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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, 2001
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 04-346630
(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 ]
The aggregate market value of the voting stock held by non-
affiliates of the registrant as of March 15, 2002 computed as the
average of the high and low market price of the common shares as
reported in the listing of composite transactions for New York
Stock Exchange listed securities in the Wall Street Journal:
$2,354,645,042.
Indicate the number of shares outstanding of each for the
registrant's classes of common stock, as of the latest
practicable date.
Class Outstanding at March 15,2002
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 22, 2002
(pages as specified herein)
List of exhibits begins on page 77 of this report.
NSTAR
Form 10-K Annual Report December 31, 2001
Page
Part I
Item 1. Business 2
Item 2. Properties 11
Item 3. Legal Proceedings 12
Item 4. Submission of Matters to a Vote of Security Holders 13
Item 4A. Executive Officers of the Registrant 14
Part II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters 15
Item 6. Selected Consolidated Financial Data 16
Item 7. Management's Discussion and Analysis 17
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 41
Item 8. Financial Statements and Supplementary Financial Information 42
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 76
Part III
Item 10. Trustees and Executive Officers of the Registrant 76
Item 11. Executive Compensation 76
Item 12. Security Ownership of Certain Beneficial Owners and 76
Management
Item 13. Certain Relationships and Related Transactions 76
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports 77
on Form 8-K
Part I
Item 1. Business
(a) General Development of Business
NSTAR (or "the Company") is an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 246,000 gas customers in 51 communities. NSTAR was created
through the merger of BEC Energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25, 1999 as an exempt public
utility holding company. Its 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
Electric). NSTAR's three retail electric companies operate under
the brand name "NSTAR Electric." Reference in this report to
"NSTAR Electric" shall mean each of Boston Edison, ComElectric
and Cambridge Electric. NSTAR's non-utility operations include
telecommunications - NSTAR Communications, Inc. (NSTAR Com),
district heating and cooling operations (Advanced Energy Systems,
Inc. and NSTAR Steam Corporation) and a liquefied natural gas
service (Hopkinton LNG Corp.). Utility operations accounted for
approximately 96% of revenues in both 2001 and 2000.
The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices. These demands
have encouraged the utility industry to seek efficiencies and
other benefits through business combinations. NSTAR is prepared
to operate in this changing marketplace by combining the
resources of its utility subsidiaries and concentrating its
activities in the transmission and distribution of energy.
NSTAR Electric has committed resources to implement a System
Improvement Program to better serve its customers by focusing on
improving customer service and system reliability. This
comprehensive, non-recurring System Improvement Program was
implemented to upgrade NSTAR Electric's distribution system and
is expected to be completed by the third quarter of 2002. The
cost of this non-recurring program is expected to be $65 million.
Approximately $11 million will be included in operations and
maintenance expense in 2002 and $54 million will be invested in
delivery assets (utility plant) during the year. A combination
of unusually severe storms, record heat and extreme customer load
in the Boston area led to prolonged and wide-spread outages in
the summer of 2001 that underscored the need to address system
upgrades and improve maintenance. NSTAR's peak demand electric
load reached an all-time level on August 9, 2001 of 4,527
megawatts (MW) and surpassed the prior year's peak load by 12%
and the previous all-time peak load by 8.5%. The program
includes non-recurring costs to eliminate the backlog of critical
maintenance activities and complete non-routine systems
enhancements.
An integral part of the merger creating NSTAR is the rate plan of
the retail utility subsidiaries of BEC and COM/Energy that was
approved by the Massachusetts Department of Telecommunication and
Energy (MDTE) on July 27, 1999. Significant elements of the rate
plan include a four-year distribution rate freeze, recovery of
the acquisition premium (goodwill) over 40 years and recovery of
transaction and integration costs (costs to achieve) over 10
years. Refer to the "Retail Electric Rates" section in Item 7,
Management's Discussion and Analysis 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. Refer to the "Generating
Assets Divestiture" section in Item 7, Management's Discussion
and Analysis 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 over 100
cities and towns in Massachusetts. Refer to Note K of the
Consolidated Financial Statements in Item 8 for specific
financial information related to NSTAR's electric utility, gas
utility and unregulated segments.
(c) Narrative Description of Business
Principal Products and Services
NSTAR ELECTRIC
NSTAR Electric operating revenues by class of customers for the
years 2001, 2000 and 1999 consisted of the following:
Retail electric revenues: 2001 2000 1999
Commercial 51% 49% 51%
Residential 33% 33% 30%
Industrial 8% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 7% 8% 9%
The results for 2001 and 2000 reflect NSTAR for a full year,
while the results for 1999 reflect eight months of BEC and four
months of NSTAR.
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 the
area served with electricity at retail is approximately 2.3
million. In 2001, NSTAR Electric served approximately 1.1
million customers.
Sources and Availability of Electric Power Supply
NSTAR Electric has existing long-term power purchase agreements
that are expected to supply approximately 90%-95% of its standard
offer service obligations. NSTAR Electric has entered into a
series of short-term power purchase agreements to meet its entire
default service supply obligations and its remaining unmet
standard offer supply obligations through December 31, 2002.
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 entered into six-month agreements effective
January 1, 2001 through June 30, 2001 and July 1, 2001 through
December 31, 2001 with suppliers to provide full default service
energy and ancillary service requirements at contract rates
substantially similar to MDTE-approved tariff rates. NSTAR
Electric's existing portfolio of power purchase contracts
supplied the majority of its standard offer (including wholesale)
energy requirements in 2001, supplemented with long-term and
daily purchases/sales in the bilateral and spot markets. In
addition, NSTAR Electric managed its Independent System Operator-
New England Power capability responsibilities, congestion and
uplift costs associated with default service and standard offer
load throughout 2001. For further information refer to Note M of
the Consolidated Financial Statements in Item 8.
ComElectric had an 11% contract entitlement in the output of the
Pilgrim nuclear power plant that was sold by Boston Edison in
1999 to Entergy Nuclear Generating Company (Entergy). Boston
Edison and ComElectric will buy power generated by the Pilgrim
plant from Entergy on a declining basis through 2004.
NSTAR Electric also has a 2.5% equity investment in the 540 MW
Vermont Yankee nuclear power plant. NSTAR Electric is entitled
to electricity produced from the facility based on its ownership
interest, and is billed for its entitlement pursuant to a
contractual agreement that is approved by the FERC. The
estimated cost to decommission this plant is $471.1 million in
current dollars. NSTAR Electric's share of this liability is
approximately $11.8 million, less its share of the market value
of the assets held in a decommissioning trust of approximately
$7.4 million, is approximately $4.4 million at December 31, 2001.
Vermont Yankee has received the approval of the FERC to include
charges for the estimated costs of decommissioning its unit in
the cost of energy that it sells. Periodically, Vermont Yankee
re-estimates the cost of decommissioning and applies to the FERC
for increased rates in response to increased decommissioning
costs. The Vermont Yankee unit was under agreement to be sold to
Amergen Energy Company (Amergen), but this transaction was
disapproved on February 14, 2001 by Vermont's regulatory
authority. Subsequently, in 2001, FERC approved an agreement
between Vermont Yankee and intervening parties that included,
among other things, a settlement on the regulatory treatment of
costs incurred in conjunction with initiatives, including Amergen
to sell the plant and related assets and liabilities.
On August 15, 2001, Vermont Yankee executed a Purchase and Sale
Agreement with the intent to sell the plant and related assets
and liabilities, including the liability to decommission the
plant, to Entergy Nuclear Vermont Yankee, LLC. The sale of the
plant, as contemplated, would likely result in the transfer of
responsibility for decommissioning the plant to the new owner and
make future decommissioning collections unnecessary.
As of December 31, 2001, information that relates to nuclear
units that are no longer operating in which NSTAR has an equity
ownership is as follows:
Connecticut Maine Yankee
Yankee Yankee Atomic
(dollars in thousands)
Year of Shutdown 1996 1997 1992
Equity Ownership (%) 14 4 14
Equity Ownership Balance $ 9,573 $ 2,493 $ 90
New England Power Pool (NEPOOL)
NEPOOL was restructured with changes taking effect to the
membership and governance provisions of the power pooling
agreement along with the transfer of operating responsibility of
the integrated transmission and generation system in New England
to ISO-New England. Previously, NEPOOL dispatched generating
units for operation based on the lowest operating costs of
available generation and transmission. Under the new structure,
generators are required to provide ISO-New England with market
prices at which they sell short-term energy supply. These prices
formed the basis for dispatch that began in the second quarter of
1999. As noted in the "Sources and Availability of Electric
Power Supply" section above, NSTAR Electric has existing long-
term power purchase contracts that have been supplying 90% - 95%
of its standard offer service obligations. Therefore, the change
to NEPOOL's operations and pricing structure is expected to have
no material adverse impact on NSTAR's costs for purchased
electric energy.
Retail Electric Rates
As a result of electric industry restructuring, NSTAR Electric
has unbundled its rates, provided customers with inflation-
adjusted rates that are 15 percent lower than rates in effect
prior to March 1, 1998 (the retail access date) and have afforded
customers the opportunity to purchase generation supply in the
competitive market. Unbundled delivery rates are composed of a
customer charge (to collect metering and billing costs), a
distribution charge (to collect the costs of delivering
electricity), a transition charge (to collect past costs for
investments in generating plants and costs related to power
contracts), a transmission charge (to collect the cost of moving
the electricity over high voltage lines from a generating plant),
an energy conservation charge (to collect costs for demand-side
management programs) and a renewable energy charge (to collect
the cost to support the development and promotion of renewable
energy projects). Electricity supply services provided by NSTAR
Electric include optional standard offer service and default
service.
Standard offer service is the electricity that is supplied to
eligible customers by the retail electric subsidiaries until a
competitive power supplier is chosen by the customer. Customers
have the option of continuing to buy power from the retail
electric distribution businesses at standard offer prices through
2004. 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 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.
Prior to the implementation of industry restructuring on March 1,
1998, NSTAR Electric had Fuel Charge rate schedules that
generally allowed for current recovery, from retail customers, of
fuel used in electric production, purchased power and
transmission costs.
NSTAR Gas
NSTAR Gas operating revenues by class of customers for the years
2001, 2000 and 1999 (effective September 1, 1999), consisted of
the following:
2001 2000 1999
Retail Gas revenues:
Residential 58% 59% 61%
Commercial 27% 24% 24%
Industrial 4% 3% 4%
Other 6% 8% 6%
Wholesale and contract revenues 5% 6% 5%
Natural gas is distributed by NSTAR Gas to approximately 246,000
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 by
NSTAR Electric with electricity. 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.
Gas Supply
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 and
Canada to the final delivery points in the Company's 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 November
2001, NSTAR Gas entered into a one-year full services firm supply
agreement with a major marketer in order to more fully optimize
its supply and transportation portfolio. The agreement requires
the supplier to deliver all of NSTAR Gas' required pipeline
supplies utilizing the Company's upstream pipeline capacity.
In addition to 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 for gas supply for NSTAR Gas during the
winter heating season is provided by Hopkinton LNG Corp.
(Hopkinton), a wholly-owned subsidiary of NSTAR. The facility
consists of a liquefaction and vaporization plant and three above-
ground cryogenic storage tanks having an aggregate capacity of 3
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 .5 Bcf of natural gas
that are filled with LNG trucked from Hopkinton or purchased from
third parties.
NSTAR Gas has contracts for LNG storage service with Hopkinton
extending on a year-to-year basis with notice of termination
required five years in advance of the anticipated termination
date. Current contract payments include a demand charge
sufficient to cover Hopkinton's fixed charges and an operating
charge that covers liquefaction and vaporization expenses. NSTAR
Gas furnishes pipeline gas during the period April 15 to November
15 each year for liquefaction and storage. As the need arises
during the winter season, LNG is vaporized and placed in the
distribution system to supplement pipeline and storage
deliveries.
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.
Off-system Gas Sales and Capacity Release Service
NSTAR Gas utilizes the off-system sales and capacity release
markets in order to optimize the value of its supply portfolio
and to mitigate the cost of any excess resources. In 2001 the
Company elected to accomplish this through third parties that
provided guaranteed payments as compensation for use of any
available excess storage and transportation entitlements. NSTAR
Gas retains 25% of the gross mitigation margins realized above a
certain threshold amount as set from year to year, with the
remaining margins credited to firm customers. As a result of
this margin-sharing agreement, NSTAR Gas retained approximately
$636,000 and $189,000 in 2001 and 2000, respectively.
Natural Gas Industry Restructuring and Rates
Effective November 1, 2000, the MDTE approved regulations that
provide for full customer choice to LDCs (local gas distribution
companies) such as NSTAR Gas. 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 during a three-year transition period.
This eliminates potential stranded cost exposure for the LDCs
until they are relieved from their responsibility as suppliers of
last resort and the establishment of a "workably competitive"
interstate pipeline capacity market. Gas restructuring is not
likely to have a significant adverse financial impact on 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 all of the 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 December 2000 and in a revised filing in January 2001, NSTAR
Gas filed for interim increases to its CGAC for the period
February through April 2001 in order to recover significant
increases in the costs to buy natural gas supplies. These
filings were made to ensure that prices to customers are set at
levels that recover all incurred costs in order to avoid the
accumulation of significant under-recoveries that would impair
NSTAR Gas' ability to serve its customers. On January 31, 2001,
the MDTE approved an adjustment to increase the CGAC factor to
$1.1123 per therm from the prior factor of $0.7608 per therm.
Subsequently, on February 28, 2001, as a result of a decline in
wholesale natural gas prices, NSTAR Gas received approval from
the MDTE to reduce the factor per therm to $0.9372 effective
March 1, 2001, and in conjunction with its semi-annual filing
made on March 15, 2001, NSTAR Gas proposed a CGAC factor of
$0.7754 per therm for the period commencing May 1, 2001 through
October 31, 2001. This factor, approved by the MDTE, included
the collection in the summer period of a portion of the coming
winter's gas costs in order to reduce cost deferrals that were
projected for the end of October 2001. In October 2001, due to
the significant decline in wholesale natural gas prices, NSTAR
Gas received approval from the MDTE to reduce the CGAC factor for
the period from November 1, 2001 through April 30, 2002 to
$0.5261 per therm. In December 2001, NSTAR Gas received approval
to further reduce its CGAC factor by 17% to $0.4350 per therm
effective January 1, 2002. In January 2002, NSTAR Gas again
filed and the MDTE approved a reduction of the NSTAR Gas CGAC
factor that became effective February 1, 2002 to $0.3834 per
therm as a result of the continuing decline in its supply costs.
This represented a 59% decrease from the weighted average factor
in effect during the prior winter season.
RCN Joint Venture and Investment Conversion
NSTAR Com is a participant in a telecommunications venture with
RCN Telecom Services, Inc. of Massachusetts, a subsidiary of RCN
Corporation (RCN). NSTAR Com has accounted for its equity
investment in the joint venture using the equity method of
accounting. As part of the Joint Venture Agreement, NSTAR Com has
the option to exchange portions of its joint venture interest for
common shares of RCN at specified periods. NSTAR Com recognized
an impairment of its entire investment in RCN in the first
quarter of 2001. For a further discussion on these exchanges and
other developments, refer to the "RCN Joint Venture and
Investment Conversion" section in Item 7, Management's Discussion
and Analysis for more information.
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 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. Pursuant to the Restructuring
Act enacted in November 1997, the MDTE has defined the service
territory of NSTAR Electric and NSTAR Gas based on the territory
actually served on July 1, 1997, and following, to the extent
possible, municipal boundaries. The legislation further provided
that, until terminated by effect of law or otherwise, these
companies shall have the exclusive obligation to provide
distribution service to all retail customers within such service
territory. No other entity shall provide distribution service
within this territory without the written consent of NSTAR
Electric and/or NSTAR Gas, which consent must be filed with the
MDTE and the municipality so affected.
Regulation
NSTAR Electric, NSTAR Gas, and Boston Edison's wholly owned
subsidiary, Harbor Electric Energy Company (HEEC), operate
primarily under the authority of the MDTE, whose jurisdiction
includes supervision over retail rates for distribution of
electricity, natural gas and financing and investing activities.
In addition, the FERC has jurisdiction over various phases of
NSTAR 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 system of
accounts.
Capital Expenditures and Financings
The most recent estimates of capital expenditures and long-term
debt maturities requirements for the years 2002 through 2006 are
as follows:
2002 2003 2004 2005 2006
(in thousands)
Capital expenditures (1) $315,000 $229,000 $ 193,000 $168,000 $147,000
Long-term debt $ 78,648 $241,168 $ 78,659 $ 77,562 $ 98,024
(1) Includes plant expenditures, capital requirements of non-
utility ventures and $54 million of costs related to a non-
recurring System Improvement Program.
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, environmental standards, availability
and cost of capital, interest rates and other assumptions.
Plant expenditures in 2001 were $228.7 million and consisted
primarily of additions to NSTAR's distribution and transmission
systems. The majority of these expenditures were for system
reliability and control improvements, customer service
enhancements and capacity expansion to allow for long-range
growth in the NSTAR service territory.
Refer to the "Liquidity and Capital Resources" section of Item 7
for more information regarding capital resources to fund NSTAR's
construction programs.
Seasonal Nature of Business
Kilowatt-hour sales and revenues are typically higher in the
winter and summer than in the spring and fall as sales tend to
vary with weather conditions. Refer to the Selected Consolidated
Quarterly Financial Data (Unaudited) in Item 6 for specific
financial information by quarter for 2001 and 2000. NSTAR Gas'
sales are positively impacted by colder weather because a
substantial portion of its customer base uses natural gas for
space heating purposes.
Competitive Conditions
The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices. These pressures
have resulted in an increasing trend in the industry to seek
competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new
marketplace by combining the resources of its utility
subsidiaries in its activities in the transmission and
distribution of energy.
Environmental Matters
NSTAR's 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 for more
information.
Environmental-related capital expenditures for the years 2001 and
2000 were $0 and $4.5 million, respectively. Management believes
that its remaining operating facilities are in substantial
compliance with currently applicable statutory and regulatory
environmental requirements. Additional expenditures could be
required as changes in environmental requirements occur.
Number of Employees
As of December 31, 2001, NSTAR had approximately 3,300 full-time
employees, including approximately 2,300 or 70% of whom are
represented by two collective bargaining units covered by
separate contracts. Effective in May 2001, all employees are
employed by NSTAR Electric & Gas Corporation (NSTAR Electric &
Gas). As of December 2000, the management of NSTAR's utility
subsidiaries and eight separate utility union bargaining units
reached an agreement to merge most of the unionized workforce,
effective January 1, 2001, into Local 369 of the Utility Workers
Union of America, AFL-CIO. The new agreement results in a single
bargaining unit of approximately 2,000 NSTAR Electric & Gas
employees with a five-year contract expiring May 15, 2005 that
replaced seven separate and widely diverse agreements.
A collective bargaining unit contract representing approximately
300 NSTAR Electric & Gas employees expires on March 31, 2002. On
March 24, 2002, Local 12004, United Steelworkers of American, AFL-
CIO-CLC ratified a new four-year contract that expires on March
31, 2006.
Management believes it has satisfactory employee relations with a
significant majority of 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
Substantially all of NSTAR Electric's fossil generating assets
were sold as of December 30, 1998. The Pilgrim Nuclear
Generating Station was sold in 1999. NSTAR, through its Canal
Electric subsidiary, continues to retain a 3.52% interest (40.5
MW of capacity) in Seabrook 1.
Other NSTAR Electric properties include an integrated system of
distribution lines and substations that are located primarily in
the Boston area as well as the outlying communities, including
Plymouth, New Bedford, Cape Cod communities and Martha's
Vineyard. In addition, NSTAR Electric's other principal
properties consist of an office building and other structures
such as garages and service buildings.
At December 31, 2001, the NSTAR Electric primary and secondary
transmission and distribution system consisted of approximately
20,200 circuit miles of overhead lines, approximately 8,400
circuit miles of underground lines, 261 substations and
approximately 1,109,000 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.
The principal natural gas properties consist of distribution
mains, services and meters necessary to maintain reliable service
to customers. At December 31, 2001, the gas system included
approximately 2,900 miles of gas distribution lines,
approximately 174,700 services and approximately 266,200 customer
meters together with the necessary measuring and regulating
equipment. In addition, NSTAR (through Hopkinton) 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, five district office buildings and several natural
gas receiving and take stations.
In the third quarter of 2001, in conjunction with its corporate
facilities consolidation of approximately a third of its work
force, NSTAR completed construction of a 370,000 square foot
office building (the Summit) sited on 33 acres in the Boston
suburb of Westwood. This site is centrally located in NSTAR's
service area and houses central administrative offices including
finance, human resources, sales, engineering, information
technology, and customer care. NSTAR is expected, in 2002, to
close on a like-kind exchange of properties in Boston and
Cambridge for the Summit.
District heating and cooling operations primarily consist of the
Medical Area Total Energy Plant (MATEP) located in the Longwood
Medical Area of Boston. MATEP provides steam, chilled water and
electricity to over 9 million square feet in medical and teaching
facilities. NSTAR Steam Corporation's distribution system
consists primarily of approximately 3.5 miles of high pressure
steam lines to 21 customers in Cambridge and Boston.
HEEC, Boston Edison's regulated subsidiary, has a distribution
system that consists principally of a 4.1 mile 115 kV submarine
distribution line and a substation which is located on Deer
Island in Boston, Massachusetts. HEEC provides the ongoing
support required to distribute electric energy to its only
customer, the Massachusetts Water Resources Authority, at this
location.
Item 3. Legal Proceedings
Industry and corporate restructuring legal proceedings
The 1998 MDTE order approving the Boston Edison electric
restructuring settlement agreement was appealed by certain
parties to the Massachusetts Supreme Judicial Court. One appeal
remains pending. However, there has to date been no briefing,
hearing or other action taken with respect to this proceeding.
Management is currently unable to determine the outcome of this
proceeding. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, cash flows and the results
of operations for a reporting period.
The 1999 MDTE order approving the rate plan associated with the
merger of BEC and COM/Energy was appealed by certain parties to
the Massachusetts Supreme Judicial Court. The appeals of the AG
and a separate group that consists of The Energy Consortium and
Harvard University remain pending. In October 2001, the MDTE
certified the record of the case to the court; however, there has
to date been no briefing, hearing or other action taken with
respect to this proceeding. If an unfavorable outcome were to
occur, there could be a material adverse impact on business
operations, the consolidated financial position, cash flows and
the results of operations for a reporting period.
Regulatory proceedings
In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the AG
contested cost allocations related to Boston Edison's wholesale
customers. On June 1, 2001, the MDTE approved Boston Edison's
revenue-credit approach for wholesale sales to be consistent with
Boston Edison's restructuring settlement. The reconciliation of
wholesale revenues and costs, along with other reconciliation
issues, were addressed in Boston Edison's 2000 filing covering
the reconciliation of costs through December 31, 2000. On
November 16, 2001, the MDTE approved a Settlement Agreement
between Boston Edison and the AG resolving all outstanding issues
in this filing. This settlement agreement did not have a
material effect on NSTAR's consolidated financial position or
results of operations.
In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities. On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million. BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002. Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs. Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets. This change had no
material adverse effect on NSTAR's consolidated financial
position or results of operations.
Other legal matters
In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters. Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued. Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal costs that may result from a
change in estimates could have a material impact on the results
of a reporting period in the near term.
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 2001.
Item 4A. Executive Officers of Registrant
Identification of Executive Officers
Age
December 31,
Name of Officer Position and Business Experience 2001
Thomas J. May Chairman of the Board, President 54
(since 2002), Chief Executive
Officer and a Director/Trustee
(since 1999), formerly Chairman of
the Board, President and Chief
Executive Officer and a Trustee
(1998-1999), BEC Energy, and
Chairman of the Board, 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, 51
Law & Policy, Clerk and General
Counsel, (since 1999); formerly
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 45
and Chief Financial Officer,
(since 2000); formerly Senior Vice
President and Chief Financial
Officer, (1999-2000); formerly
Senior Vice President-Corporate
Services and Treasurer, BEC Energy
(1998-1999); and Senior Vice
President-Corporate Services and
Treasurer, Boston Edison Company
(1995-1999).
Eugene J. Zimon Senior Vice President/Information 53
Technology, (since 2001).
Werner J. Schweiger Senior Vice President/Operations, 42
(since 2002).
Joseph R. Nolan, Jr. Senior Vice President - Corporate 38
Relations, (since 2000); formerly
Vice President of Government
Affairs, (1999-2000); Director of
Regulatory Relations, BEC Energy
(1998-1999); and Manager of
Legislative Affairs, Boston Edison
Company (1994-1998);
Robert J. Weafer, Jr. Vice President, Controller and 54
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, 2001 was $44.85 per
share.
The high and low market value per common share as reported in the
Wall Street Journal for each of the quarters in 2001 and 2000 was
as follows.
2001 2000
High Low High Low
First quarter $42.6875 $33.9375 $47.00 $38.25
Second quarter $43.85 $36.78 $46.125 $40.375
Third quarter $45.05 $39.50 $44.5625 $39.00
Fourth quarter $45.24 $40.10 $43.1875 $36.375
(b) Holders
As of December 31, 2001, there were 29,890 holders of NSTAR
common shares.
(c) Dividends
Dividends declared per common share for each of the quarters in
2001 and 2000 were as follows.
2001 2000
First quarter $0.515 $0.500
Second quarter $0.515 $0.500
Third quarter $0.515 $0.500
Fourth quarter $0.53 $0.515
Item 6. Selected Consolidated Financial Data
The following table summarizes five years of selected
consolidated financial data (in thousands, except per share
data). Prior to September 1999, the information below refers to
BEC Energy.
2001 2000 1999(c) 1998 1997
Operating revenues $3,191,836 $2,692,762 $1,851,427 $1,622,515 $1,778,531
Net income (a) $ 3,201 $ 180,962 $ 146,463 $ 141,046 $ 144,642
Earnings (loss)per
share of common stock:
Basic (a) $ (0.05) $ 3.19 $ 2.77 $ 2.76 $ 2.71
Diluted (a) $ (0.05) $ 3.18 $ 2.76 $ 2.75 $ 2.71
Total assets $5,328,191 $5,547,715 $5,466,143 $3,204,036 $3,622,347
Long-term debt (b) $1,377,899 $1,440,431 $ 986,843 $ 955,563 $1,057,076
Transition property
securitization
certificates (b) $ 513,904 $ 584,130 $ 646,559 $ - $ -
Redeemable preferred
stock (b) $ 43,000 $ 43,000 $ 92,279 $ 92,040 $ 163,093
Cash dividends
declared per
common share $ 2.075 $ 2.015 $ 1.955 $ 1.895 $ 1.88
(a) 2001 includes the impact of a non-cash, after-tax charge of
$173.9 million, or $3.28 per share, related to NSTAR's
investment in RCN Corporation.
(b) Excludes the current portion of long-term debt or 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.
Selected Consolidated Quarterly Financial Data (Unaudited)
(in thousands, except earnings per share)
Basic
Earnings
Earnings (Loss)
(Loss) Per
Net Available Average
Operating Operating Income for Common Common
Revenues Income (Loss) Shareholders Share (b)
2001
First quarter (a) $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
2000
First quarter $658,518 $ 79,401 $ 37,099 $ 35,609 $ 0.62
Second quarter $630,194 $ 76,955 $ 32,928 $ 31,438 $ 0.57
Third quarter $709,519 $126,864 $ 66,286 $ 64,796 $ 1.21
Fourth quarter $694,531 $ 91,074 $ 44,649 $ 43,159 $ 0.81
(a) Includes impact of a non-cash, after-tax charge of $173.9
million, or $3.28 per share, related to NSTAR's investment in RCN
Corporation.
(b) The sum of the quarters for 2000 may not equal basic annual
earnings per average common share since the result is based on
the weighted average number of common shares outstanding each
quarter.
Item 7. Management's Discussion and Analysis
Overview
NSTAR (or "the Company") is an energy delivery company serving
approximately 1.3 million customers in Massachusetts, including
approximately 1.1 million electric customers in 81 communities
and 246,000 gas customers in 51 communities. NSTAR was created
through the merger of BEC Energy (BEC) and Commonwealth Energy
System (COM/Energy) on August 25, 1999 as an exempt public
utility holding company. Its 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
Electric" shall mean each of Boston Edison, ComElectric and
Cambridge Electric. NSTAR's non-utility operations include
telecommunications - NSTAR Communications, Inc. (NSTAR Com),
district heating and cooling operations (Advanced Energy Systems,
Inc. and NSTAR Steam Corporation) and a liquefied natural gas
service company (Hopkinton LNG Corp.). Utility operations
accounted for approximately 96% of revenues in both 2001 and
2000.
The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices. These demands
have encouraged the utility industry to seek efficiencies and
other benefits through business combinations. NSTAR is prepared
to operate in this changing marketplace by combining the
resources of its utility subsidiaries and concentrating its
activities in the transmission and distribution of energy.
NSTAR Electric has committed resources to implement a System
Improvement Program to better serve its customers by focusing on
improving customer service and system reliability. This
comprehensive, non-recurring System Improvement Program was
implemented to upgrade NSTAR Electric's distribution system and
is expected to be completed during 2002. The cost of this non-
recurring program is expected to be $65 million. Approximately
$11 million will be included in operations and maintenance
expense in 2002 and $54 million will be invested in delivery
assets during the year. A combination of unusually severe
storms, record heat and extreme customer load in the Boston area
led to prolonged and wide-spread outages in the summer of 2001
that underscored the need to address system upgrades and improve
maintenance. NSTAR's peak demand electric load reached an all-
time level on August 9, 2001 of 4,527 megawatts (MW) and
surpassed the prior year's peak load by 12% and the previous all-
time peak load by 8.5%. The program includes non-recurring costs
to eliminate the backlog of critical maintenance activities and
complete non-routine systems enhancements.
Cautionary Statement
This Management's Discussion and Analysis 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 be
contained in filings with the Securities and Exchange Commission
(SEC) and in press releases and oral statements. You can
identify these statements by the fact that they do not relate
strictly to historical or current facts. They use words such as
"anticipate," "estimate," "expect," "project," "intend," "plan,"
"believe" and other words and terms of similar meaning in
connection with any discussion of future operating or financial
performance. These statements are based on the current
expectations, estimates or projections of management and are not
guarantees of future performance. Some or all of these forward-
looking statements may not turn out to be what the Company
expected. Actual results could potentially differ materially
from these statements. Therefore, no assurance can be given that
the outcomes stated in such forward-looking statements and
estimates will be achieved.
The impact of continued cost control procedures on operating
results could differ from current expectations. NSTAR's revenues
from its electric and gas sales are weather-sensitive,
particularly sales to residential and commercial customers.
Accordingly, NSTAR's sales in any given period reflect, in
addition to other factors, the impact of weather, with colder
temperatures generally resulting in increased gas sales and
warmer 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,
prices and availability of operating supplies could materially
affect the projected operating results.
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 any
further disclosures NSTAR makes in its Forms 10-Q and 8-K to the
SEC. Also note that NSTAR provides in the next paragraph 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.
NSTAR's forward-looking information depends in large measure on
prevailing governmental policies and regulatory actions,
including those of the Massachusetts Department of
Telecommunications and Energy (MDTE) and the Federal Energy
Regulatory Commission (FERC), with respect to allowed rates of
return, rate structure, 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 issues, and
regulatory matters could differ from current expectations. New
regulations or changes to existing regulations could impose
additional operating requirements or liabilities other than
expected. The effects of changes in specific hazardous waste
site conditions and the specific cleanup technology could affect
the estimated cleanup liabilities. The impacts of changes in
available information and circumstances regarding legal issues
could affect any estimated litigation costs.
Generating Assets Divestiture
On October 26, 2000, the MDTE approved the filing made by
ComElectric and Cambridge Electric (together, "the Companies")
for the partial buydown of their contract with Canal for power
from the Seabrook nuclear generating facility (Seabrook). In
November 2000, a total of $141.6 million of funds held by an
affiliate, Energy Investment Services, Inc. (EIS), was
transferred to the Companies. EIS was established as the vehicle
to invest the net proceeds from the sale of the Companies'
generation assets. The Companies, in turn, reduced their
respective future costs to be recovered from customers. The FERC
and the MDTE approved Canal's request to reflect the buydown
effective November 1, 2000. Canal, along with other joint-owners
of Seabrook, has begun to actively market the sale of Seabrook.
In July 1999, Boston Edison completed the sale of the Pilgrim
Nuclear Generating Station to Entergy Nuclear Generating Company
(Entergy), a subsidiary of Entergy Corporation, for $81 million.
In addition to the amount received from the buyer, Boston Edison
received a total of approximately $233 million from the Pilgrim
contract customers, including $103 million from ComElectric, to
terminate their contracts. As part of the sale, Boston Edison,
transferred its decommissioning trust fund to Entergy. In order
to provide Entergy with a fully funded decommissioning trust
fund, Boston Edison contributed approximately $271 million to the
fund at the time of the sale. As a result of a favorable
Internal Revenue Service tax ruling, Boston Edison received $43
million from Entergy reflecting a reduction in the required
decommissioning funding. The difference between the total
proceeds received and the net book value of the Pilgrim assets
sold plus the net amount to fully fund the decommissioning trust
is included in Regulatory assets on the accompanying Consolidated
Balance Sheets as such amounts are currently being collected from
customers under Boston Edison's settlement agreement.
Rate and Regulatory Proceedings
An integral part of the merger creating NSTAR is the rate plan of
the retail utility subsidiaries of BEC and COM/Energy 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. Refer to the "Retail Electric Rates" section of
this Management's Discussion and Analysis for more information.
Goodwill relating to the merger amounted to approximately $490
million, resulting in annual amortization of goodwill of
approximately $12.2 million. Costs to achieve are being
amortized based on the filed estimate of $111 million over 10
years. NSTAR's retail utility subsidiaries will reconcile the
ultimate costs to achieve with that estimate, and any difference
is expected to be recovered over the remainder of the
amortization period commencing in 2003. A majority of costs to
achieve the merger were severance costs associated with a
voluntary separation program (VSP) in which approximately 700
employees elected to participate. The VSP was completed by the
end of August 2000. These amounts are offset by ongoing cost
savings from streamlined operations and avoidance of costs that
would have otherwise been incurred by BEC and COM/Energy. Refer
to the "New Accounting Principles" section of this Management's
Discussion and Analysis for further information.
In a Boston Edison reconciliation filing for 1999 with the MDTE
reflecting final costs and revenues through 1998, the
Massachusetts Attorney General (AG) contested cost allocations
related to Boston Edison's wholesale customers. On June 1, 2001,
the MDTE approved Boston Edison's revenue-credit approach for
wholesale sales to be consistent with Boston Edison's
restructuring settlement. The reconciliation of wholesale
revenues and costs, along with other reconciliation issues, were
addressed in Boston Edison's 2000 filing covering the
reconciliation of costs through December 31, 2000. On November
16, 2001, the MDTE approved a Settlement Agreement between Boston
Edison and the AG resolving all outstanding issues in this
filing. This settlement agreement did not have a material effect
on NSTAR's consolidated financial position or results of
operations.
In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Energy Technology Group, Inc. (BETG) and
authorized Boston Edison to invest up to $45 million in non-
utility activities. On December 28, 2001, the MDTE issued its
order ruling that Boston Edison exceeded the $45 million
investment cap set by the MDTE in 1993 by $3.9 million. BETG was
ordered to return this amount to Boston Edison within 30 days.
This reimbursement occurred in January 2002. Boston Edison was
also ordered to pay approximately $1.9 million representing
carrying charges on the over-investment amount since December 31,
1997 to current customers in the form of a credit to Boston
Edison's transition costs. Accordingly, this credit has been
recorded and is included in the accompanying Consolidated Balance
Sheets as a reduction of Regulatory assets. This charge had no
material adverse effect on NSTAR's consolidated financial
position or results of operations.
On June 13, 2001, the MDTE approved a settlement agreement
between Cambridge Electric and the Massachusetts Institute of
Technology (MIT) involving a dispute over the customer transition
charge (CTC) assessed by Cambridge Electric to MIT. Under the
settlement, Cambridge Electric refunded approximately $1.7
million to MIT and MIT withdrew (i) its appeal at the
Massachusetts Supreme Judicial Court of the MDTE's rate order
associated with the merger of BEC Energy and COM/Energy and (ii)
its separate rate complaint at the MDTE involving the CTC.
On October 29, 2001, and as subsequently updated, NSTAR Electric
and NSTAR Gas each filed with the MDTE proposed service quality
plans for each company, which replaced the service quality plan
that had previously been filed as a part of the NSTAR merger rate
plan and includes guidelines that had been established by the
MDTE as a result of its generic investigation of service quality
issues. 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. On October 29, 2001, NSTAR Electric and
NSTAR Gas also filed with the MDTE a report concerning their
performance on the identified service quality measures for the
two twelve-month periods ended August 31, 2000 and 2001. This
report included a calculation of penalties in accordance with
MDTE guidelines whereby penalties were calculated totaling
approximately $3.9 million relating primarily to Boston Edison's
electric system reliability performance for the summer of 2001.
NSTAR disputes the legal applicability of penalties for these
performance periods; however, NSTAR proposed in settlement of
this matter to provide credits to Boston Edison customers
totaling $3.9 million, offset in part by other payments to Boston
Edison customers, which totaled approximately $1 million,
relating to summer 2001 electric service outages. On March 22,
2002, following hearings on the matter, the MDTE issued an order
imposing a service quality penalty of approximately $3.25 million
to be refunded to customers as a credit to their bills in 2002.
Also on October 29, 2001, NSTAR Electric filed with the MDTE a
comprehensive report regarding electric system performance issues
encountered during the summer of 2001. The filing included
detailed analyses of factors affecting performance, as well as,
the companies' plans to address issues identified. The MDTE also
requested similar filings from other Massachusetts electric
distribution companies and has held public hearings and will hold
adjudicatory hearings concerning each such filing. On January
30, 2002, the AG and the Massachusetts Division of Energy
Resources (DOER) filed comments urging the MDTE to assess the
maximum penalties allowed pursuant to the established service
quality benchmarks and to require an independent management audit
as a result of alleged service quality deficiencies. On February
6, 2002, NSTAR Electric filed its brief arguing against the AG's
and DOER's positions. On March 22, 2002, following a number of
public hearings throughout the NSTAR Electric service area, the
MDTE issued an order finding that NSTAR Electric had made
progress in addressing the issues which initiated the
investigation and requiring that NSTAR Electric submit further
updated reports on specific issues on a quarterly and annual
basis. NSTAR is unable to estimate its ultimate liability for
future costs or penalties as a result of any further filings
relating to this investigation. However, in view of NSTAR's
current assessment of its electric distribution system
performance responsibilities, existing legal requirements and
regulatory policies, management believes it would not have a
material effect on NSTAR's consolidated financial position, cash
flows or results of operations for a reporting period.
Retail Electric Rates
All distribution customers must pay a transition charge as a
component of their rate. The purpose of the transition charge is
to allow for the collection of generation-related costs that
would not be collected in the competitive energy supply market.
The plant and regulatory asset balances that will be recovered
through the transition charge are approved by the MDTE in annual
filings by the NSTAR Electric companies. The current schedule
for cost recovery through the transition charge is: Boston Edison
through 2016, Cambridge Electric and ComElectric through 2026.
This schedule is subject to adjustment by the MDTE.
The 1997 Restructuring Act requires electric distribution
companies to obtain and resell power to retail customers who
choose not to buy energy from a competitive energy supplier
through either standard offer service or default service.
Standard offer service will be available to eligible customers
through 2004 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,
2001, NSTAR Electric had approximately 16% of its load
requirements provided by competitive suppliers.
NSTAR Electric's accumulated cost to provide default and standard
offer service was in excess of the revenues it was allowed to
bill. As a result, NSTAR reflected a regulatory asset of
approximately $242.7 million at December 31, 2000 that is
reflected as a component of Regulatory assets on the accompanying
Consolidated Balance Sheets. NSTAR Electric was permitted by the
MDTE to increase its rates charged to customers to collect this
shortfall. As a result of new rates for standard offer and
default service that became effective January 1 and July 1, 2001,
and the reduction in power supply costs in 2001, the regulatory
asset has declined to $45.4 million as of December 31, 2001.
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
based on a decrease in the cost of fuel. The MDTE has ruled that
these fuel index adjustments are excluded from the 15% rate
reduction requirement under the Restructuring Act.
NSTAR Electric must, on an annual basis, file a forecast of its
rates for the upcoming year along with any reconciliation of
prior year revenues and costs for standard offer, default
service, transmission and transition charges. The MDTE will, in
the ordinary course, approve rates for the coming year before the
current year-end to allow the new rates to become effective the
first of January. Subsequently, the estimates for the prior year
are reconciled to the actual amounts for that year. The MDTE
reviews these costs and approves the amounts subject to any
required adjustments.
In December 2001, NSTAR Electric made filings containing proposed
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 has 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 or results of operations for the period ended December
31, 2001.
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. Reconciliation
proceedings for ComElectric and Cambridge Electric reflecting
costs and revenues for 1999 and 2000 remain open with hearings
not yet having taken place. Management is unable to determine
the outcome of the remaining MDTE proceedings. However, based
upon past procedures and on information currently available,
management does not believe that it is probable that the final
MDTE approval will have a material adverse impact on NSTAR's
consolidated financial position, results of operations and cash
flows.
In addition to the annual rate filings referenced above, NSTAR
Electric has also made interim filings with the MDTE concerning
charges for a standard offer fuel adjustment and for (market-
based) default service rates. NSTAR Electric has existing long-
term power purchase agreements that are expected to supply
approximately 90%-95% of its standard offer service obligations.
NSTAR Electric has entered into a series of power purchase
agreements to meet its entire default service supply obligations
and its remaining unmet standard offer supply obligations through
December 31, 2002. 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. At December 31, 2001,
approximately 29% of NSTAR Electric's customers were on default
service.
Natural Gas Industry Restructuring and Rates
Effective November 1, 2000, the MDTE approved regulations that
provide for full customer choice to LDCs (local gas distribution
companies) such as NSTAR Gas. 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 during a three-year transition period.
This eliminates potential stranded cost exposure for the LDCs
until they are relieved from their responsibility as suppliers of
last resort and the establishment of a "workably competitive"
interstate pipeline capacity market. Gas restructuring is not
likely to have a significant adverse financial impact on 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 all of the 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 December 2000 and in a revised filing in January 2001, NSTAR
Gas filed for interim increases to its CGAC for the period
February through April 2001 in order to recover significant
increases in the costs to buy natural gas supplies. These
filings were made to ensure that prices to customers are set at
levels that recover all incurred costs in order to avoid the
accumulation of significant under-recoveries that would impair
NSTAR Gas' ability to serve its customers. On January 31, 2001,
the MDTE approved an adjustment to increase the CGAC factor to
$1.1123 per therm from the prior factor of $0.7608 per therm.
Subsequently, on February 28, 2001, as a result of a decline in
wholesale natural gas prices, NSTAR Gas received approval from
the MDTE to reduce the factor per therm to $0.9372 effective
March 1, 2001, and in conjunction with its semi-annual filing
made on March 15, 2001, NSTAR Gas proposed a CGAC factor of
$0.7754 per therm for the period commencing May 1, 2001 through
October 31, 2001. This factor, approved by the MDTE, included
the collection in the summer period of a portion of the coming
winter's gas costs in order to reduce cost deferrals that were
projected for the end of October 2001. In October 2001, due to
the significant decline in wholesale natural gas prices, NSTAR
Gas received approval from the MDTE to reduce the CGAC factor for
the period from November 1, 2001 through April 30, 2002 to
$0.5261 per therm. In December 2001, NSTAR Gas received approval
to further reduce its CGAC factor by 17% to $0.4350 per therm
effective January 1, 2002. In January 2002, NSTAR Gas again
filed and the MDTE approved a reduction of the NSTAR Gas CGAC
factor that became effective February 1, 2002 to $0.3834 per
therm as a result of the continuing decline in its supply costs.
This represented a 59% decrease from the weighted average factor
in effect during the prior winter season.
Other Legal Matters
In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters. Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued. Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal costs that may result from changes
in estimates could have a material impact on the results for a
reporting period.
Other Matters
The September 11, 2001 terrorist attack that occurred in New York
City and in Washington, D.C., resulted in a tremendous loss of
life and property. This unfortunate incident has had
unprecedented pervasive negative impacts on several U.S.
industries and on the U.S. economy in general. While NSTAR was
not directly impacted by the event, the Company believes that it
could be impacted indirectly in the near future. The indirect
impacts may include lower revenues due to the negative impact on
certain of NSTAR's commercial and industrial customers and higher
costs related to items such as insurance and security.
Results of Operations
The following section of Management's Discussion and Analysis
compares the results of operations for each of the three fiscal
years ended December 31, 2001 and should be read in conjunction
with the consolidated financial statements and the accompanying
notes included elsewhere in this report.
2001 versus 2000
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,
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
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 Corporation (RCN). Factors that contributed to
the $3.5 million, or 2%, decline in earnings before the non-cash,
after-tax charge include a decline in firm gas sales (in billions
of British thermal units or BBTU) of 11%, a proposed refund of
$3.9 million to electric customers in conjunction with NSTAR's
service quality plan, the accrual of costs associated with a
pending shutdown of a district energy facility of $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
eleven cents.
As previously disclosed and further discussed in this report,
NSTAR is finalizing the process of converting its joint venture
investment in RCN into shares of RCN common stock. NSTAR's
investment in RCN includes 4.1 million common shares that it
currently holds and 7.5 million common shares that it expects to
receive 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. NSTAR
determined, in the first quarter of 2001, that this decline in
market value was "other-than-temporary" as defined by Statement
of Financial Accounting Standards (SFAS) No. 115, "Accounting for
Certain Investments in Debt and Equity Securities."
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 includes 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 number of retail customers increased in 2001 to
1,086,000 from 1,079,000 customers and represents a growth rate
of 0.7%. The customer growth rate in 2002 is projected to be an
additional 0.7%.
The 0.6% increase in 2001 retail kWh sales primarily reflects
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.
NSTAR forecasts its electric and gas sales based on normal
weather conditions. Forecasted results may differ from those
projected due to actual weather conditions above or below these
normal weather levels.
Weather conditions greatly impact the change in electric and, to
a larger extent, gas sales and revenues in NSTAR's service area.
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
Cooling degree days 822 588 678
Percentage change from prior year 39.8% (34.0)%
Percentage change from 30-year average 21.2% (13.3)%
Heating degree days 5,637 6,147 5,939
Percentage change from prior year (8.3)% 11.7%
Percentage change from 30-year average (5.1)% 3.5%
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 reflects increased
demand from a public transit authority and municipal contracts.
In 2002, wholesale electric sales are forecasted to decrease due
to the expiration of contracts with several municipalities. The
expiration of these contracts is not expected to impact NSTAR's
consolidated earnings.
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 is primarily attributable to the recovery of
prior period gas costs, partially offset by an 11% decline in
firm sales and transportation due to the economic slowdown in the
commercial and industrial sectors. NSTAR Gas' sales are
positively impacted by colder weather because a substantial
portion of its customer base uses natural gas for space heating
purposes. Conversely, warmer weather conditions have a negative
impact on gas sales. 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 8.3% below
2000 and 5.1% 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. The number of firm
customers increased in 2001 to 246,000 customers and represents a
growth rate of 0.8%. The customer growth rate in 2002 is
projected to be an additional 1.25%.
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 reflects higher New England Power Pool 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 reflects the impact of the recognition of
previously deferred standard offer and default service supply
costs resulting from collection of these costs in 2001. NSTAR
Electric adjusts its electric rates to collect the costs related
to energy supply from customers on a fully reconciling basis.
Due to the rate adjustment mechanisms, changes in the amount of
energy supply expense have no impact on earnings. 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 is 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 reflects 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 post-retirement and
other benefits. Offsetting this increase was the absence of non-
recurring computer system implementations costs incurred during
2000.
In 2002, operations and maintenance expense is forecasted to
increase significantly to support the utility System Improvement
Program of $11 million and increased pension costs. NSTAR has
forecasted that pension costs will increase by approximately $20
million for 2002 as compared to 2001. This is due to the
downturn in equity markets, which have reduced the value of
NSTAR's pension investments and the impact of lower interest
rates. This expected level of expense could vary due to external
factors beyond the Company's control.
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 reflects 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 a 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.
Demand side management (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 (Deductions), net
Other deductions were $169 million in 2001 compared to income of
$12.1 million in 2000, a net decrease in income of $181.1 million
primarily attributable to the aforementioned non-cash, after-tax
charge related to the carrying value of the RCN investment. This
is discussed further in this section under the caption "RCN Joint
Venture and Investment Conversion."
The decrease in other income, net for 2001 reflects the result of
income items recognized in 2000 related to a gain of $3.4 million
from the sale of land by a non-utility subsidiary, $4.4 million
received from a third party related to the Pilgrim wholesale
contract buyout and interest income on funds held by EIS of $7.6
million (EIS interest income in 2001 was $743,000 and these
amounts were offset entirely with interest charges). Offsetting
these gains in 2000 was the impact of NSTAR COM RCN joint venture
losses of $5.6 million and in 2001, $4.5 million of income
associated with the receipt of common stock in connection with
the demutualization of two insurance companies. These factors
were offset in 2001 by $3.8 million for the accrual of costs
associated with a pending shutdown of an unregulated district
energy facility.
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 includes $15.3 million that reflects
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 reflects the retirement of $199 million in Boston Edison
debt and the paydown of other subsidiary company debt of $7.4
million throughout 2000 as compared to retirements and paydowns
in 2001 of $24.3 million and $10.1 million, respectively. Long-
term debt interest in 2001 also reflects a reduction of
securitization certificates interest of $4 million due to the
partial retirement of this debt. 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.
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 is 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
includes the impact of higher average short-term borrowing levels
from banks. The increase in borrowing is 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.
2000 versus 1999
Consistent with the application of the purchase method of
accounting, the results for 2000 reflect the results of NSTAR for
a full year while the results for 1999 reflect eight months of
BEC and four months of NSTAR.
Basic and diluted earnings per common share were $3.19 and $3.18,
respectively, in 2000, compared to $2.77 and $2.76, respectively,
in 1999, a 15% increase. The dilutive impact on earnings of an
additional 4.1 million average common shares outstanding at year-
end 2000 ($0.26 per share) reflects shares issued to transact the
merger in 1999, partially offset by 5 million shares repurchased
in 2000 upon completion of a common share repurchase plan.
Operating Revenues
Operating revenues for 2000 increased 45% from 1999 as follows:
(in thousands)
Retail electric revenues $ 514,627
Wholesale electric revenues (30,704)
Gas sales revenues 261,585
Other revenues 95,827
Increase in operating revenues $ 841,335
=========
Retail electric revenues were $2,065.4 million in 2000 compared
to $1,550.8 million in 1999, an increase of $514.6 million, or
33%. The change in retail revenues reflects a full year of NSTAR
operations, the recognition of mitigation incentive revenue
entitlements for successfully lowering transition charges, the
higher costs of natural gas and oil as a component of purchased
power and the impact of a 25% increase in retail kWh sales
reflecting the addition of COM/Energy. On a combined pro-forma
basis as if BEC and COM/Energy were NSTAR for the entire year of
1999, retail kWh sales increased 3.3%. The increase in retail
kWh sales is the result of a strong local economy as indicated by
a 2.2% improvement in the overall Massachusetts employment rate,
new construction and customer growth. In addition, NSTAR
Electric increased its standard offer and default service rates
in January and December 2000. NSTAR Electric's standard offer
revenues were $616.4 million and $467.7 million in 2000 and 1999,
respectively. The revenues derived from standard offer and
default services are fully reconciled to the costs incurred and
have no impact on net income.
Wholesale electric revenues were $77.9 million in 2000, compared
to $108.6 million in 1999, a decrease of $30.7 million, or 28%.
This decrease in wholesale revenues primarily reflects the
absence of sales to Pilgrim contract customers due to the sale of
Pilgrim in July 1999.
Gas sales revenues were $368.7 million in 2000 compared to $107.1
million in 1999, an increase of $261.6 million, or 244%. The
increase represents NSTAR Gas operations for a full year. In
addition, on a comparable basis, the fourth quarter firm and
transportation BBTU gas sales were higher by 25% due to colder
weather. Heating degree days for the fourth quarter of 2000
totaled 2,246, 20% above the same period last year and 12%
greater than the normal level of 2,009. On a combined pro-forma
basis as if BEC and COM/Energy were NSTAR for the entire year of
1999, firm gas sales and transportation increased 15%.
Other revenues were $180.8 million in 2000 compared to $84.9
million in 1999, an increase of $95.9 million, or 113%. This
revenue increase primarily reflects non-utility district heating
and cooling energy sales operations in 2000 and higher
transmission revenues related to refunds to wholesale customers
in 1999 resulting from a FERC-approved settlement with
transmission contract customers.
Operating Expenses
Operating expenses for 2000 include a full year of expenses for
NSTAR, while the level of expenses for 1999 reflect eight months
of BEC Energy and four months of NSTAR.
Purchased power and cost of gas sold expense was $1,385.7 million
in 2000, compared to $794.7 million in 1999, an increase of $591
million, or 74%. The purchased power component of these costs
was $1,172.9 million in 2000 compared to $736.8 million in 1999,
an increase of $436.1 million, or 59%. The increase in 2000
primarily reflects a full year of NSTAR operations, an increase
in purchased power requirements due to the sale of Pilgrim in
1999, an overall increase in the cost of wholesale power and
increased requirements resulting from increased kWh sales and
firm gas sales. NSTAR Electric adjusts its rates to collect the
costs related to fuel and purchased power from customers on a
fully reconciling basis. Fuel and purchased power expenses
reflect a reduction of $212.7 million in 2000 and $67.3 million
in 1999 related to these rate recovery mechanisms. Due to the
rate adjustment mechanisms, changes in the amount of purchased
power expense have no impact on earnings. The cost of gas sold,
representing NSTAR Gas' supply expense, was $212.8 million in
2000 compared to $57.9 million in 1999, an increase of $154.9
million and is also fully reconciled.
Operations and maintenance expense was $415.8 million in 2000
compared to $353.8 million in 1999, an increase of $62 million,
or 18%. The increase primarily reflects a full year of NSTAR
operations that was partially offset by the absence of $70
million of nuclear power production expenses due to the sale of
Pilgrim. As a result of the merger, operations and maintenance
cost savings were realized due to reduced staffing levels and
operating efficiencies. In addition, NSTAR experienced
significantly lower costs for employee pensions and benefits in
2000.
Depreciation and amortization expense was $238.6 million in 2000
compared to $210.3 million in 1999, an increase of $28.3 million,
or 13%. The increase reflects approximately $23.2 million
resulting from a full year of amortization of goodwill and costs
to achieve related to the merger compared to $8 million in 1999
and approximately $13.4 million related to other amortization and
depreciation for a full year of NSTAR operations and capital
additions. These increases were partially offset by the sale of
Pilgrim in July 1999.
DSM and renewable energy programs expense was $78.8 million in
2000 compared to $63.4 million in 1999, an increase of $15.4
million, or 24% primarily due to a full year of NSTAR operations.
These costs are in accordance with program guidelines established
by the MDTE and are collected from customers on a fully
reconciling basis and therefore, fluctuations in program costs
have no impact on earnings. In addition, NSTAR earns incentive
amounts in return for increased customer participation.
Property and other taxes were $82.1 million in 2000 compared to
$77.8 million in 1999, an increase of $4.3 million, or 6%. The
increase is primarily due to a full year of NSTAR operations
partially offset by lower municipal property taxes primarily
related to the sale of Pilgrim.
Other Income (Deductions), net
Other income, net of taxes was $12.1 million in 2000 compared to
income of $8.1 million in 1999, a net increase in income of $4
million, or 49%. The increase in income in 2000 reflects
interest income on funds held by EIS of $7.6 million compared to
$2.8 million in the prior year. These amounts were offset
entirely with interest charges. Also, 2000 includes a gain of
$3.4 million from the sale of land by a non-utility subsidiary
and $4.4 million received from a third party related to the
Pilgrim wholesale contract buyout. Offsetting these factors in
2000 was the absence of $20.8 million related to the 1999
recognition of previously deferred investment tax credits
associated with the Pilgrim Unit that was sold in 1999. Also in
2000, the change in other income reflected significantly lower
NSTAR Com RCN joint venture losses which amounted to $5.6 million
in 2000 that reflected NSTAR Com's decreased ownership interest
compared to $16.2 million in 1999.
Interest Charges
Interest on long-term debt and transition property securitization
certificates was $154.8 million in 2000 compared to $104.6
million in 1999, an increase of $50.2 million, or 48%. The
increase reflects $25.1 million of interest related to transition
property securitization certificates issued in July 1999, $24.7
million related to the $500 million 8% Notes issued in February
2000 ($300 million) and in October 2000 ($200 million) and a full
year of NSTAR operations. These increases were partially offset
by approximately $12.3 million in reductions related to the
retirements as described in this section under the caption
"Liquidity and Capital Resources."
Interest on short-term and other obligations was $55.2 million in
2000 compared to $22.9 million in 1999, an increase of $32.3
million, or 141%. This increase is directly related to increases
in short-term borrowings, primarily the result of increases of
approximately $147 million in the unrecovered costs for standard
offer and default service during 2000 (to a balance of $242.7
million at December 31, 2000). In addition, 2000 reflects $7.5
million of interest costs associated with additional borrowing
used to finance deferred transition costs and $1.1 million on
deferred gas costs.
Allowance for borrowed funds used during construction (AFUDC)
amounted to $4.6 million in 2000 compared to $2.2 million in
1999, an increase of $2.4 million. This increase is primarily
related to capitalized interest associated with construction of
NSTAR's new office facility located in Westwood, Massachusetts
and the impact of a full year of NSTAR operations.
Liquidity and Capital Resources
During 2001, 2000 and 1999, internal generation of cash provided
103%, 188% and 174%, 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 2002 is $315 million,
which includes approximately $271 million for electric and gas
operations and the balance for other capital requirements of non-
utility ventures. Also, included in this level of spending is
$54 million of costs associated with NSTAR's System Improvement
Program. The capital spending level over the following four
years is forecasted to aggregate approximately $737 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, 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, 2001, for
each of the years presented below:
(in millions) 2002 2003 2004 2005 2006
Long-term debt $ 38 $ 173 $ 10 $ 9 $ 29
Transition property
securitization certificates 70 68 69 69 69
Leases 23 19 18 17 15
Electric capacity obligations 177 166 168 171 173
Gas contractual obligations 52 49 40 39 38
$ 360 $ 475 $ 305 $ 305 $ 324
====== ====== ====== ===== ======
In 2001, long-term debt 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, the early redemption of $24.3 million 9.375%
debentures, and other scheduled sinking fund payments. There
were no new long-term debt issuances in 2001. In February and
October 2000, NSTAR issued $300 million and $200 million,
respectively, 8% notes, due February 2010, of long-term debt
related to its $500 million shelf registration. Proceeds from
these issues were used to pay down short-term borrowings. These
increases in long-term debt were partially offset in 2000 by $206
million in long-term debt retirements, that included Boston
Edison debenture redemptions of $65 million (6.8% Series) in
February, $34 million (9.875% Series) in June and $100 million
(6.05% Series) in August.
NSTAR has a $450 million revolving credit agreement with a group
of banks effective through November 2002. At December 31, 2001
and 2000, there were no amounts outstanding under this revolving
credit agreement. This arrangement serves as back-up to NSTAR's
$450 million commercial paper program that, at December 31, 2001
and 2000, had $315.5 million and $252 million outstanding,
respectively, under its commercial paper program. NSTAR
anticipates renewing its revolving credit agreement under similar
terms.
Boston Edison has approval from the FERC to issue up to $350
million of short-term debt. Boston Edison has a $300 million
revolving credit agreement with a group of banks effective
through December 2002. At December 31, 2001 and 2000, there were
no amounts outstanding under this revolving credit agreement.
This arrangement serves as back-up to Boston Edison's $300
million commercial paper program that, at December 31, 2001 and
2000, had outstanding balances of $191.5 million and $96.5
million, respectively. Separately, Boston Edison, effective July
20, 2001, has an additional $50 million line of credit with no
outstanding amounts at December 31, 2001.
Boston Edison has approval from the MDTE to issue from time to
time up to $500 million of long-term debt securities through
2002. In connection with this, on February 20, 2001, Boston
Edison filed a registration statement on Form S-3 with the SEC,
using a shelf registration process, to issue up to $500 million
in debt securities. The SEC declared the registration statement
effective on February 28, 2001. When issued, Boston Edison will
use the proceeds to pay at maturity long-term debt and equity
securities, refinance short-term debt and for other corporate
purposes. No issuance of debt securities were made during 2001
under this authorization.
In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $190 million available under several lines of
credit. Approximately $118 million and $120 million was
outstanding under these lines of credit at December 31, 2001 and
2000, respectively. ComElectric, Cambridge Electric and Canal
have approval from FERC to issue short-term debt with amounts
ranging from $60 million to $100 million.
In April 1998, BEC announced a common share repurchase program
under which it would repurchase up to four million of its common
shares. NSTAR assumed this program effective as of the merger
date and completed it in October 1999. Four million shares were
repurchased at a total cost of approximately $157 million. NSTAR
subsequently announced a second common share repurchase program,
which began in November 1999, of $300 million that was completed
in September 2000 with the repurchase of approximately 7.2
million shares.
In July 1999, BEC Funding LLC, a wholly owned consolidated
special-purpose subsidiary (SPS) of Boston Edison, closed the
sale of $725 million of notes to a special purpose trust created
by two Massachusetts state agencies. The trust then concurrently
closed the sale of $725 million of electric rate reduction
certificates to the public. A portion of the transition charge
assessed to Boston Edison's retail customers, as permitted under
the Restructuring Act and authorized by the MDTE, secures the
certificates held by BEC Funding. The certificates were issued
in five separate classes with variable payment periods ranging
from approximately one to ten years and bearing fixed interest
rates ranging from 5.99% to 7.03%. The certificates are non-
recourse to Boston Edison. Net proceeds ($719 million received
by Boston Edison from BEC Funding) were utilized to finance a
portion of the stranded costs that are being collected from
customers under Boston Edison's restructuring settlement
agreement. Boston Edison will collect a portion of the
transition charge on behalf of BEC Funding and remit the proceeds
to the SPS. Boston Edison used a portion of the proceeds
received from the financing to fund a portion of the nuclear
decommissioning fund transferred to Entergy as part of the sale
of the Pilgrim generating station. Boston Edison used the
remaining proceeds to reduce its capitalization and for general
corporate purposes.
NSTAR's goal is to maintain a capital structure that preserves an
appropriate balance between debt and equity. Management believes
its liquidity and capital resources are sufficient to meet its
current and projected requirements.
Performance Assurances and Financial Guarantees
NSTAR Electric has entered into a series of purchased power
agreements to meet its default service supply obligations and its
remaining unmet standard offer supply obligations through
December 31, 2002. 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.
Preferred Stock Dividends and Redemptions
Preferred dividends of Boston Edison were approximately $5.6
million in 2001 and $6 million in both 2000 and 1999. 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. Effective December 1, 2001, the dividends on
this series ceased.
Other Investments
In the second quarter of 2001, NSTAR recorded $4.5 million as
Other income for equity securities it received in connection with
the demutualization of John Hancock Mutual Life Insurance Company
and MetLife, Inc. NSTAR and its subsidiaries, as policyholders,
received an appropriate distribution of common stock of each
company. These securities are currently available for sale and
are included in Other investments on the accompanying
Consolidated Balance Sheets. The value of these common shares
was adjusted to reflect market values as of December 31, 2001.
The unrealized gain or loss associated with these shares will
fluctuate due to changes in current market values and is
reflected, net of applicable income taxes, as a component of
Comprehensive income (loss) on the accompanying Consolidated
Statements of Comprehensive Income (Loss). The cumulative
increase or decrease in fair value of these shares as of December
31, 2001 is reflected as a component of Accumulated other
comprehensive income (loss) on the accompanying Consolidated
Balance Sheets.
New Accounting Principles
In June 2001, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standard (SFAS) No. 142,
"Goodwill and Other Intangible Assets" (SFAS 142). This
Statement, which is effective for NSTAR in the first quarter of
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 will be subject to
review for impairment. However, in accordance with paragraph
(d)8 of SFAS 142 and revised paragraph 30 of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation,"
NSTAR plans to continue amortization of this asset over its
estimated regulatory recovery period. NSTAR has determined that
its unique regulatory rate structure, resulting from the merger
and approved by the MDTE on July 27, 1999, requires continued
amortization of goodwill. A significant element of this rate
plan includes recovery of the acquisition premium over 40 years
and provides for the reasonable assurance of the existence of a
regulatory asset. NSTAR will determine the appropriate balance
sheet classification of this asset once adopted. Management will
continue to review its determination of SFAS 142.
On July 5, 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS 143). This Statement, which
is effective for fiscal years beginning after June 15, 2002,
establishes accounting and reporting 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. This standard 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. However, based on
NSTAR's assessment to date, the adoption of SFAS 143 is not
expected to have a material effect on its results of operations,
cash flows, or financial position.
As of January 1, 2001, NSTAR adopted SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133), as
amended by SFAS Nos. 137 and 138, and collectively referred to as
SFAS 133. SFAS 133 established accounting and reporting
standards requiring that every derivative instrument (including
certain derivative instruments embedded in contracts possibly
including fixed-price fuel supply and power contracts) be
recorded on the Consolidated Balance Sheets as either an asset or
liability measured at its fair value.
The management of NSTAR has assessed the impact of the adoption
of SFAS 133. As part of this assessment, NSTAR formed an
implementation team in 2000 consisting of key individuals from
various operational and financial areas of the organization. The
primary role of this team was to inventory and determine the
impact of potential contractual arrangements for SFAS 133
application. The implementation team performed extensive reviews
of critical operating areas of NSTAR and documented its
pro