,033 54,887
Effect of dilutive shares:
Weighted average dilutive potential common
shares 264 183 158
Weighted average common shares outstanding for
diluted EPS 53,297 53,216 55,045
====== ====== ======
Note C. Investments - Available for Sale Securities
NSTAR classifies its investments in marketable securities as
available for sale. As of December 31, 2002, these investments
include 11.6 million common shares of RCN Corporation (RCN) and
represents approximately 10.6% of RCN's outstanding common
shares.
As of December 31, 2001, these investments included 4.1 million
common shares of RCN, 148,400 common shares of John Hancock
Financial Services, Inc. (John Hancock), and 141,300 common
shares of MetLife, Inc. (MetLife). During 2002, NSTAR sold all
of its common shares in John Hancock and MetLife for a gain of
$4.9 million. This gain is recorded as part of Other Income, net
in the accompanying Consolidated Statements of Income.
In accordance with its accounting policies, NSTAR continuously
evaluates the carrying value of its investment in RCN to assess
whether any decline in the market value below its carrying value
is deemed to be other than temporary. Consistent with the
performance of the telecommunications sector as a whole, the
market value of RCN's common shares decreased significantly
during the later part of 2000 and continued to decrease through
2002. As a result, in 2001 and 2002, management determined that
this decline in market value was "other-than-temporary" in
accordance with SFAS No. 115, "Accounting for Certain Investments
in Debt and Equity Securities."
NSTAR recognized non-cash, after-tax impairment charges in 2002
and 2001 on its investment in RCN common shares of $17.7 million
and $173.9 million, respectively. These charges are reported on
the accompanying Consolidated Statements of Income as "Write-down
of RCN Investment, net." The income tax results of NSTAR's
investment in RCN are described more fully in the accompanying
Note F to Consolidated Financial Statements.
The total carrying value of the 11.6 million RCN common shares is
included in Other investments on the accompanying Consolidated
Balance Sheets at its estimated fair value of approximately $6.1
million at December 31, 2002. The fair value of the 11.6 million
shares held may increase or decrease as a result of changes in
the market value of RCN common shares. As of December 31, 2002
and 2001, the market value per share of RCN was $0.53 and $2.93,
respectively. The unrealized gain or loss associated with these
shares will fluctuate due to the changes in fair value of these
securities during each period and is reflected, net of associated
income taxes, as a component of Other comprehensive income
(loss), net on the accompanying Consolidated Statements of
Comprehensive Income. The cumulative increase or decrease in
fair value of these shares including the impact of the write-down
adjustments of these shares are included in Accumulated other
comprehensive income on the accompanying Consolidated Balance
Sheets.
Note D. Regulatory Assets
Regulatory assets represent costs incurred that are expected to
be collected from customers through future rates in accordance
with agreements with regulators. These costs are expensed when
the corresponding revenues are received in order to appropriately
match revenues and expenses.
Regulatory assets consisted of the following:
December 31,
(in thousands) 2002 2001
Power contracts (including Yankee units) $ 773,922 $ 53,041
Generation-related regulatory assets, net 542,485 686,519
Pension costs 425,755 -
Merger costs to achieve 105,992 118,059
Income taxes 50,666 53,375
Purchased power costs 30,375 45,413
Postretirement benefits costs 15,088 16,965
Redemption premiums 13,479 12,853
Other 44,115 40,016
Total regulatory assets $2,001,877 $1,026,241
========== ==========
Under the traditional revenue requirements model, electric rates
are based on the cost of providing electric service. Under this
model, NSTAR Electric and NSTAR Gas are subject to certain
accounting standards that are not applicable to other businesses
and industries in general. The application of SFAS 71 requires
companies to defer the recognition of certain costs when incurred
if future rate recovery of these costs is expected. This is
applicable to NSTAR's distribution and transmission operations.
Power contracts
Approximately $72.8 million at December 31, 2002 represents the
remaining unamortized balance of the estimated costs to close the
Connecticut Yankee (CY), Yankee Atomic (YA) and Maine Yankee (MY)
nuclear power plants that are currently being decommissioned.
NSTAR's liability for CY decommissioning and its recovery ends in
2007, for YA in 2010 and for MY in 2008. However, should the
actual costs exceed current estimates and anticipated
decommissioning dates, NSTAR could have an obligation beyond
these periods that would be fully recoverable. These costs are
recovered through NSTAR Electric's transition charge. Refer to
Note O, "Commitments and Contingencies," for more discussion.
The remaining balance includes $701.1 million at December 31,
2002 representing the recognition of six purchased power
contracts as derivatives and their above-market value and future
recovery through NSTAR Electric's transition charges. Refer to
Note E, "Derivative Instruments - Power Contracts" for further
details.
Generation-related plant regulatory assets
Plant and other regulatory assets related to the divestiture of
NSTAR's generation business are recovered with a return through
the transition charge. This recovery occurs through 2016 for
Boston Edison, through 2023 for ComElectric and through 2011 for
Cambridge Electric. This schedule is subject to adjustment by
the MDTE.
As of December 31, 2002, $493.6 million of these generation-
related regulatory assets are collateralized with the Transition
Property Securitization Certificates held by Boston Edison's
subsidiary, BEC Funding, LLC. The certificates are non-recourse
to Boston Edison.
Pension costs
The regulatory asset attributable to pension costs represents the
deferral of pension related costs, which NSTAR expects to recover
from customers in future years. This amount results from the
reclassification of amounts, which in the absence of the MDTE
Accounting Order issued on December 20, 2002 (see Note G), would
otherwise have been classified as a charge to other comprehensive
income pursuant to SFAS 87 (as amended by SFAS 130). The amount
of the deferral consists of approximately $169 million that
represents the additional minimum pension liability recorded to
reflect the unfunded liability of NSTAR's pension plan, and
approximately $257 million, which represents the adjustment to
reverse the prepaid pension costs. Prepaid pension costs
represent the cumulative excess of cash contribution over the
cumulative net periodic pension costs. For purposes of financial
statement presentation, the amount previously reported as prepaid
pension costs in 2001 has been displayed net of the additional
minimum pension liability in 2002, as required by SFAS 87.
Merger costs to achieve
An integral part of the merger is the rate plan of the retail
utility subsidiaries of NSTAR that was approved by the MDTE on
July 27, 1999. Significant elements of the rate plan include a
four-year distribution rate freeze, recovery of the acquisition
premium (goodwill) over 40 years and recovery of transaction and
integration costs (costs to achieve) over 10 years. Costs to
achieve are the costs incurred to execute the merger including
costs for a voluntary severance program, costs of financial
advisors, legal costs and other transaction and systems
integration costs. These costs are collected from all NSTAR
Electric and NSTAR Gas distribution customers and exclude a
return component. These costs have been adjusted since the
original recovery began and any unrecovered costs will be
included in each company's next respective rate case filing.
Income taxes, net
The principal holder of this regulatory asset is Boston Edison.
Approximately $32 million of this regulatory asset balance
reflects deferred tax reserve deficiencies that the MDTE has
allowed recovery of from ratepayers over a 17 year period. In
addition, approximately $40 million in additional Boston Edison
deferred tax reserve deficiencies has been recorded in accordance
with an MDTE-approved settlement agreement. Offsetting these
amounts is approximately $21 million of a regulatory liability
associated with unamortized investment tax credits relating to
NSTAR Electric and NSTAR Gas.
Purchased power costs
The purchased power costs relate to deferred standard offer
service and deferred default service costs. Customers have the
option of continuing to buy power from the retail electric
distribution businesses at standard offer prices through February
2005. Since 1998, NSTAR has been allowed to defer the difference
between the retail price per kWh for standard offer and default
service revenues and the cost to supply the power, plus carrying
costs. Default service is the electricity that is supplied by
the local distribution company when a customer is not receiving
power from standard offer service. The market price for standard
offer and default service will fluctuate based on the average
market price for power. Amounts collected through standard offer
and default service are recovered on a fully reconciling basis.
Postretirement benefits costs
Cambridge Electric in its last base rate case was allowed by the
MDTE to recover costs over a four-year phase-in for the full tax
deductible amount of deferred postretirement costs other than
pension. Cambridge Electric will include any remaining
unrecovered costs in its next distribution rate case filing.
There is no current recovery of these deferred costs; however,
ComElectric is recovering its deferred postretirement costs other
than pension over a ten-year period with no return allowed.
ComElectric will include any remaining unrecovered costs in its
next distribution rate case filing. There is no current recovery
of these deferred costs. Boston Edison will include these costs
in its next base rate case filing. There is no current recovery
of these deferred costs.
Redemption premiums
These amounts reflect the unamortized balance of redemption
premium on Boston Edison Debentures that is amortized and
recovered over the life of the respective debentures pursuant to
MDTE approval. There is no return recognized on this balance.
Other
These amounts primarily consist of deferred transmission revenues
that are set to be recovered over a subsequent twelve-month
period. The deferred revenue represents the difference between
the level of billed transmission revenues and the current period
costs incurred to provide transmission-related services.
Also included are environmental reserves and response costs that
represent the recovery of costs to clean up former gas
manufacturing sites over a 7-year period without a return.
Note E. Derivative Instruments - Power Contracts
NSTAR adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133), effective January
1, 2001. The accounting for derivative financial instruments is
subject to change based on the guidance received from the
Derivative Implementation Group (DIG) of FASB. The DIG issued
No. C15, "Scope Exceptions: Normal Purchases and Normal Sales
Exception for Option-Type Contracts and Forward Contracts in
Electricity" on October 10, 2001, which specifically addressed
the interpretation of clearly and closely related contracts that
qualify for the normal purchases and sales exception under SFAS
133. The conclusion reached by the DIG was that contracts with a
pricing mechanism that is subject to future adjustment based on a
generic index that is not specifically related to the contracted
service commodity generally would not qualify for the normal
purchases and sales exception.
On April 1, 2002, the effective date of DIG Issue C15, NSTAR
adopted the interpretation of this guidance and began marking to
market certain of its long-term purchased power contracts that
previously qualified for the normal purchases and sales
exception. NSTAR has six purchased power contracts that contain
components with pricing mechanisms that are based on a pricing
index, such as the GNP or CPI. Although these factors are only
applied to certain ancillary pricing components of these
agreements, as required by the interpretation of DIG Issue C15,
NSTAR began recording these contracts at fair value on its
Consolidated Balance Sheets during 2002. This action resulted in
the recognition of a liability for the fair value of the above-
market portion of these contracts at December 31, 2002 of
approximately $701 million and is a component of Deferred credits
- - Power contracts on the accompanying Consolidated Balance
Sheets. NSTAR has recorded a corresponding regulatory asset to
reflect the future recovery of the above-market component of
these contracts through its transition charge. Therefore, as a
result of this regulatory treatment, the recording of these
contracts on its accompanying Consolidated Balance Sheets does
not result in an earnings impact.
NSTAR has other purchased power contracts in which the contract
value is significantly above-market. However, these contracts
have met the criteria for the normal purchases and sales exception
pursuant to SFAS 133 and DIG Issue C15 and have not been recorded
on the accompanying Consolidated Balance Sheets. The above-
market portion of these contracts is currently being recovered
through the transition charge. Therefore, NSTAR does not account
for these types of capacity and energy contracts, gas supply
contracts, or purchase orders for numerous supply arrangements as
derivatives.
Note F. Income Taxes
Income taxes are accounted for in accordance with SFAS No. 109,
"Accounting for Income Taxes" (SFAS 109). SFAS 109 requires the
recognition of deferred tax assets and liabilities for the future
tax effects of temporary differences between the carrying amounts
and the tax basis of assets and liabilities. In accordance with
SFAS 109, net regulatory assets of $50.7 million and $53.4
million and corresponding net increases in accumulated deferred
income taxes were recorded as of December 31, 2002 and 2001,
respectively. The regulatory assets represent the additional
future revenues to be collected from customers for deferred
income taxes.
Accumulated deferred income taxes and unamortized investment tax
credits consisted of the following:
December 31,
(in thousands) 2002 2001
Deferred tax liabilities:
Plant-related $421,599 $351,882
Transition costs 206,895 233,465
Other 259,466 313,480
887,960 898,827
Deferred tax assets:
Plant-related 59,155 61,543
Investment tax credits 18,317 23,956
Other 158,546 154,600
236,018 240,099
Net accumulated deferred income taxes 651,942 658,728
Accumulated unamortized investment tax
credits 28,631 37,877
$680,573 $696,605
======= =======
Previously deferred investment tax credits are amortized over the
estimated remaining lives of the property generating the credits.
Components of income tax expense were as follows:
(in thousands) 2002 2001 2000
Current income tax expense $ 89,201 $148,230 $ 68,944
Deferred income tax expense (benefit) 19,886 (32,735) 50,461
Investment tax credit amortization (1,974) (2,083) (1,985)
Income taxes charged to operations 107,113 113,412 117,420
Tax (benefit) expense on other income,
net (25,437) 12,032 11,480
Total income tax expense $ 81,676 $125,444 $128,900
======= ======= =======
Tax expense on other income, net reflects $7.3 million in 2002 of
investment tax credits recognized as a result of the sale of
Seabrook.
The effective income tax rates reflected in the Consolidated
Financial Statements and the reasons for their differences from
the statutory federal income tax rate were as follows:
2002 2001 2000
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 4.8 5.3 5.1
Investment tax credits (3.2) (0.7) (0.6)
Other 0.7 0.6 2.1
Effective tax rate before write-down and tax
valuation allowance adjustment 37.3 40.2 41.6
Adjustment to tax valuation allowance and write-
down of RCN investment (federal and state) (4.0) 57.3 -
Effective tax rate 33.3% 97.5% 41.6%
==== ==== ====
a. Tax Valuation Allowance
SFAS 109 prohibits the recognition of all or a portion of
deferred income tax benefits if it is more likely than not that
the deferred tax asset will not be realized. NSTAR had
determined that it was more likely than not that a current or
future income tax benefit would not be realized relating to the
write-downs of its RCN investment that were recorded in the
second and fourth quarters of 2002 and previously in the first
quarter of 2001. These write-downs resulted from the significant
declines in the market value of the telecommunications sector,
including RCN. As a result of this uncertainty, NSTAR recorded a
$77.6 million tax valuation allowance on the entire tax benefit
associated with these write-downs. During 2002, as a result of
previously unanticipated capital gain transactions, NSTAR
recognized $3.9 million of this tax benefit.
Additionally, based on the Internal Revenue Service (IRS) review
of NSTAR's 1999 and 2000 federal income tax returns, NSTAR
determined that it was more likely than not that it would
ultimately recognize the tax benefits relating to the incremental
operating losses from the joint venture. The returns are
currently being audited by the IRS as part of their normal review
of NSTAR's consolidated federal income tax returns. The tax
valuation allowance included reserves relating to the tax
treatment of these losses through June 19, 2002. Each of the tax
returns filed for 1999 through 2001 claimed operating losses.
The return to be filed for 2002 will also claim the remaining
portion of these operating losses. The issues involving the
operating loss deductions recorded on the tax returns for the
years 2001 and 2002 are substantially similar to those that had
concerned NSTAR regarding the tax treatment of that item on the
1999 and 2000 returns. Based on the IRS examining agent's
current review, no adjustment for the years under audit is
proposed. A determination of this issue was arrived at in the
fourth quarter of 2002 and, as a result, NSTAR applied the
treatment of these operating losses for all years on a consistent
basis, allowing a reduction to its valuation allowance of
approximately $19.7 million as a net credit to income tax expense
included as a component of the write-down of the RCN investment.
NSTAR has and will continue to research potential transactions
that improve the operational efficiencies of NSTAR while
maximizing the utilization of these potential tax benefits.
Should NSTAR be successful in its tax and operational planning to
allow a portion of the remaining tax benefit to be ultimately
realized, NSTAR will reflect a credit to its income tax expense.
Future earnings could be positively impacted by the outcome of
this strategy. The maximum potential positive future earnings
impact is currently estimated at $53 million. Management is
currently unable to determine when, whether, or the extent to
which NSTAR will be able to recognize this potential benefit.
b. Tax Gain on Generating Assets
The cost of transitioning to retail open access was mitigated, in
part, by the sale of Commonwealth Energy System's (COM/Energy)
(now a wholly owned subsidiary of NSTAR) non-nuclear generating
assets. COM/Energy completed the sale of substantially all of
its non-nuclear generating assets in 1998. Proceeds from the
sale of these assets amounted to approximately $453.9 million, or
6.1 times their book value of approximately $74.2 million. The
proceeds from the sale, net of book value, transaction costs and
certain other adjustments amounted to $358.6 million and are
required to be used for the benefit of COM/Energy customers under
MDTE rate setting policies. In this instance, the amount was
used to reduce transition costs of Cambridge Electric and
ComElectric related to electric industry restructuring.
COM/Energy determined that this transaction was not a taxable
event because it did not provide an economic benefit to its
shareholders. The amount, if not for this treatment, that would
otherwise have been paid in taxes is approximately $136 million.
Should COM/Energy ultimately lose this issue, tax deductions
resulting in tax savings of approximately $136 million would be
realized by COM/Energy over a period of years. During the second
quarter of 2002, NSTAR was notified that the IRS intended to file
a Request for Technical Advice with the IRS National Office with
regard to COM/Energy's tax treatment of this item. As of
December 31, 2002, the Requests for Technical Advice had not yet
been filed.
The IRS is in the process of completing its audit of COM/Energy's
tax returns for the years 1997, 1998 and 1999. The audit will
not be closed at the examination level until the issue described
above has been resolved either by the IRS closing the audit with
no adjustment for the item or by providing COM/Energy with a tax
deficiency notice. Should COM/Energy be issued a deficiency
notice it must then decide to either contest the notice (at IRS
Appellate or in a court of law) or concede the issue. It is
expected that once the request for Technical Advice is filed, a
National Office decision would be made within two months. Should
NSTAR's position be challenged, it is probable that NSTAR will
make a tax payment of approximately $60 million in order to stop
the accrual of interest on the potential remaining tax deficiency
for all years involved through 2002. NSTAR intends to vigorously
defend its position, which is supported by an opinion from an
independent tax advisor, relative to this transaction and
anticipates pursuing a refund of any amounts paid plus interest.
In addition, NSTAR would pursue regulatory rate recovery for the
interest on tax deficiencies should any amounts ultimately be
incurred as a result of this transaction. The MDTE has provided
written acknowledgements to NSTAR indicating: (1) its
understanding of the issue; and (2) COM/Energy's ability to seek
recovery of costs relating to the tax deficiency that may be
incurred. NSTAR believes that recovery from customers is
probable in view of the MDTE's position and its understanding of
the monetary benefits to be realized by COM/Energy's customers
should it be successful in defending its position. However, if
NSTAR is unsuccessful with the IRS and unsuccessful in getting
favorable regulatory treatment, it is possible that it could have
an adverse impact on NSTAR's results of operations, cash flows
and financial position.
Note G. Pension and Other Postretirement Benefits
1. Pension
NSTAR sponsors a defined benefit funded retirement plan (the
Plan) that covers substantially all employees. NSTAR also
maintains unfunded supplemental retirement plans for certain
management employees.
In 2002, the Plan was amended to comply with the Economic Growth
and Tax Relief Reconciliation Act of 2001 (EGTRRA). EGTRRA,
among other things, increased the annual benefits limit for
amounts payable from the Plan to $160,000, increased the number
of rollover options for distributions, and allowed surviving
spouses to rollover distributions to their employer's plan. This
amendment also brought the Plan into conformance with recently
issued IRS revenue rulings and regulations that require the
change of the mortality table used for computing lump sum pension
distributions and annuity conversions.
The changes in benefit obligation and Plan assets were as
follows:
December 31,
(in thousands) 2002 2001
Change in benefit obligation:
Benefit obligation, beginning of the year $ 824,302 $804,358
Service cost 15,280 14,082
Interest cost 59,658 57,381
Plan participants' contributions 74 71
Plan amendments 671 -
Actuarial loss 108,037 14,579
Additional accrued benefits 15,194 -
Settlement payments (21,529) (17,176)
Benefits paid (52,041) (48,993)
Benefit obligation, end of the year $ 949,646 $824,302
========= ========
Change in Plan assets:
Fair value of Plan assets, beginning of the year $ 790,704 $846,207
Actual loss on Plan assets, net (105,578) (52,493)
Employer contribution 54,267 63,088
Plan participants' contributions 74 71
Settlement payments (21,529) (17,176)
Benefits paid (52,041) (48,993)
Fair value of Plan assets, end of the year $ 665,897 $790,704
========= ========
The Plan's funded status was as follows:
December 31,
(in thousands) 2002 2001
Funded status $(283,749) $(33,598)
Unrecognized actuarial net loss 523,967 249,456
Unrecognized transition obligation 980 1,581
Unrecognized prior service cost (2,829) (3,420)
Net amount recognized $ 238,369 $214,019
========= ========
Amount recognized in the accompanying Consolidated Balance Sheets
consisted of:
December 31,
(in thousands) 2002 2001
Prepaid benefit cost $ - $218,713
Accrued retirement liability (198,280) (10,547)
Intangible asset 6,379 5,853
Accumulated other comprehensive income 4,515 -
Regulatory asset 425,755 -
Net amount recognized $ 238,369 $214,019
========= ========
The projected benefit obligation, accumulated benefit obligation
and fair value of plan assets for the supplemental retirement
plan with accumulated benefit obligations in excess of plan
assets were $32,154,000, $28,561,000 and $0, respectively, as of
December 31, 2002 and $13,785,000, $10,547,000 and $0,
respectively, as of December 31, 2001.
Weighted average assumptions were as follows:
2002 2001 2000
Discount rate at the end of the year 6.5% 7.25% 7.5%
Expected return on Plan assets for the
year (net of investment expenses) 9.4% 9.4% 9.3%
Rate of compensation increase at the end
of the year 4.0% 4.0% 4.0%
The expected return on Plan assets has been adjusted to 8.4% in
2003.
Components of net periodic benefit cost/(income) were as follows:
Years ended December 31,
(in thousands) 2002 2001 2000
Service cost $ 15,280 $ 14,082 $ 14,636
Interest cost 59,658 57,381 59,798
Expected return on Plan assets (74,426) (78,397) (85,884)
Amortization of prior service cost 80 80 448
Amortization of transition obligation 601 601 601
Recognized actuarial loss 13,530 830 -
Net periodic benefit cost/(income) $ 14,723 $ (5,423) $(10,401)
======== ======== ========
Funded Status
NSTAR's qualified Plan assets have been affected by significant
declines in the equity markets in the past three years. These
conditions have impacted the funded status of the Plan at
December 31, 2002. As a result of the negative investment
performance, at December 31, 2002, the accumulated benefit
obligation exceeded Plan assets. Therefore, NSTAR is required to
recognize an additional minimum liability as prescribed by SFAS
No. 87, "Employers' Accounting for Pensions" (SFAS 87) and SFAS
No. 132, "Employers' Disclosures about Pensions and
Postretirement Benefits." The additional minimum liability
results in the netting of the Prepaid pension cost with the
additional minimum liability on the accompanying Consolidated
Balance Sheet.
Under SFAS 87, NSTAR is also required to net its prepaid pension
balance. The additional minimum pension liability adjustment,
which is equal to the sum of the minimum pension liability and
the prepaid pension adjustment, would be recorded, net of taxes,
as a non-cash charge to Other Comprehensive Income (OCI) on the
accompanying Consolidated Statements of Comprehensive Income and
would not affect the results of operations for 2002. The fair
value of Plan assets and the ABO are measured at each year-end
balance sheet date. The minimum liability will be adjusted each
year to reflect this measurement. At such time that the Plan
assets exceed the ABO, the minimum liability would be reversed.
In November 2002, NSTAR filed a request with the MDTE seeking an
accounting ruling to mitigate the impact of the non-cash charge
to OCI in 2002 and the increases in expected pension and PBOP
costs in 2003. On December 20, 2002, the MDTE approved the
Accounting Order. Based on this Accounting Order and an opinion
from legal counsel regarding the probability of recovery of these
costs in the future, NSTAR recorded a regulatory asset in lieu of
taking a charge to OCI at December 31, 2002. In addition, the
order permits NSTAR to defer, as a regulatory asset or liability,
the difference between the level of pension and PBOP expense that
is included in rates and the amounts that are required to be
recorded under SFAS 87 and SFAS 106 beginning in 2003.
The regulatory asset of $426 million, recorded as a result of this
accounting ruling, consists of the prepaid pension asset ($257
million) and includes the additional minimum liability ($169 million)
incurred at December 31, 2002. The regulatory asset is shown as part
of Deferred debits in the accompanying Consolidated Balance Sheets.
2. Other Postretirement Benefits
NSTAR provides health care and other benefits to retired
employees who meet certain age and years of service eligibility
requirements. These benefits include health and life insurance
coverage and reimbursement until April 1, 2003 of certain
Medicare premiums. Under certain circumstances, eligible
employees are required to make contributions for postretirement
benefits.
The changes in benefit obligation and plan assets were as
follows:
December 31,
(in thousands) 2002 2001
Change in benefit obligation:
Benefit obligation, beginning of the year $ 469,903 $ 428,341
Service cost 5,204 4,332
Interest cost 33,170 31,662
Plan participants' contributions 1,490 1,811
Plan amendments (20,908) -
Actuarial loss 110,055 30,716
Benefits paid (27,241) (26,959)
Benefit obligation, end of the year $ 571,673 $ 469,903
========= =========
Change in plan assets:
Fair value of plan assets, beginning of
the year $ 225,848 $ 224,651
Actual loss on plan assets (23,523) (13,376)
Employer contribution 38,500 39,721
Plan participants' contributions 1,490 1,811
Benefits paid (27,241) (26,959)
Fair value of plan assets, end of the
year $ 215,074 $ 225,848
========= =========
The plans' funded status and amount recognized in the
accompanying Consolidated Balance Sheets were as follows:
December 31,
(in thousands) 2002 2001
Funded status $(356,599) $(244,055)
Unrecognized actuarial net loss 283,651 134,006
Unrecognized transition obligation 56,168 61,784
Unrecognized prior service cost (35,730) (16,233)
Net amount recognized $ (52,510) $ (64,498)
========= =========
Weighted average assumptions were as follows:
2002 2001 2000
Discount rate at the end of the year 6.5% 7.25% 7.5%
Expected return on plan assets for the year 9.0% 9.0% 9.0%
For measurement purposes a 9% weighted annual rate increase in
per capita cost of covered medical claims was assumed for 2003.
This rate is assumed to decrease gradually to 5% in 2013 and
remain at that level thereafter. Dental claims and Medicare
premiums are assumed to increase at a weighted annual rate of 4%
and 5%, respectively. The expected rate of return on plan assets
is 8% in 2003.
A 1% change in the assumed health care cost trend rate would have
the following effects:
One-Percentage-Point
(in thousands)
Increase Decrease
Effect on total service and interest costs
components for 2002 $ 3,203 $ (2,639)
Effect on December 31, 2002 postretirement
benefit obligation $47,461 $(39,784)
Components of net periodic benefit cost were as follows:
Years ended December 31,
(in thousands) 2002 2001 2000
Service cost $ 5,204 $ 4,332 $ 3,563
Interest cost 33,170 31,662 29,574
Expected return on plan assets (22,655) (21,430) (19,010)
Amortization of prior service cost (1,411) (1,411) (1,703)
Amortization of transition obligation 5,616 5,616 5,616
Recognized actuarial loss 6,588 2,352 -
Net periodic benefit cost $ 26,512 $ 21,121 $ 18,040
======== ======== ========
3. Savings Plan
NSTAR also provides a defined contribution 401(k) plan for
substantially all employees. Matching contributions (which are
equal to 50% of the employees' deferral up to 8% of compensation)
included in the accompanying Consolidated Statements of Income
amounted to $9 million in both 2002 and in 2001, and $7 million
in 2000. The plan was amended, effective April 1, 2001, to allow
participants the ability to reallocate their investments in the
NSTAR Common Share Fund to other investment options. Effective
January 1, 2002, consistent with the EGTRRA, the plan was further
amended to allow for increased maximum annual pre-tax
contributions and additional "catch-up" pre-tax contributions for
participants age 50 or older, acceptance of other types of "roll-
over" pre-tax funds from other plans and the option of
reinvesting dividends paid on the NSTAR Common Share Fund or
receiving such dividends in cash. The election to reinvest
dividends paid on the NSTAR Common Share Fund or receive the
dividends in cash is subject to a freeze period beginning seven
days prior to the date any dividend is paid. During this period,
participants cannot change their election. Dividends are paid to
this plan four times a year on February 1, May 1, August 1, and
November 1.
Note H. Stock-Based Compensation
The NSTAR Share Incentive Plan (the Plan) permits a variety of
stock and stock-based awards, including stock options and
deferred (non-vested) stock to be granted to key employees. The
Plan limits the terms of awards to ten years. Subject to
adjustment for stock-splits and similar events, the aggregate
number of common shares that may be awarded under the Plan is
four million as a result of an amendment to the Plan approved by
shareholders in 2002 that increased the number of shares
available for issuance from two million to four million,
including shares issued in lieu of or upon reinvestment of
dividends arising from awards. The weighted average grant date
fair value of the deferred stock issued during 2002, 2001 and
2000 was $45.24, $39.70 and $44.38, respectively. During 2002,
45,300 deferred shares and 265,000 ten-year non-qualified stock
options were granted under the Plan. During 2001, 97,850
deferred shares and 240,500 ten-year non-qualified stock options
were granted. During 2000, 69,750 deferred shares and 316,700
ten-year non-qualified stock options were granted. The options
were granted at the full market price of the common shares on the
date of the grant. All the awards vest ratably over a three-year
period.
Stock option activity of the Plan was as follows:
Weighted Weighted Weighted
Average Average Average
2002 Exercise 2001 Exercise 2000 Exercise
Activity Price Activity Price Activity Price
Options outstanding
at January 1 967,602 $38.80 918,135 $39.09 814,267 $36.03
Options granted 265,000 $45.24 240,500 $39.70 316,700 $44.38
Options exercised (152,033) $39.92 (47,567) $40.21 (125,432) $31.66
Options forfeited (33,700) $42.92 (143,466) $41.68 (87,400) $40.42
Options outstanding
at December 31 1,046,869 $40.14 967,602 $38.80 918,135 $30.09
Summarized information regarding stock options outstanding at
December 31, 2002:
Options Outstanding Options Exercisable
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Exercise Prices Outstanding (Years) Price Outstanding Price
$25.75-$26.00 148,400 4.45 $25.92 148,400 $25.92
$39.75-$41.38 291,935 5.26 $40.37 291,935 $40.37
$44.38 182,200 7.40 $44.38 122,074 $44.38
$39.70 159,334 8.40 $39.70 52,580 $39.70
$44.12-$45.33 265,000 9.30 $45.24 - -
There were 614,989, 546,264 and 404,976 stock options exercisable
on December 31, 2002, 2001 and 2000, respectively. The weighted
average exercise price of these options exercisable are $37.62,
$36.54 and $34.44, respectively.
The stock options granted during 2002, 2001 and 2000 have a
weighted average grant date fair value of $5.97, $5.10 and $7.00,
respectively. The fair value was estimated using the Black-
Scholes option-pricing model with the following weighted average
assumptions:
2002 2001 2000
Expected life (years) 4.0 4.0 4.0
Risk-free interest rate 4.31% 4.82% 6.48%
Volatility 21% 21% 20%
Dividends 4.77% 5.34% 4.64%
Compensation cost recognized in the accompanying Consolidated
Statements of Income for stock-based compensation awards in 2002,
2001 and 2000 was $2,737,216, $2,069,000 and $1,717,000,
respectively.
Note I. Capital Stock
1. Common Shares
Common share issuances and repurchases in 2000 through 2002 were
as follows:
Number of Total Premium on
(in thousands) Shares Par Value Common Shares
Balance at December 31, 1999 58,060 $ 58,060 $1,075,483
Common share repurchase program (5,027) (5,027) (198,113)
Share Incentive Plan - - (621)
Balance at December 31, 2000 53,033 53,033 876,749
Share Incentive Plan and other - - (3,085)
Balance at December 31, 2001 53,033 53,033 873,664
Share Incentive Plan - - (2,787)
Balance at December 31, 2002 53,033 $ 53,033 $ 870,877
====== ======== ==========
Dividends declared per common share were $2.13, $2.075 and $2.015
in 2002, 2001 and 2000, respectively.
2. Cumulative Preferred Stock of Subsidiary
Non-mandatory redeemable series:
Par value $100 per share, 2,660,000 shares authorized and 430,000
shares issued and outstanding:
(in thousands, except per share amounts)
Current Shares Redemption December 31, December 31,
Series Outstanding Price/Share 2002 2001
4.25% 180,000 $103.625 $18,000 $18,000
4.78% 250,000 $102.80 25,000 25,000
Total non-mandatory redeemable series $43,000 $43,000
======= =======
500,000 shares of the mandatory redeemable 8% Series with a par
value of $100 per share were redeemed in total on December 3,
2001, plus accrued dividends from November 1, 2001 to December 1,
2001.
Note J. Indebtedness
1. Long-Term Debt
NSTAR's long-term debt consisted of the following:
December 31,
(in thousands) 2002 2001
Mortgage Bonds, collateralized by
property of operating subsidiaries:
6.54%, due September 2007 $ 7,143 $ 8,571
7.04%, due September 2017 25,000 25,000
9.95%, due December 2020 25,000 25,000
7.11%, due December 2033 35,000 35,000
Notes:
7.75%, due June 2002 - 2,100
9.30%, due January 2002 - 30,000
7.43%, due March 2003 15,000 15,000
9.50%, due December 2004 2,000 3,000
7.62%, due November 2006 20,000 20,000
8.70%, due March 2007 5,000 5,000
9.55%, due December 2007 7,143 8,571
7.70%, due March 2008 10,000 10,000
8.0%, due February 2010 498,444 498,226
9.37%, due January 2012 10,526 11,579
7.98%, due March 2013 25,000 25,000
9.53%, due December 2014 10,000 10,000
9.60%, due December 2019 10,000 10,000
6.924%, due June 2021 106,518 106,058
8.47%, due March 2023 15,000 15,000
Debentures:
6.80%, due March 2003 150,000 150,000
7.80%, due May 2010 125,000 125,000
8.25%, due September 2022 - 60,000
7.80%, due March 2023 181,000 181,000
4.875%, due October 2012 400,000 -
Floating Rate (2.275% in 2002), due October 2005 100,000 -
Sewage facility revenue bonds, due through 2015 19,882 21,470
Massachusetts Industrial Finance Agency
(MIFA) bonds:
5.75%, due February 2014 15,000 15,000
Transition Property Securitization Certificates:
6.45%, due through September 2005 40,555 108,986
6.62%, due March 2007 103,390 103,390
6.91%, due September 2009 170,876 170,876
7.03%, due March 2012 171,624 171,624
2,304,101 1,970,451
Amounts due within one year (212,746) (78,648)
Total long-term debt $2,091,355 $1,891,803
========== ==========
The 7.80% series debentures due 2023 are first redeemable in
March 2003 at 103.73%. There are no sinking fund requirements
for any series of debentures.
Sewage facility revenue bonds are tax-exempt, subject to annual
mandatory sinking fund redemption requirements and mature through
2015. Scheduled redemptions of $1.6 million were made in 2002
and 2001. The weighted average interest rate of the bonds was
7.4% in 2002 and 2001.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable
beginning in February 2004 at a redemption price of 102%. The
redemption price decreases to 101% in February 2005 and to par in
February 2006.
On October 15, 2002, Boston Edison issued two new debentures:
$400 million, 4.875% due in 2012 and $100 million, floating rate
debentures due in 2005 priced at three-month LIBOR plus 50 basis
points. Boston Edison used the proceeds to pay down short-term
debt and anticipates it will use approximately $40 million to
fund its $150 million debt maturing in March 2003.
The aggregate principal amounts of NSTAR long-term debt
(including securitization certificates and sinking fund
requirements) due in the five years subsequent to 2002 are
approximately $213 million in 2003, $79 million in 2004, $178
million in 2005, $98 million in 2006 and $84 million in 2007.
2. Financial Covenant Requirements
NSTAR and Boston Edison have no financial covenant requirements
under their respective long-term debt arrangements. ComElectric,
Cambridge Electric and NSTAR Gas have financial covenant
requirements under their long-term debt arrangements and were in
compliance at December 31, 2002 and 2001. NSTAR's long-term debt
other than the Mortgage Bonds of NSTAR Gas is unsecured.
The Transition Property Securitization Certificates held by
Boston Edison's subsidiary, BEC Funding, LLC, is collaterized
with a securitized regulatory asset with a balance of $493.6
million as of December 31, 2002. Boston Edison, as servicing
agent for BEC Funding, collected $105.7 million in 2002. These
collected funds are remitted daily to the trustee of BEC Funding.
These Certificates are non-recourse to Boston Edison.
NSTAR had a $450 million revolving credit agreement with a group
of banks effective through November 2002. NSTAR lowered this
credit facility to $350 million that consists of a three year,
$175 million revolving credit agreement that expires on November
14, 2005 and a 364-day, $175 million agreement that expires on
November 14, 2003. At December 31, 2002 and 2001, there were no
amounts outstanding under these revolving credit agreements.
These arrangements serve as backup to NSTAR's $350 million
commercial paper program that, at December 31, 2002 and 2001, had
$63.5 million and $315.5 million outstanding, respectively. In
October 2002, following receipt of the proceeds of Boston
Edison's $500 million debt issue previously referenced, NSTAR
used the entire proceeds to pay down on its total consolidated
debt. Under the terms of this credit agreement, NSTAR is
required to maintain a maximum total consolidated debt to total
capitalization ratio of not greater than 65% at all times,
excluding Transition Property Securitization Certificates and
excluding Accumulated Other Comprehensive Income from Common
equity, and to maintain a ratio of consolidated earnings before
interest and taxes to consolidated total interest expense of not
less than 2 to 1 for each period of four consecutive fiscal
quarters. Commitment fees must be paid on the total agreement
amount. At December 31, 2002 and 2001, NSTAR was in full
compliance with all of the aforementioned covenants.
Boston Edison had approval from the FERC to issue up to $350
million of short-term debt until December 31, 2002. On May 31,
2002, Boston Edison received FERC authorization to issue short-
term debt securities from time to time on or before December 31,
2004, with maturity dates no later than December 31, 2005, in
amounts such that the aggregate principal does not exceed $350
million at any one time. Boston Edison had a $300 million
revolving credit agreement with a group of banks effective
through December 2002. Boston Edison replaced this credit
facility with a 364-day, $350 million revolving credit agreement
that expires on November 14, 2003. At December 31, 2002 and
2001, there were no amounts outstanding under these revolving
credit agreements. These arrangements serve as backup to Boston
Edison's $350 million commercial paper program that had no
outstanding balance at December 31, 2002 and had an outstanding
balance of $191.5 million at December 31, 2001. In October 2002,
following receipt of the proceeds of its $500 million debt issue
previously referenced, its short-term debt balance was reduced to
zero. Under the terms of this agreement, Boston Edison is
required to maintain a maximum total consolidated debt to total
capitalization of not greater than 60% at all times, excluding
Transition Property Securitization Certificates and excluding
Accumulated Other Comprehensive Income from Common equity.
Commitment fees must be paid on the total agreement amount. At
December 31, 2002 and 2001, Boston Edison was in full compliance
with all of the aforementioned covenants.
On September 16, 2002, Boston Edison retired the $60 million
8.25% Series Debentures, due 2022. A $2.3 million redemption
premium was paid; this transaction had minimal impact on
earnings.
In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $170 million available under several lines of
credit and had $135.1 million and $117.8 million outstanding
under these lines of credit at December 31, 2002 and 2001,
respectively. ComElectric had approval from FERC to issue short-
term debt in an amount not exceeding $100 million until November
29, 2002. On May 31, 2002, ComElectric and Cambridge Electric
received FERC authorization to issue short-term debt securities
from time to time on or before November 30, 2004 and June 27,
2004, with maturity dates no later than November 29, 2005 and
June 26, 2005, respectively, in amounts such that the aggregate
principal does not exceed $125 million and $60 million,
respectively, at any one time. NSTAR Gas is not required to seek
approval from FERC to issue short-term debt.
Interest rates on the outstanding borrowings generally are money
market rates and averaged 1.89% and 4.13% in 2002 and 2001,
respectively. In aggregate, notes payable to banks discussed
above totaled $198.6 million and $624.8 million at December 31,
2002 and 2001, respectively.
Note K. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the
fair value of each class of securities for which it is
practicable to estimate the value:
1. Cash and Cash Equivalents
The carrying amounts of $53.4 million and $11.7 million for 2002
and 2001, respectively, approximate fair value due to the short-
term nature of these securities.
2. Indebtedness (Excluding Notes Payable)
The fair values of long-term indebtedness are based upon the
quoted market prices of similar issues. Carrying amounts and fair
values as of December 31, 2002 and 2001 were as follows:
2002 2001
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Long-term indebtedness
(including current maturities) $2,304,101 $2,422,440 $1,970,451 $2,076,190
Note L. Segment and Related Information
For the purpose of providing segment information, NSTAR's
principal operating segments, or its traditional core businesses,
are the electric and natural gas utilities that provide energy
delivery services in 107 cities and towns in Massachusetts.
NSTAR subsidiaries also supply electricity at wholesale to
municipalities.
The unregulated operating segment engages in business activities
that include district energy operations, telecommunications and a
liquefied natural gas service. Amounts shown on the following
table for 2002, 2001 and 2000 include the allocation of NSTAR's
(parent company) results of operations and assets, net of inter-
company transactions, and primarily consist of interest charges
and investment assets, respectively, to these business segments.
The allocation of parent company charges is based on an indirect
allocation of the parent company's investment relating to these
various business segments.
In addition, the unregulated net loss for 2002, 2001 and 2000
reflects reductions in the carrying value of NSTAR's investment
and its ultimate discontinuance of certain chilled water
operations in the amount of $1 million, $4.9 million and $3.5
million, respectively. During 2000, NSTAR notified certain
chilled water customers of its decision to exit a portion of that
business and that service ceased effective September 30, 2002, in
accordance with its contractual obligations. As part of the 2001
charge, NSTAR's carrying value of this investment has been
written-off entirely. In addition, in 2002 and 2001, NSTAR had
reserved for the removal costs of those assets. The net loss for
2002 and 2001 for the unregulated operations segment also
includes the impact of non-cash, after-tax charges of $17.7
million and $173.9 million, respectively, or $0.33 and $3.28 per
share, related to the write-down of NSTAR's investment in RCN
Corporation.
Excluding the impact of transactions related to NSTAR's
investment in RCN, NSTAR's chilled water operations and the
negative effect of the allocation of parent company losses, the
unregulated operations segment would otherwise reflect a minimal
level of net income for the periods shown.
(in thousands) 2002 2001 2000
Operating revenues
Electric utility operations $2,318,044 $2,668,509 $2,204,332
Gas utility operations 300,335 397,990 378,626
Unregulated operations 100,688 125,337 109,804
Consolidated total $2,719,067 $3,191,836 $2,692,762
========== ========== ==========
Depreciation and amortization
Electric utility operations $ 210,067 $ 197,233 $ 202,209
Gas utility operations 17,643 16,588 15,573
Unregulated operations 11,523 17,128 20,826
Consolidated total $ 239,233 $ 230,949 $ 238,608
========== ========== ==========
Operating income tax expense
(benefit)
Electric utility operations $95,354 $ 106,349 $ 112,310
Gas utility operations 10,283 14,031 15,514
Unregulated operations 1,476 (6,968) (10,404)
Consolidated total $ 107,113 $ 113,412 $ 117,420
========== ========== ==========
Equity income (loss) in
investments accounted for by the
equity method (a)
Electric utility operations $ 2,667 $ 2,258 $ 4,241
Unregulated operations - - (5,467)
Consolidated total $ 2,667 $ 2,258 $ (1,226)
========== ========== ==========
Interest charges
Electric utility operations $ 149,733 $ 133,019 $ 156,205
Gas utility operations 14,782 14,505 13,257
Unregulated operations 12,108 31,064 35,931
Consolidated total $ 176,623 $ 178,588 $ 205,393
========== ========== ==========
Segment net income (loss)
Electric utility operations $ 158,129 $ 169,642 $ 176,112
Gas utility operations 15,298 21,225 22,950
Unregulated operations (9,760) (187,666) (18,100)
Consolidated total $ 163,667 $ 3,201 $ 180,962
========== ========== ==========
Equity Investments
Electric utility operations $ 19,845 $ 22,560 $ 25,791
========== ========== ==========
Expenditures for property
Electric utility operations $ 305,153 $ 181,463 $ 142,997
Gas utility operations 28,238 26,900 19,500
Unregulated operations 34,693 21,504 21,809
Consolidated total $ 368,084 $ 229,867 $ 184,306
========== ========== ==========
Segment assets
Electric utility operations $5,285,143 $4,509,982 $4,557,948
Gas utility operations 620,956 517,659 541,406
Unregulated operations 217,176 300,550 448,361
Consolidated total $6,123,275 $5,328,191 $5,547,715
========== ========== ==========
(a) The equity income (loss) from equity investments is included
in other income, net on the accompanying Consolidated Statements
of Income.
Note M. Long-Term Contracts for the Purchase of Energy
1. NSTAR Electric Power Purchase Agreements
NSTAR Electric expects to continue to make periodic market
solicitations for default service and standard offer power supply
consistent with provisions of the Massachusetts Electric
Restructuring Act of 1997 (Restructuring Act) and MDTE orders.
NSTAR Electric has existing long-term power purchase agreements
that are expected to supply approximately 80%-85% of its standard
offer service obligation for 2003. NSTAR Electric has contracted
with a third party supplier to provide 100% of its standard offer
supply obligation through December 31, 2003. In connection with
this arrangement, NSTAR Electric has assigned its long-term power
purchase agreements to this supplier through December 31, 2003.
NSTAR Electric is recovering its payments to suppliers through
MDTE approved rates billed to customers. NSTAR Electric's
existing portfolio of long-term power purchase contracts supplied
the majority of its standard offer (including wholesale) energy
requirements in 2002. Also during 2002, NSTAR Electric entered
into an agreement whereby all of its energy supply resource
entitlements were transferred to an independent energy supplier,
following which NSTAR Electric repurchased its energy resource
needs from this independent energy supplier for NSTAR Electric's
ultimate sale to its standard offer customers.
Capacity costs of long-term contracts reflect NSTAR Electric's
proportionate share of capital and fixed operating costs of
certain generating units. In 2002, these costs were attributed
to 723.7 MW of capacity purchased. Energy costs are paid to
generators based on a price per kWh actually received into NSTAR
Electric's distribution system and are included in the total
cost. Total capacity purchased in 2002 was 1,705.1 MW.
Information related to long-term power contracts during 2002 was
as follows:
Proportionate share (in thousands)
Range of Capacity Charge
Contract Units of 2002 2002 Obligation
Fuel Type of Expireation Capacity Capacity Total Through Contact
Generating Unit Dates Purchased Cost Cost Expiration Date
% Range Total MW
Natural Gas 2008-2017 11.1-100 720.6 $147,647 $371,396 $1,596,784
Nuclear 2004-2012 2.3-71.2 532.0 13,794 177,10 50,364
Refuse 2015 100 76.9 8,084 55,921 -
Hydro 2014-2023 100 25.6 - 8,518 -
Oil 2002-2019 50-100 350.0 17,572 53,246 49,423
Total 1,705.1 $187,097 $666,185 $1,696,571
======= ======== ======== ==========
NSTAR Electric has entered into a short-term power purchase
agreement to meet its entire default service supply obligation
for the period January 1, 2003 through June 30, 2003 and for 50%
of its obligation for the second-half of 2003. A Request for
Proposals will be issued in the second quarter of 2003 for the
remainder of the obligation. NSTAR Electric entered into
agreements ranging in length from five to twelve-months effective
January 1, 2002 through December 31, 2002 with suppliers to
provide full default service energy and ancillary service
requirements at contract rates approved by the MDTE.
NSTAR Electric's total capacity and/or energy costs associated
with these contracts in 2002, 2001 and 2000 were approximately
$666 million, $678 million and $720 million, respectively.
NSTAR Electric's capacity charge obligation under these contracts
for the years after 2002 are as follows:
Capacity
Charge
(in thousands) Obligation
2003 $ 149,290
2004 155,863
2005 158,500
2006 160,294
2007 162,014
Years thereafter 910,610
$1,696,571
==========
2. NSTAR Gas Supply and Storage Agreements
NSTAR Gas maintains a flexible resource portfolio consisting of
gas supply contracts, transportation contracts on interstate
pipelines, market area storage and peaking services. In order to
control costs and to efficiently manage the gas supply needs of
its customers, NSTAR Gas optimizes its supply mix to ensure
maximum resource utilization. NSTAR Gas purchases
transportation, storage and balancing services from Tennessee Gas
Pipeline Company and Algonquin Gas Transmission Company, as well
as other upstream pipelines that bring gas from major producing
regions in the U.S., Gulf of Mexico and Canada to the final
delivery points in the NSTAR Gas service area. NSTAR Gas
purchases all of its gas supplies from third-party vendors,
primarily under firm contracts with terms of less than one year.
The vendors vary from small independent marketers to major gas
and oil producers.
NSTAR Gas also utilizes contracts for underground storage and
liquefied natural gas (LNG) facilities to meet its winter peaking
demands. The underground storage contracts are a combination of
existing and new agreements that are the result of FERC Order 636
service unbundling. During the summer injection season, excess
pipeline capacity is used to deliver and store gas in market area
storage facilities, located in the New York and Pennsylvania
region. Stored gas is withdrawn during the winter season to
supplement pipeline supplies in order to meet firm heating
demand. NSTAR Gas has firm storage capacity entitlements of over
7.5 billion cubic feet.
NSTAR Gas has various contractual agreements covering the
transportation of natural gas, underground and liquefied natural
gas storage facilities, which are recoverable from customers
under the MDTE approved Cost of Gas Adjustment Clause of NSTAR
Gas. These contracts expire at various times from 2003 to 2013.
NSTAR Gas' firm contract demand charges associated with firm
pipeline transportation and storage capacity contracts in 2002,
2001 and 2000 were approximately $51.8 million, $51.8 million and
$54.3 million, respectively. NSTAR Gas' firm contract demand
charges at current rates under these contracts for the years
after 2002 are as follows:
Firm Contract
(in thousands) Demand Charges
2003 $ 50,345
2004 49,634
2005 49,098
2006 45,969
2007 35,451
Years thereafter 154,283
$ 384,780
==========
Note N. Other Utility Matters
Service Quality Index
On October 29, 2001, and as subsequently updated, NSTAR Electric
and NSTAR Gas filed proposed service quality plans for each
company with the MDTE. The service quality plans established
performance benchmarks effective January 1, 2002 for certain
identified measures of service quality relating to customer
service and billing performance, customer satisfaction, and
reliability and safety performance. The companies are required
to report annually concerning their performance as to each
measure and are subject to maximum penalties of up to two percent
of transmission and distribution revenues should performance fail
to meet the applicable benchmarks. Concurrently, NSTAR Electric
and NSTAR Gas filed with the MDTE a report of their performance
on the identified service quality measures for the two twelve-
month periods ended August 31, 2000 and 2001. This report
included a calculation of penalties in accordance with MDTE
guidelines. On March 22, 2002, following hearings on the matter,
the MDTE issued an order imposing a service quality penalty of
approximately $3.25 million on NSTAR Electric that was refunded
to customers as a credit to their bills during the month of May
2002. This refund had no material effect on NSTAR's consolidated
financial position, cash flows or results of operations in 2002.
For the four-month period ended December 31, 2001, the MDTE
determined that NSTAR's performance relative to service quality
measures did not warrant a penalty assessment.
On February 28, 2003, NSTAR Electric and NSTAR Gas filed their
2002 Service Quality Reports with the MDTE that reflected
significant improvements in reliability and performance and
indicate that no penalty will be assessed for this period. NSTAR
accounts for its service quality penalties pursuant to SFAS No.
5, "Accounting for Contingencies." Accordingly, these penalties
are monitored on a monthly basis to determine NSTAR's contingent
liability, and if NSTAR determines it is probable that a
liability has been incurred and is estimable, NSTAR would then
accrue an appropriate liability. Annually, each NSTAR utility
subsidiary makes a service quality performance filing with the
MDTE. Any settlement or rate order that would result in a
different liability (or credit) level from what has been accrued
would be adjusted in the period an agreement is reached with the
MDTE.
Generating Assets Divestiture
a. Seabrook Nuclear Power Station
On November 1, 2002, FPL Group, Inc. purchased 88% of the
majority ownership interest in the Seabrook Nuclear Power
Station, including Canal's 3.52% ownership interest, for $799.4
million, net of closing adjustments. FPL Group assumed
responsibility for the ultimate decommissioning of the facility
and received the Seabrook decommissioning funds of approximately
$226.9 million at the closing. Canal's portion of the sale
proceeds amounted to $31.9 million, of which $3.5 million was
paid into the decommissioning trust as a final top-off and $1.3
million was used for other transaction costs. The net proceeds
of $27.1 million were less than Canal's remaining investment in
Seabrook. The difference of approximately $16.7 million will be
included as a component of Cambridge Electric's and ComElectric's
transition cost recovery and is expected to be collected from
ComElectric's and Cambridge Electric's customers in 2003 through
the transition charge. As part of this sale, all purchased power
agreements were terminated. The Seabrook sale did not have an
impact on NSTAR's current results of operations. The future
impact of the sale will not have a material effect on results of
operations, cash flow or financial position.
b. Blackstone Station
On August 1, 2002, Cambridge Electric reached a tentative
agreement to sell Blackstone Station to Harvard University
(Harvard) for $14.6 million that will be used to reduce Cambridge
Electric's transition charge. At the same time, NSTAR Steam
signed an agreement with Harvard to sell its Blackstone steam
assets and contracts to Harvard for $3 million. The sale is
subject to the approval of the MDTE. A filing with the MDTE for
regulatory approval for this transaction was made on November 21,
2002. Under terms of this agreement, NSTAR Steam will continue
to manage the day-to-day operations of the steam plant on this
site for one year after the sale. Cambridge Electric is
divesting its electric generating assets consistent with the
provisions of the Restructuring Act. Cambridge Electric divested
the majority of its non-nuclear generating facilities in 1998.
NSTAR anticipates completing the Blackstone Station sale in the
second quarter of 2003.
Note O. Commitments and Contingencies
1. Contractual Commitments
NSTAR also has leases for facilities and equipment. The
estimated minimum rental commitments under non-cancellable
capital and operating leases for the years after 2002 are as
follows:
(in thousands)
2003 $ 21,854
2004 20,085
2005 16,767
2006 14,191
2007 11,433
Years thereafter 45,633
Total $129,963
========
The total expense for both lease rentals and transmission
agreements was $86.6 million in 2002, $82.7 million in 2001 and
$67.7 million in 2000, net of capitalized expenses of $2.3
million in 2002, $2.9 million in 2001 and $2.3 million in 2000.
Total rent expense for all operating leases, except those with
terms of a month or less, amounted to $7.4 million in 2002, $8.3
million in 2001 and $8.7 million in 2000.
NSTAR Electric has entered into a short-term power purchase
agreement to meet its entire default service supply obligation
for the period January 1, 2003 through June 30, 2003 and for 50%
of its obligation for the second-half of 2003. A Request for
Proposals will be issued in the second quarter of 2003 for the
remainder of the obligation. NSTAR Electric entered into
agreements ranging in length from five to twelve-months effective
January 1, 2002 through December 31, 2002 with suppliers to
provide full default service energy and ancillary service
requirements at contract rates approved by the MDTE. NSTAR
Electric is completely recovering all of the payments it is
making to suppliers and has financial and performance assurances
and financial guarantees in place with those suppliers to protect
NSTAR Electric from risk in the unlikely event any of its
suppliers encounter financial difficulties or fail to maintain an
investment grade credit rating. In connection with certain of
these agreements, should, in the unlikely event, an individual
NSTAR Electric distribution company receive a credit rating below
investment grade, that company potentially could be required to
obtain certain financial commitments, including but not limited
to, letters of credit. Refer to Note M, "Long-Term Contracts for
the Purchase of Energy" for a further discussion.
2. Electric Equity Investments and Joint Ownership Interest
NSTAR Electric has an equity investment of approximately 14.5% in
two companies that own and operate transmission facilities to
import electricity from the Hydro-Quebec system in Canada. As an
equity participant, NSTAR Electric is required to guarantee, in
addition to each companies' own share, the obligations of those
participants who do not meet certain credit criteria. At
December 31, 2002, NSTAR Electric's portion of these guarantees
amounted to $13 million. New England Hydro-Transmission Electric
Company, Inc. (NEH) and New England Hydro-Transmission
Corporation (NHH) have agreed to use their best efforts to limit
their equity investment to 40% of their total capital during the
time NEH and NHH have outstanding debt in their capital
structure. In order to meet its best efforts obligation pursuant
to the Equity Funding Agreement dated June 1, 1985, as amended,
for NEH and NHH, in 2002, NEH repurchased a total of 325,000 of
its outstanding shares from all equity holders and NHH
repurchased a total of 1,725 outstanding shares from all equity
holders. Through December 31, 2002, NSTAR Electric's reduction
of its equity ownership resulting from NEH buy-back of 47,018
shares and NHH buy-back of 250 shares was approximately
$1,139,000.
Canal had owned a 3.52% joint ownership interest in the Seabrook
Nuclear Power Station (Seabrook) until November 1, 2002. On this
date, FPL Group, Inc. closed on its purchase of an 88% majority
ownership interest in Seabrook, including Canal's 3.52% interest
for $799.4 million, net of closing adjustments. Among other
things, FPL Group, Inc. assumed responsibility for the ultimate
decommissioning of the Seabrook facility and received the
decommissioning funds of approximately $226.9 million. Canal's
portion of the proceeds amounted to $31.9 million, less the $3.5
million paid into the decommissioning trust as a final top-off
and $1.3 million for other transaction costs. The net proceeds
of $27.1 million were less than Canal's remaining investment in
Seabrook. The net result of this transaction will be included as
a component of Cambridge Electric's and ComElectric's transition
cost recovery of approximately $16.7 million and is expected to
be collected from Cambridge Electric's and ComElectric's
customers in 2003 through the transition charge. As part of this
sale, all purchased power agreements were terminated. This
transaction did not have an impact on NSTAR's current results of
operations. The future impact of this transaction will not have
a material effect on operations.
Cambridge Electric had a 2.65% interest in the Vermont Yankee
nuclear power plant. On July 31, 2002, Vermont Yankee was sold
for approximately $180 million to Entergy Nuclear Vermont Yankee,
LLC (Entergy). The sale agreement provided, among other items,
that Entergy assume responsibility for the ultimate
decommissioning of the facility and received the Vermont Yankee
decommissioning funds. Pursuant to the terms of an Additional
Power Contract, Cambridge Electric is obligated to purchase its
2.5% entitlement percentage of the output of the plant through
the current license term ending in March 2012. The plant's
owners, before the sale, were a consortium of New England
utilities, including Cambridge Electric. This transaction did
not have an impact on NSTAR's results of operations. The net
result of this transaction was included as a component of
Cambridge Electric's transition cost recovery and is reflected on
the accompanying Consolidated Balance Sheets as a Regulatory
asset.
NSTAR Electric collectively has an equity ownership of 14% in
Connecticut Yankee Atomic Power Company (CYAPC), 14% in Yankee
Atomic Electric Company (YAEC), and 4% in Maine Yankee Atomic
Power Company, (the "Yankee Companies"). Periodically, NSTAR
obtains estimates from the management of the Yankee Companies on
the cost of decommissioning the Connecticut Yankee nuclear unit
(CY), the Yankee Atomic nuclear unit (YA), and the Maine Yankee
nuclear unit (MY). These nuclear units are completely shut down
and are currently conducting decommissioning activities.
Based on estimates from the Yankee Companies' management as of
December 31, 2002, the total remaining cost for decommissioning
each nuclear unit is approximately as follows: $248 million for
CY, $225 million for YA and $166 million for MY. Of these
amounts, NSTAR Electric is obligated to pay $34.7 million towards
the decommissioning of CY, $31.5 million toward YA, and $6.6
million toward MY. These estimates are recorded in the
accompanying Consolidated Balance Sheets as Power contract
liabilities with a corresponding regulatory asset. These
estimates may be revised from time to time based on information
available to the Yankee Companies regarding future costs.
NSTAR expects the Yankee Companies to seek recovery of these
costs and any additional increases to these costs in rate
applications with the FERC, with any resulting adjustments being
charged to their respective sponsors, including NSTAR Electric.
NSTAR Electric would recover its share of any allowed increases
from customers through its own filings with the MDTE.
The various decommissioning trusts for which NSTAR or its
subsidiaries are responsible through their equity ownership are
established pursuant to the Code of Federal Regulations, Title 18
- - Conservation of Power and Water Resources. The investment of
decommissioning funds that have been established, are managed in
accordance with these federal guidelines, state jurisdictions and
with the applicable Internal Revenue Service requirements. Some
of the requirements state that these investments be managed
independently by a prudent fund manager and that funds are to be
invested in conservative, minimum risk investment securities.
Any gains or losses are anticipated to be refunded to or
collected from customers, respectively.
3. Financial and Performance Guarantees
On a limited basis, NSTAR and certain of its subsidiaries may
enter into agreements providing financial assurance to third
parties. Such agreements include letters of credit, surety
bonds, and other guarantees.
At December 31, 2002, outstanding guarantees totaled $34.2
million as follows:
(in thousands)
Letters of Credit $ 5,527
Surety Bonds 15,709
Other Guarantees 13,000
Total Guarantees $ 34,236
========
The $5.5 million letter of credit is for the benefit of a third
party, as trustee in connection with the 6.924% Notes of one of
its subsidiaries. The letter of credit is available if its
subsidiary has insufficient funds to pay the debt service
requirements. As of December 31, 2002, there have been no
amounts drawn under this letter of credit.
At December 31, 2002, certain of NSTAR's subsidiaries have
purchased a total of $1 million of performance surety bonds for
the purpose of obtaining licenses, permits and rights-of-way in
various municipalities. In addition, NSTAR has purchased
approximately $14.7 million in worker's compensation self-insurer
bonds. These bonds support the guarantee by NSTAR to the
Commonwealth of Massachusetts required as part of NSTAR's
worker's compensation self-insurance program.
NSTAR and its subsidiaries have also issued $13 million of
residual value guarantees related to its equity interest in the
Hydro-Quebec transmission companies.
Management believes the likelihood NSTAR would be required to
perform or otherwise incur any significant losses associated with
any of these guarantees is remote.
4. Environmental Matters
As of December 31, 2002, NSTAR's subsidiaries were involved in 21
state-regulated properties ("Massachusetts Contingency Plan, or
"MCP" sites") where oil or other hazardous materials were
previously spilled or released. On February 4, 2003, NSTAR
closed-out one of these sites and filed the required information
with the Massachusetts Department of Environmental Protection.
The NSTAR subsidiaries are required to clean up or otherwise
remediate these properties in accordance with specific state
regulations. There are uncertainties associated with the
remediation costs due to the final selection of the specific
cleanup technology and the particular characteristics of the
different sites. In addition to the MCP sites, NSTAR
subsidiaries also face possible liability as a result of
involvement in multi-party disposal sites or third party claims
associated with contamination remediation. NSTAR generally
expects to have only a small percentage of the total potential
liability for these sites. Estimates of approximately $4.2
million and $5.8 million are included as liabilities in the
accompanying Consolidated Balance Sheets at December 31, 2002 and
2001, respectively, and are the total amount of NSTAR's estimated
environmental clean-up obligations. Accordingly, this amount has
not been reduced by any potential rate recovery treatment of
these costs or any potential recovery from NSTAR's insurance
carriers. Prospectively, should NSTAR be allowed regulatory rate
recovery of these specific costs, it would record an offsetting
regulatory asset and record a credit to operating expenses equal
to previously expensed costs. Based on its assessments of the
specific site circumstances, management does not believe that it
is probable that any such additional costs will have a material
impact on NSTAR's consolidated financial position.
NSTAR Gas is participating in the assessment of six 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 NSTAR Gas may be responsible for
remedial action. The MDTE has approved recovery of costs
associated with MGP sites over a 7-year period, without carrying
costs. As of December 31, 2002 and 2001, NSTAR Gas has recorded
a liability of $4.8 million and $6.7 million, respectively, as an
estimate for site cleanup costs for several MGP sites for which
NSTAR Gas was previously cited as a potentially responsible
party. A corresponding regulatory asset has been recorded that
reflects the future rate recovery for these costs.
Estimates related to environmental remediation costs are reviewed
and adjusted periodically as further investigation and assignment
of responsibility occurs and as either additional sites are
identified or NSTAR's responsibilities for such sites evolve or
are resolved. NSTAR's ultimate liability for future
environmental remediation costs may vary from these estimates.
Although, 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
consolidated financial position or results of operations for a
reporting period.
5. Regulatory and Legal Proceedings
a. Regulatory proceedings
In December 2002, NSTAR Electric filed proposed transition rate
adjustments for 2003, including a preliminary reconciliation of
transition, transmission, standard offer and default service
costs and revenues through 2002. The MDTE subsequently approved
tariffs for each retail electric subsidiary effective January 1,
2003. The filings were updated in February 2003 to include final
costs and revenues for 2002.
On November 14, 2002, Boston Edison and the AG received approval
of a Settlement Agreement from the MDTE resolving issues in
Boston Edison's reconciliation of costs and revenues for the year
2001. Among other issues, the Settlement Agreement includes an
adjustment relating to the reconciliation of costs relating to
securitization and efforts to mitigate costs incurred in relation
to a purchased power agreement with Hydro Quebec. As a result of
this Settlement Agreement with the AG, Boston Edison recognized
approximately $11.4 million in additional transition charge
revenues in 2002. This benefit was significantly offset by
several other regulatory true-up adjustments.
In December 2001, NSTAR Electric filed proposed transition rate
adjustments for 2002, including a preliminary reconciliation of
costs and revenues through 2001. The MDTE subsequently approved
tariffs for each retail electric subsidiary effective January 1,
2002. The filings were updated in February 2002 to include final
costs for 2001. The MDTE approved the reconciliation of costs
and revenues for Boston Edison through 2000 in its approval on
November 16, 2001 of a Settlement Agreement between Boston Edison
and the AG resolving all outstanding issues in Boston Edison's
prior reconciliation filings. As a part of this settlement,
Boston Edison agreed to reduce the costs sought to be collected
through the transition charge by approximately $2.9 million as
compared to the amounts that were originally sought. This
settlement did not have a material adverse effect on NSTAR's
consolidated financial position, results of operations or cash
flows.
On June 1, 2001, the MDTE issued its final orders on the
reconciliation of ComElectric and Cambridge Electric's
transition, standard offer service, default service and
transmission costs and revenues for 1998. ComElectric and
Cambridge Electric reached a settlement with the AG regarding the
1999 and 2000 reconciliation proceedings. Under this settlement,
the companies' future recovery of transition costs would be
reduced by approximately $7.8 million. This settlement was
approved by the MDTE on June 5, 2002 and did not have a material
adverse effect on NSTAR's 2002 consolidated financial position,
cash flows or results of operations.
b. Merger Rate Plan
On December 16, 2002, the Massachusetts Supreme Judicial Court
(SJC) affirmed the MDTE's 1999 decision to allow for the merger
of BEC and COM/Energy as originally structured. The SJC decision
finalized the resolution of all issues relating to this appeal
and did not have any impact on NSTAR's 2002 or prior periods'
consolidated financial position, cash flows or results of
operations. The 1999 MDTE order, which approved the rate plan
associated with the merger, was appealed to the SJC by the
Massachusetts Attorney General (AG) and a separate group that
consisted of The Energy Consortium (TEC) and Harvard University
(Harvard). The AG, TEC and Harvard alleged that, in approving
the rate plan and merger proposal, the MDTE committed errors of
law in the following areas: (1) in adopting a public interest
standard, the MDTE applied the wrong standard of review, and
failed to investigate the propriety of rates and to determine
that the resulting rates of Boston Edison, Cambridge Electric,
ComElectric and NSTAR Gas were just and reasonable; (2) that in
permitting Cambridge Electric and ComElectric to adjust their
rates by $49.8 million to reflect demand-side management costs,
the MDTE failed to determine whether such an adjustment was
warranted in light of other cost decreases; (3) that the MDTE's
approval results in an arbitrary and unjustified sharing of
benefits and costs between ratepayers and shareholders; and (4)
that the MDTE's approval of the rate plan guarantees shareholders
recovery of future costs without any future demonstration of
customer savings. The AG's brief included similar arguments in
each of these areas and added that, in allowing recovery of the
acquisition premium, the MDTE improperly deviated from a cost
basis in setting approved rates and the ratemaking policies in
other jurisdictions.
c. Other Legal Matters
In the normal course of its business, NSTAR and its subsidiaries
are involved in certain legal matters, including civil lawsuits.
Management is unable to fully determine a range of reasonably
possible court-ordered damages, settlement amounts, and related
litigation costs ("legal liabilities") that would be in excess of
amounts accrued. Based on the information currently available,
NSTAR does not believe that it is probable that any such
additional legal liability will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal liabilities that may result from
changes in estimates could have a material impact on its results
of operations for a reporting period.
Report of Independent Accountants
To the Shareholders and Trustees of NSTAR:
In our opinion, the consolidated financial statements listed in
the index appearing under Item 15(a)(1) on page 95, present
fairly, in all material respects, the financial position of NSTAR
and its subsidiaries at December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 2002 in conformity
with accounting principles generally accepted in the United
States of America. In addition, in our opinion, the financial
statement schedule listed in the index appearing under Item
15(a)(2) on page 95, presents fairly, in all material respects,
the information set forth therein when read in conjunction with
the related consolidated financial statements. These financial
statements and the financial statement schedule are the
responsibility of NSTAR's management; our responsibility is to
express an opinion on these financial statements and the
financial statement schedule based on our audits. We conducted
our audits of these statements in accordance with auditing
standards generally accepted in the United States of America,
which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating
the overall financial statement presentation. We believe that
our audits provide a reasonable basis for our opinion.
PricewaterhouseCoopers LLP
/s/ PRICEWATERHOUSECOOPERS LLP
Boston, Massachusetts
January 22, 2003
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
No event that would be described in response to this Item 9 has
occurred with respect to NSTAR or its subsidiaries.
Part III
Item 10. Trustees and Executive Officers of the Registrant
(a) Identification of Trustees
Information required by this item is incorporated herein by
reference to the 2003 Proxy Statement dated March 27, 2003.
Pages 3-5
(b) Identification of Officers
Information required by this item is included in Item 4A.
Item 11. Executive Compensation
Information required by this item is incorporated herein by
reference to the 2003 Proxy Statement dated March 27, 2003.
Pages 9-15
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Information required by this item is incorporated herein by
reference to the 2003 Proxy Statement dated March 27, 2003.
Pages 1, 6 and 7
Equity Compensation Plan Information
The following table provides information about NSTAR's equity
compensation plans as of December 31, 2002.
Number of
Number of securities
securities to remaining
be issued upon Weighted-average available for
exercise of exercise price future issuance
outstanding of outstanding under equity
Plan Category options options compensation plans
Equity
compensation
plans approved
by shareholders 1,046,869 $40.14 2,274,814
Equity
compensation plans
not approved by - - -
shareholders
Total 1,046,869 $40.14 2,274,814
========= ====== =========
Item 13. Certain Relationships and Related Transactions
Information required by this item is not applicable to NSTAR.
Part IV
Item 14. Controls and Procedures
NSTAR's disclosure controls and procedures are designed to ensure
that information required to be disclosed in reports that it
files or submits under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time
periods specified in the rules and forms of the Securities and
Exchange Commission.
Within 90 days prior to the date of filing this Annual Report on
Form 10-K, NSTAR carried out an evaluation, under the supervision
and with the participation of NSTAR's management, including
NSTAR's Chief Executive Officer and Chief Financial Officer, of
the effectiveness of the design and operation of NSTAR's
disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based on that evaluation, the Chief Executive Officer
and the Chief Financial Officer concluded that NSTAR's disclosure
controls and procedures are effective in order to timely alert
them to material information required to be disclosed by NSTAR in
the reports that it files or submits under the Securities
Exchange Act of 1934.
Subsequent to the date of that evaluation, there have been no
significant changes in NSTAR's internal controls or in other
factors that could significantly affect internal controls, nor
were any corrective actions required with regard to significant
deficiencies and material weaknesses.
Item 15. Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements:
Page
Consolidated Statements of Income for the years ended
December 31, 2002, 2001 and 2000 51
Consolidated Statements of Comprehensive Income for the
years ended December 31, 2002, 2001 and 2000 52
Consolidated Statements of Retained Earnings for the
years ended December 31, 2002, 2001 and 2000 52
Consolidated Balance Sheets as of December 31, 2002 and
2001 53
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000 54
Notes to Consolidated Financial Statements 55-91
Selected Consolidated Quarterly Financial Data
(Unaudited) 15
Report of Independent Accountants 92
2. Financial Statement Schedules:
Schedule II - Valuation and Qualifying accounts for the
years ended December 31, 2002, 2001 and 2000 101
3. Exhibits:
Refer to the exhibits listing beginning below.
(b) Reports on Form 8-K:
A report on Form 8-K was filed on November 27, 2002 that reported
on revised decommissioning costs of certain nuclear units in
which NSTAR has an equity ownership interest.
A report on Form 8-K was filed on December 17, 2002 that reported
on the Massachusetts Supreme Judicial Court affirming a 1999 MDTE
order associated with the merger of BEC Energy and Commonwealth
Energy System that created NSTAR.
A report on Form 8-K was filed on January 3, 2003 following the
MDTE approval received on December 20, 2002 to allow NSTAR to
defer as a regulatory asset, an additional minimum liability, and
the difference between the level of pension and postretirement
benefits that is included in rates and the amounts that would
have been recorded under SFAS 87 and SFAS 106 in 2003.
Incorporated by reference unless designated otherwise:
NSTAR (Registrant)
Exhibit 3 Articles of Incorporation and By-Laws
3.1 Declaration of Trust of NSTAR (incorporated by
reference to Annex D to the Joint Proxy
Statement/Prospectus, which forms part of the
Registration Statement on Form S-4 of NSTAR (No.
333-78285)).
3.2 Bylaws of NSTAR (Incorporated by reference to Annex
E to the Joint Proxy Statement/Prospectus, which
forms part of the Registration Statement on Form S-
4 of NSTAR (No. 333-78285)).
Exhibit 4 Instruments Defining the Rights of Security
Holders, Including Indentures
4.1 Indenture dated as of January 12, 2000 between
NSTAR and Bank One Trust Company N.A. (Incorporated
by reference, Exhibit 4.1 to NSTAR Registration
Statement on Form S-3, File No. 333-94735).
4.2 Votes of the Board of Trustees of NSTAR, dated
January 27, 2000, supplementing the Indenture dated
as of January 12, 2000 between NSTAR and Bank One
Trust Company N.A. (Filed herewith).
4.3 Votes of the Board of Trustees of NSTAR, dated
September 28, 2000 supplementing the Indenture
dated as of January 12, 2000 between NSTAR and Bank
One Trust Company N.A. (Filed herewith).
- -- Management agrees to furnish to the Securities and
Exchange Commission, upon request, a copy of any
other agreements or instruments of NSTAR and its
subsidiaries defining the rights of holders of any
long-term debt whose authorization does not exceed
10% of total assets.
Exhibit 10 Material Contracts
10.1 NSTAR Excess Benefit Plan, effective August 25,
1999 (NSTAR Form 10-K/A for the year ended December
31, 1999, File No. 1-14768).
10.2 NSTAR Supplemental Executive Retirement Plan,
effective August 25, 1999 (NSTAR Form 10-K/A for
the year ended December 31, 1999, File No. 1-14768).
10.3 Special Supplemental Executive Retirement Agreement
between Boston Edison Company and Thomas J. May
dated March 13, 1999, regarding Key Executive
Benefit Plan and Supplemental Executive Retirement
Plan (NSTAR Form 10-K/A for the year ended December
31, 1999, File No. 1-14768).
10.4 Key Executive Benefit Plan Agreement dated October
1, 1983 between Boston Edison Company and Thomas J.
May (NSTAR Form 10-K/A for the year ended December
31, 1999, File No. 1-14768).
10.5 Employment Agreement between Thomas J. May and
NSTAR dated May 11, 1999 (Incorporated by reference
to Annex A to the Joint Proxy Statement/Prospectus
in Part I of the Registration Statement of NSTAR on
Form S-4, File No. 333-78285).
10.6 Change in Control Agreement between NSTAR and
Thomas J. May dated May 11, 1999 (NSTAR Form 10-K/A
for the year ended December 31, 1999, File No. 1-14768).
10.7 NSTAR Deferred Compensation Plan (Restated
Effective August 25, 1999) (NSTAR Form 10-K/A for
the year ended December 31, 1999, File No. 1-14768).
10.8 NSTAR 1997 Share Incentive Plan, as amended January
24, 2002 and June 30, 1999 and assumed by NSTAR
effective August 28, 2000 (NSTAR Form 10-Q for the
quarter ended September 30, 2000, File No. 1-14768).
10.8.1 NSTAR 1997 Share Incentive Plan, as amended January
24, 2002 (Filed herewith).
10.9 Amended and Restated Change in Control Agreement
between James J. Judge and NSTAR, November 1, 2001.
(NSTAR Form 10-K for the year ended December 31,
2001, File No. 1-14768).
10.10 NSTAR Trustees' Deferred Plan (Restated Effective
August 25, 1999), dated October 20, 2000 (NSTAR
Form 10-Q for the quarter ended September 30, 2000,
File No. 1-14768).
10.11 Master Trust Agreement between NSTAR and State
Street Bank and Trust Company (Rabbi Trust), dated
August 25, 1999 (NSTAR Form 10-Q for the quarter
ended September 30, 2000, File No. 1-14768).
10.12 Amended and Restated Change in Control Agreement
between Douglas S. Horan and NSTAR dated November
1, 2001 (NSTAR Form 10-K for the year ended
December 31, 2001, File No. 1-14768).
10.13 Amended and Restated Change in Control Agreement
between Joseph R. Nolan, Jr. and NSTAR dated
November 1, 2001 (NSTAR Form 10-K for the year
ended December 31, 2001, File No. 1-14768).
10.14 Amended and Restated Change in Control Agreement
between Eugene J. Zimon and NSTAR dated November 1,
2001 (NSTAR Form 10-Q for the quarter ended
September 30, 2000, File No. 1-14768).
10.15 Amended and Restated Change in Control Agreement
between Werner J. Schweiger and NSTAR dated March
1, 2002 (NSTAR Form 10-K for the year ended
December 31, 2001, File No. 1-14768).
10.16 Amended and Restated Change in Control Agreement
between Timothy R. Manning and NSTAR dated April
29, 2002 (filed herewith).
Exhibit 21 Subsidiaries of the Registrant
21.1 (filed herewith).
Exhibit 23 Consent of Independent Accountants
23.1 (filed herewith).
Exhibit 99 Additional Exhibits
99.1 Certification Statement of Chief Executive Officer
of NSTAR pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002 (filed herewith).
99.2 Certification Statement of Chief Financial Officer
of NSTAR pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002 (filed herewith).
99.3 Annual Reports on Form 11-K for certain employee
savings plans for the years ended December 31,
2001, 2000 and 1999, as dated June 28, 2002, June
29, 2001 and June 23, 2000, respectively, File No.
1-14768.
BEC Energy and Subsidiaries
Exhibit 3 Articles of Incorporation and By-Laws
3.1 Boston Edison Restated Articles of Organization
(Form 10-Q for the quarter ended June 30, 1994,
File No. 1-2301).
3.2 Boston Edison Company Bylaws April 19, 1977, as
amended January 22, 1987, January 28, 1988, May 28,
1988, and November 22, 1989 (Form 10-Q for the
quarter ended June 30, 1990, File No. 1-2301).
Exhibit 4 Instruments Defining the Rights of Security
Holders, Including Indentures
4.1 Indenture between Boston Edison Company and The
Bank of New York (as successor to Bank of Montreal
Trust Company) (Form 10-Q for the quarter ended
September 30, 1988, File No. 1-2301).
4.11 Votes of the Pricing Committee of the Board of
Directors of Boston Edison Company taken March 5,
1993 re 6.80% Debentures due March 15, 2003 and
7.80% debentures due March 15, 2023 (Form 10-K for
the year ended December 31, 1992, File No. 1-2301).
4.12 Votes of the Pricing Committee of the Board of
Directors of Boston Edison Company taken May 10,
1995 re 7.80% debentures due May 15, 2010 (Form 10-
K for the year ended December 31, 1995, File No. 1-
2301).
4.13 Votes of the Board of Directors of Boston Edison
Company taken October 8, 2002 re $500 million
aggregate principal amount of unsecured debentures
($400 million, 4.875% due in 2012 and $100 million,
Floating rate due in 2005) (Form 8-K dated October
11, 2002, File No. 1-2301).
Exhibit 10 Material Contracts
10.11 Boston Edison Company and Entergy Nuclear
Generation Company Purchase and Sale Agreement
dated November 18, 1998 (Form 10-K for the year
ended December 31, 1999, File No. 1-2301).
10.12 Boston Edison Company Restructuring Settlement
Agreement dated July 1997 (Form 10-K for the year
ended December 31, 1997, File No. 1-2301).
Commonwealth Energy System
Exhibit 10 Power Contracts
10.2.1 New England Power Pool Agreement (NEPOOL) dated
September 1, 1971 as amended through August 1,
1977, between NEGEA Service Corporation, as agent
for CEL, CEC, NBGEL, and various other electric
utilities operating in New England together with
amendments dated August 15, 1978, January 31, 1979
and February 1, 1980. (Exhibit 5(c)13 to New
England Gas and Electric Association's Form S-16
(April 1980), File No. 2-64731).
10.2.1.1 Thirteenth Amendment to 10.2.1 as amended September
1, 1981 (Refiled as Exhibit 3 to the Parent's 1991
Form 10-K, File No. 1-7316).
10.2.1.2 Fourteenth through Twentieth Amendments to 10.2.1
as amended December 1, 1981, June 1, 1982, June 15,
1983, October 1, 1983, August 1, 1985, August 15,
1985 and September 1, 1985, respectively (Exhibit 4
to the CES Form 10-Q (September 1985), File No. 1-
7316).
10.2.1.3 Twenty-first Amendment to 10.2.1 as amended to
January 1, 1986 (Exhibit 1 to the CES Form 10-Q
(March 1986), File No. 1-7316).
10.2.1.4 Twenty-second Amendment to 10.2.1 as amended to
September 1, 1986 (Exhibit 1 to the CES Form 10-Q
(September 1986), File No. 1-7316).
10.2.1.5 Twenty-third Amendment to 10.2.1 as amended to
April 30, 1987 (Exhibit 1 to the CES Form 10-Q
(June 1987), File No. 1-7316).
10.2.1.6 Twenty-fourth Amendment to 10.2.1 as amended March
1, 1988 (Exhibit 1 to the CES Form 10-Q (March
1989), File No. 1-7316).
10.2.1.7 Twenty-fifth Amendment to 10.2.1. as amended to May
1, 1988 (Exhibit 1 to the CES Form 10-Q (March
1988), File No. 1-7316).
10.2.1.8 Twenty-sixth Agreement to 10.2.1 as amended March
15, 1989 (Exhibit 1 to the CES Form 10-Q (March
1989), File No. 1-7316).
10.2.1.9 Twenty-seventh Agreement to 10.2.1 as amended
October 1, 1990 (Exhibit 3 to the CES 1990 Form 10-
K, File No. 1-7316).
10.2.1.10 Twenty-eighth Agreement to 10.2.1 as amended
September 15, 1992 (Exhibit 1 to the CES Form 10-Q
(September 1994), File No. 1-7316).
10.2.1.11 Twenty-ninth Agreement to 10.2.1 as amended May 1,
1993 (Exhibit 2 to the CES Form 10-Q (September
1994), File No. 1-7316).
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 and 2000
(Dollars in Thousands)
Additions Deductions
Balance at Provisions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written Off of Year
Allowance for Doubtful Accounts
Year Ended December 31, 2002 $ 29,763 $ 19,688 $ 6,690 $ 31,762 $ 24,379
Year Ended December 31, 2001 $ 28,309 $ 21,815 $ 4,130 $ 24,491 $ 29,763
Year Ended December 31, 2000 $ 23,836 $ 18,920 $ 2,525 $ 16,972 $ 28,309
Tax Valuation Allowance
Year Ended December 31, 2002 $ 64,499 $ 15,384 $ - $26,986 $ 52,897
Year Ended December 31, 2001 $ - $ 64,499 $ - $ - $ 64,499
Year Ended December 31, 2000 $ - $ - $ - $ - $ -
FORM 10-K NSTAR
DECEMBER 31, 2002
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
NSTAR
(Registrant)
Date: March 27, 2003 By: /s/ Robert J. WEAFER, Jr.
Robert J. Weafer, Jr.
Vice President, Controller
and Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated on
the 27th day of March 2003.
Signature Title
/s/ Thomas J. May Chairman, President, Chief
Thomas J. May Executive Officer and
Trustee
/s/ James J. Judge Senior Vice President,
James J. Judge Treasurer and Chief
Financial Officer
/s/ G. L. Countryman Trustee
Gary L. Countryman
/s/Daniel Dennis Trustee
Daniel Dennis
/s/Thomas G. Dignan, Jr. Trustee
Thomas G. Dignan, Jr.
/s/Charles K. Gifford Trustee
Charles K. Gifford
Signature Title
/s/Matina S. Horner Trustee
Matina S. Horner
/s/Franklin M. Hundley Trustee
Franklin M. Hundley
/s/Paul A. LaCamera Trustee
Paul A. La Camera
/s/Sherry H. Penney Trustee
Sherry H. Penney
/s/William C. VanFaasen Trustee
William C. Van Faasen
/s/ Gerald L. Wilson Trustee
Gerald L. Wilson
Sarbanes - Oxley Section 302(a) Certifications
I, Thomas J. May, certify that:
1. I have reviewed this Annual Report on Form 10-K of NSTAR;
2. Based on my knowledge, this Annual Report does not contain any
untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not
misleading with respect to the period covered by this Annual
Report;
3. Based on my knowledge, the financial statements, and other
financial information included in this Annual Report, fairly
present in all material respects the financial condition,
results of operations and cash flows of NSTAR as of, and for,
the periods presented in this Annual Report;
4. NSTAR's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-14 and 15d-14) for NSTAR
and we have:
a) designed such disclosure controls and procedures to
ensure that material information relating to NSTAR,
including its consolidated subsidiaries, is made known to
us by others within those entities, particularly during
the period in which this Annual Report is being prepared;
b) evaluated the effectiveness of NSTAR's disclosure
controls and procedures as of a date within 90 days prior
to the filing date of this Annual Report (the "Evaluation
Date"); and
c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. NSTAR's other certifying officer and I have disclosed, based on
our most recent evaluation, to NSTAR's auditors and the Audit,
Finance and Risk Management Committee of NSTAR's Board of
Trustees:
a) all significant deficiencies in the design or operation
of internal controls which could adversely affect NSTAR's
ability to record, process, summarize and report
financial data and have identified for NSTAR's auditors
any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant role
in the registrant's internal controls; and
6. NSTAR's other certifying officer and I have indicated in this
Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most
recent evaluation, including any corrective actions with regard
to significant deficiencies and material weaknesses.
Date: March 27, 2003 By: /s/ THOMAS J. MAY
Thomas J. May
Chairman, President and
Chief Executive Officer
I, James J. Judge, certify that:
1. I have reviewed this Annual Report on Form 10-K of NSTAR:
2. Based on my knowledge, this Annual Report does not contain
any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light
of the circumstances under which such statements were made,
not misleading with respect to the period covered by this
Annual Report;
3. Based on my knowledge, the financial statements, and other
financial information included in this Annual Report, fairly
present in all material respects the financial condition,
results of operations and cash flows of NSTAR as of, and for,
the periods presented in this Annual Report;
4. NSTAR's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-
14) for NSTAR and we have:
a) designed such disclosure controls and procedures to
ensure that material information relating to NSTAR,
including its consolidated subsidiaries, is made known
to us by others within those entities, particularly
during the period in which this Annual Report is being
prepared;
b) evaluated the effectiveness of NSTAR's disclosure
controls and procedures as of a date within 90 days
prior to the filing date of this Annual Report (the
"Evaluation Date"); and
c) presented in this Annual Report our conclusions about
the effectiveness of the disclosure controls and
procedures based on our evaluation as of the Evaluation
Date;
5. NSTAR's other certifying officer and I have disclosed, based
on our most recent evaluation, to NSTAR's auditors and the
Audit, Finance and Risk Management Committee of NSTAR's Board
of Trustees:
a) all significant deficiencies in the design or operation
of internal controls which could adversely affect
NSTAR's ability to record, process, summarize and report
financial data and have identified for NSTAR's auditors
any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves
management or other employees who have a significant
role in NSTAR's internal controls; and
6. NSTAR's other certifying officer and I have indicated in this
Annual Report whether or not there were significant changes
in internal controls or in other factors that could
significantly affect internal controls subsequent to the date
of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material
weaknesses.
Date: March 27, 2003 By: /s/ JAMES J. JUDGE
James J. Judge
Senior Vice President, Treasurer
and Chief Financial Officer