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, 2000
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 principle executive offices) (Zip Code)
Registrant's telephone number, including area code: 617-424-2000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which
registered
Common Shares, Par Value $1 per New York Stock Exchange
share 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, 2001 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:
$2,079,671,291.
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 15,2001
Common Shares, $1 par value 53,032,546 Shares
Documents Incorporated by Reference Part in Form 10-K
Portions of the Registrant's Parts I, II and III
Definitive Proxy Statement Dated
March 23, 2001
(pages as specified herein)
NSTAR
Form 10-K Annual Report December 31, 2000
Page
Part I
Item 1. Business 2
Item 2. Properties 10
Item 3. Legal Proceedings 11
Item 4. Submission of Matters to a Vote of Security Holders 12
Item 4A. Executive Officers of the Registrant 13
Part II
Item 5. Market for the Registrant's Common Equity and
Related Stockholder Matters 14
Item 6. Selected Financial Data 15
Item 7. Management's Discussion and Analysis 15
Item 7A. Quantitative and Qualitative Disclosures About 33
Market Risk
Item 8. Financial Statements and Supplementary Financial 34
Information
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 66
Part III
Item 10. Trustees and Executive Officers of the Registrant 67
Item 11. Executive Compensation 67
Item 12. Security Ownership of Certain Beneficial Owners and 67
Management
Item 13. Certain Relationships and Related Transactions 67
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports 68
on Form 8-K
Part I
Item 1. Business
(a) General Development of Business
NSTAR is an energy delivery company serving approximately 1.3
million customers in Massachusetts including more than one
million electric customers in 81 communitites and 244,000 gas
customers in 51 communitites. NSTAR also supplies electricity at
wholesale for resale to municipalities. 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) and its
wholesale electric sudsidiary is Canal Electric Company (Canal
Electric). Effective November 1, 2000, NSTAR's three retail
electric companies began to 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 liquefied natural gas services (Hopkinton LNG
Corp.). Utility operations accounted for more than 97% of
revenues in both 2000 and 1999.
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. The demands have
resulted in an increasing trend in the industry to seek
competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new
marketplace by combining the resources of its utility
subsidiaries and concentrating its activities in the transmission
and distribution of energy.
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) in July 1999. The costs associated with the merger
consisting primarily of severance costs associated with a
voluntary separation program are expected to be offset by ongoing
future cost savings from streamlined operations and avoidance of
costs that would have otherwise been incurred by BEC and
COM/Energy. As a result of the merger, cost savings have been
realized due to reduced staffing levels and operating
efficiencies. 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 non-utility segments.
(c) Narrative Description of Business
Principal Products and Services
NSTAR ELECTRIC
NSTAR Electric operating revenues by class of customers for the
last three years consisted of the following:
2000 1999 1998
Retail electric revenues:
Commercial 47% 51% 51%
Residential 32% 30% 27%
Industrial 8% 9% 9%
Other 1% 1% 1%
Wholesale and contract revenues 12% 9% 12%
The results for 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 2.2
million. In 2000, NSTAR Electric served approximately 1.1
million customers.
Sources and Availability of Electric Power Supply
NSTAR Electric entered into various six-month agreements during
2000 to transfer substantially all of the unit output
entitlements in long-term power purchase contracts to suppliers,
who in turn provided full energy service to meet NSTAR Electric's
standard offer and default service load requirements.
NSTAR Electric entered into a six-month agreement effective
January 1, 2001 through June 30, 2001 with a supplier to provide
full default service energy and ancillary service requirements at
contract rates substantially similar to MDTE-approved tariff
rates. A default service request for proposal, applicable to the
second half of 2001, will be issued in early 2001. NSTAR
Electric's existing portfolio of power purchase contracts is
supplying the majority of its standard offer and wholesale energy
requirements, supplemented with long-term and daily
purchases/sales in the bilateral and spot markets. In addition,
NSTAR Electric is managing its Independent System Operator-New
England (ISO-New England) 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 Federal Energy
Regulatory Commission (FERC). Vermont Yankee has received the
approval of FERC to include charges for the estimated costs of
decommissioning its unit in the costs 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,
but this transaction was disapproved on February 14, 2001 by the
state of Vermont's regulatory authority.
Information relative to nuclear units that are no longer
operating in which NSTAR has an equity ownership is as follows:
Connecticut Maine Yankee
Yankee Yankee Atomic
(dollars in thousands)
Year of Shutdown 1996 1997 1992
Equity Ownership (%) 14 4 14
Equity Ownership Balance $ 10,409 $ 2,881 $ 1,078
New England Power Pool (NEPOOL)
During 1997, NEPOOL was restructured with changes taking effect
to the membership and governance provisions of the power pooling
agreement along with the transfer of operating responsibility of
the integrated transmission and generation system in New England
to ISO-New England. Previously, NEPOOL dispatched generating
units for operation based on the lowest operating costs of
available generation and transmission. Under the new structure,
generators will be required to provide ISO-New England with
market prices at which they will sell short-term energy supply.
These prices formed the basis for 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 will supply 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. It is
designed as a seven-year transitional service (from March 1,
1998) to give the customer time to learn about competitive power
suppliers. The price of standard offer service increases over
time. Default service is supplied by the local distribution
company when a customer is not eligible for standard offer
service or receiving power from a competitive power supplier.
The market price for default service will fluctuate based on the
average market price for power. Amounts collected through these
various charges are reconciled to actual expenditures on an on-
going 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 2000 and
1999 (effective September 1, 1999), consisted of the following:
2000 1999
Retail Gas revenues:
Residential 59% 61%
Commercial 24% 24%
Industrial 3% 4%
Other 8% 6%
Wholesale and contract revenues 6% 5%
Natural gas is distributed by NSTAR Gas to approximately 244,000
customers in 51 communities in central and eastern Massachusetts
covering 1,067 square miles and having an aggregate population of
1,128,000. 25 of these communities are also served by 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 supply areas to the final delivery points.
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. In November 2000, NSTAR Gas entered
into a five-month full services firm supply agreement with a
major marketer in order to more fully optimize its supply
portfolio. In June 2000, the MDTE approved various changes that
NSTAR Gas had made to its pipeline transportation and storage
portfolio. These changes enabled NSTAR Gas to reduce its overall
upstream portfolio cost while maintaining supply reliability.
In addition to firm transportation and gas supplies mentioned
above, NSTAR Gas utilizes contracts for underground storage and
LNG facilities to meet its winter peaking demands. The
underground storage contracts are a combination of existing and
new agreements that are the result of FERC Order 636 service
unbundling. The LNG facilities, described below, are used to
liquefy and store pipeline gas during the warmer months for use
during the heating season.
On November 17, 1995, the MDTE approved the NSTAR Gas Original
Alberta Northeast (ANE) Contract between NSTAR Gas and ANE for
the purchase of approximately 4.5 million cubic feet per day of
natural gas from Alberta, Canada. The MDTE approved the Gas
Sales Agreement between ANE Gas Limited and NSTAR Gas as filed on
March 3, 1999. Previous to the Agreement, NSTAR Gas purchased
its Canadian supply through Boston Gas Company. The agreement
allows NSTAR Gas to receive up to 4,500 MMBtu/day of Canadian
supply delivered into the Iroquois Gas Transmission system. In
compliance with this order, NSTAR Gas also signed transportation
agreements with the Tennessee Gas Pipeline and Iroquois Pipeline.
NSTAR Gas also transports gas on its distribution system for end-
users. As of December 31, 2000, there were approximately 725
commercial and industrial NSTAR GAS customers using
transportation service, accounting for 12,696 BBTU or
approximately 26% of total throughput. Effective November 1,
2000, with the MDTE's approval of NSTAR Gas' Transportation Terms
and Conditions, transportation service became available to all
system customers.
A portion of the 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 million
MCF of natural gas.
In addition, Hopkinton owns a satellite vaporization plant and
two above-ground cryogenic storage tanks located in Acushnet,
Massachusetts with an aggregate capacity of 500,000 MCF of
natural gas that are filled with LNG trucked from Hopkinton.
NSTAR Gas has contracts for LNG 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, LNG is
vaporized and placed in the distribution system of NSTAR Gas.
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 as a means to sell excess resources. Off-system sales
totaled 2,458 BBTU in 2000, while 36,810 BBTU of capacity was
sold in the capacity release market. NSTAR Gas retains 25% of
the gross 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 $189,000 and $294,000 in 2000
and 1999, respectively.
Natural Gas Industry Restructuring and Rates
In September 1997, NSTAR Gas along with other gas utilities
initiated the Massachusetts Gas Unbundling Collaborative (the
Collaborative) to explore and develop generic principles to
achieve the MDTE's goals of establishing choice of gas supplier
for all customers (comprehensive unbundling).
In August 1998, the MDTE approved the unbundled rate settlement
submitted by NSTAR Gas, followed in September with compliance
rates submitted by NSTAR Gas that were consistent with a
settlement agreement. These unbundled rates became effective on
November 1, 1998.
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 the margin on such service is returned to its
firm customers as cost reductions.
In addition to delivery services 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 late 1998, the MDTE issued an order establishing rules and
regulations governing the unbundling of retail gas service to all
customers in Massachusetts. Prior to this, only commercial and
industrial customers were able to obtain competitive gas supply
service from a source other than the local distribution company
(LDC) such as NSTAR Gas. These regulations are similar to those
adopted by the MDTE governing electric restructuring. 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. In addition, the MDTE has standardized the
eligibility requirements for low-income rates for all LDCs that
are identical to previously established requirements for electric
customers. In February 1999, the MDTE issued an order requiring
the mandatory assignment of the LDC's upstream pipelines 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. In January
2000, the MDTE approved the Model Terms and Conditions submitted
by the LDCs that provided the framework for implementing the
regulations. In October 2000, the MDTE approved compliance Terms
and Conditions submitted by NSTAR Gas and other LDCs that
implement the unbundling of retail gas services to all customers.
With the issuance of these orders and regulations, the MDTE moved
the date for full customer choice to November 1, 2000. NSTAR Gas
has modified its billing, customer and gas supply systems to
accommodate full retail choice. As a result of these orders, gas
restructuring is likely to have no significant financial impact
on LDCs.
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 accounts for its Class A 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. 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, natural gas, steam and
other forms of energy, have powers incidental thereto and are
entitled to all the rights and privileges of and subject to the
duties imposed upon electric and natural gas companies under
Massachusetts laws. The locations in public ways for electric
transmission and distribution lines or gas distribution are
obtained from municipal and other state authorities which, in
granting these locations, act as agents for the state. In some
cases the actions of these authorities is subject to appeal to the
MDTE. The rights to these locations are not limited in time, but
are not vested and are subject to the action of these authorities
and the legislature. Pursuant to the 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, long-term debt
maturities and preferred stock redemption requirements for the
years 2001 through 2005 are as follows:
2001 2002 2003 2004 2005
(in thousands)
Capital expenditures (1) $295,300 $187,900 $163,700 $181,100 $136,900
Long-term debt $ 45,619 $108,836 $241,168 $ 78,659 $ 77,559
Preferred stock $ 50,000 $ - $ - $ - $ -
(1) Includes both plant expenditures and capital requirements of
non-utility ventures.
Management continuously reviews its capital expenditure and
financing programs. These programs and, therefore, the estimates
included in this Form 10-K are subject to revision due to changes
in regulatory requirements, environmental standards, availability
and cost of capital, interest rates and other assumptions.
Plant expenditures in 2000 were $182.7 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 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 2000 and 1999. 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 Other Matters - Environmental section in
Item 7, "Management's Discussion and Analysis" for more
information.
Environmental-related capital expenditures for the years 2000 and
1999 were $4.5 million and $0.6 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, 2000, NSTAR's subsidiaries had approximately
3,300 full-time employees, including approximately 2,300 or 70%
of employees represented by nine collective bargaining units
covered by separate contracts. In 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 2,000 NSTAR Electric and
Gas employees and one five-year contract expiring May 15, 2005
that will replace seven separate and widely diverse agreements.
The other remaining collective bargaining unit contract expires
March 31, 2002. Management believes it has satisfactory
employees relations.
(d) Financial Information about Foreign and Domestic Operations
and Export Sales
None of NSTAR's subsidiaries have any foreign operations or
export sales.
Item 2. Properties
Substantially all of NSTAR's 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,
still retains 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, 2000, the NSTAR Electric transmission and
distribution system consisted of 17,078 pole miles of overhead
lines, 10,867 cable miles of underground lines, 287 substations
and 1,112,000 active customer meters.
The principal natural gas properties consist of distribution
mains, services and meters necessary to maintain reliable service
to customers. At December 31, 2000, the gas system included
2,884 miles of gas distribution lines, 173,247 services and
251,919 customer meters together with the necessary measuring and
regulating equipment. In addition, NSTAR owns a liquefaction and
vaporization plant, a satellite vaporization plant and above-
ground cryogenic storage tanks having an aggregate storage
capacity equivalent to 3.5 million MCF of natural gas. NSTAR Gas
owns an office and service building in Southborough,
Massachusetts, five district office buildings and several natural
gas receiving and take stations.
NSTAR Electric's high-tension transmission lines are generally
located on land either owned or subject to easements in its
favor. Its low-tension distribution lines are located
principally on public property under permission granted by
municipal and other state authorities.
In completion of its corporate facilities consolidation, NSTAR is
constructing 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 will house central
corporate offices including finance, human resources, sales,
engineering, information technology, and customer care. NSTAR
expects to consolidate more than a third of its workforce into
the building during the third quarter of 2001.
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.
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 MDTE order approving the Boston Edison electric restructuring
settlement agreement was appealed by certain parties to the
Massachusetts Supreme Judicial Court (SJC). One appeal remains
pending. However, there has to date been no briefing, hearing or
other action taken with respect to 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.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE,
the Massachusetts Attorney General contested cost allocations
related to Boston Edison's wholesale customers since 1998.
Management is unable to determine the outcome of the MDTE
proceedings. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on NSTAR's consolidated
financial position, cash flows and the results of operations in
the near term.
In October 1997, the MDTE opened a proceeding to investigate
Boston Edison's compliance with a 1993 order that permitted the
formation of Boston Edison Technology Group and authorized Boston
Edison to invest up to $45 million in non-utility activities.
Hearings were completed during 1999 and no further developments
have occurred at this time. Management is currently unable to
determine the timing of and 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 results of
operations for a reporting period.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of
Pilgrim Station, filed suit against Boston Edison. The town
claimed that Boston Edison wrongfully failed to execute an
agreement with the town for payments in addition to or in lieu of
taxes due to the town under the Restructuring Act. Boston Edison
and the town settled the suit and agreed in March 1999 on a 15-
year, $141 million payment as required by the Restructuring Act.
Payments in each of the first four years are approximately $15
million after which payments gradually decline. All payments
under this agreement will be recovered from customers through the
transition charge.
In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters. Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued. Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal costs that may result from a
change in estimates could have a material impact on the results
of a reporting period in the near term.
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 2000.
Item 4A. Executive Officers of Registrant
Identification of Executive Officers
Age
Name of Officer Position and Business Experience December 31,
2000
Thomas J. May Chairman of the Board, Chief 53
Executive Officer and a
Director/Trustee (since 1999),
NSTAR and its subsidiaries;
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 Financial
Companies, Inc.; Liberty Mutual
Insurance Company; New England
Business Services, Inc. and RCN
Corporation.
Russell D. Wright President, Chief Operating Officer 54
and a Director/Trustee (since
1999), NSTAR and its subsidiaries;
formerly President, and Chief
Executive Officer and a Trustee
(1998-1999), Commonwealth Energy
System; and President, Chief
Operating Officer and a Director
(1993-1998), Commonwealth Energy
System's operating subsidiaries;
Director, Reed and Barton.
Deborah A. Executive Vice President-Customer 42
McLaughlin Care/Shared Services, NSTAR (since
1999); President and Chief
Operating Officer, Commonwealth
Energy System's operating
subsidiaries (1998-1999); Vice
President - Customer Service,
Commonwealth Energy System's
operating subsidiaries (1993-
1998).
Douglas S. Horan Senior Vice President/Strategy, 50
Law & Policy, Clerk and General
Counsel, NSTAR (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 44
and Chief Financial Officer, NSTAR
(since 2000); formerly Senior Vice
President and Chief Financial
Officer, NSTAR (1999-2000); Senior
Vice President-Corporate Services
and Treasurer, BEC Energy (1998-
1999); Senior Vice
President-Corporate Services and
Treasurer, Boston Edison Company
(1995-1999).
Age
December
Name of Officer Position and Business Experience 31,
2000
Joseph R. Nolan, Senior Vice President - Corporate 37
Jr. Relations, NSTAR (since 2000);
formerly Vice President of
Government Affairs, NSTAR (1999-
2000); Director of Regulatory
Relations, BEC Energy (1998-1999);
Manager of Legislative Affairs,
Boston Edison Company (1994-1998);
Robert J. Weafer, Vice President, Controller and 53
Jr. Chief Accounting Officer, NSTAR
(since 1999), 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.
The high and low market value per common share as reported in the
Wall Street Journal for each of the quarters in 2000 and 1999 was
as follows. (Prior to September 1999, the information listed
refers to BEC Energy common shares.)
2000 1999
High Low High Low
First quarter $47.00 $38.25 $41.1875 $36.4375
Second quarter $46.125 $40.375 $44.625 $37.1875
Third quarter $44.5625 $39.00 $43.3125 $36.75
Fourth quarter $43.1875 $36.375 $42.375 $36.625
(b) Holders
As of December 31, 2000, there were 32,635 holders of NSTAR
common shares.
(c) Dividends
Dividends declared per common share for each of the quarters in
2000 and 1999 were as follows. (Prior to September 1999, the
information listed refers to BEC Energy common shares.)
2000 1999
First quarter $0.500 $0.485
Second quarter $0.500 $0.485
Third quarter $0.500 $0.485
Fourth quarter $0.515 $0.500
Item 6. Selected Financial Data
The following table summarizes five years of selected
consolidated financial data (in thousands, except per share
data). Prior to September 1999, the information below refers to
BEC Energy.
2000 1999(b) 1998 1997 1996
Operating revenues $2,699,506 $1,851,427 $1,622,515 $1,778,531 $1,668,856
Net income $ 180,962 $ 146,463 $ 141,046 $ 144,642 $ 141,546
Earnings per share
of common stock:
Basic $ 3.19 $ 2.77 $ 2.76 $ 2.71 $ 2.61
Diluted $ 3.18 $ 2.76 $ 2.75 $ 2.71 $ 2.61
Total assets $5,569,514 $5,466,143 $3,204,036 $3,622,347 $3,729,291
Long-term debt (a) $1,440,431 $ 986,843 $ 955,563 $1,057,076 $1,058,644
Transition property
securitization
certificates (a) $ 584,130 $ 646,559 $ - $ - $ -
Redeemable preferred
stock (a) $ 43,000 $ 92,279 $ 92,040 $ 163,093 $ 203,419
Cash dividends
declared per
common share $ 2.015 $ 1.955 $ 1.895 $ 1.880 $ 1.880
(a) Excludes the current portion of long-term debt or preferred
stock.
(b) 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)
Earnings Basic
Available Earnings
Operating Operating Net for Common Per Average
Revenue Income Income Shareholders Common Share(a)
(in thousands, except earnings per share)
2000
First quarter $ 665,262 $ 79,401 $ 37,099 $ 35,609 $ 0.62
Second quarter $ 630,194 $ 76,955 $ 32,928 $ 31,438 $ 0.57
Third quarter $ 709,519 $ 127,158 $ 66,286 $ 64,796 $ 1.21
Fourth quarter $ 694,531 $ 106,556 $ 44,649 $ 43,159 $ 0.81
1999
First quarter $ 371,870 $ 43,729 $ 19,562 $ 18,072 $ 0.38
Second quarter $ 379,290 $ 58,669 $ 36,253 $ 34,763 $ 0.76
Third quarter $ 517,151 $ 85,022 $ 68,260 $ 66,770 $ 1.32
Fourth quarter $ 583,116 $ 76,278 $ 22,388 $ 20,898 $ 0.35
(a) The sum of the quarters 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
NSTAR is an energy delivery company serving approximately 1.3
million customers in Massachusetts including more than one
million electric customers in 81 communities and 244,000 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) and its wholesale electric subsidiary is Canal
Electric Company (Canal Electric). Effective November 1, 2000,
NSTAR's three retail electric companies began to 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 liquefied natural gas
services (Hopkinton LNG Corp.). Utility operations accounted for
more than 97% of revenues in both 2000 and 1999.
The electric and natural gas industries have continued to change
in response to legislative, regulatory and marketplace demands
for improved customer service at lower prices. These demands have
resulted in an increasing trend in the industry to seek
competitive advantages and other benefits through business
combinations. NSTAR was created to operate in this new
marketplace by combining the resources of its utility
subsidiaries and concentrating its activities in the transmission
and distribution of energy. The 1997 Massachusetts Electric
Restructuring Act (Restructuring Act) required all electric
utilities to divest their generating assets and leave the retail
power supply business, in exchange for the right to recover all
non-mitigable stranded costs associated with the creation of
customer choice and competition.
Merger of BEC Energy and Commonwealth Energy System
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 Telecommunications
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 of this
Discussion and Analysis for more information.
The merger was accounted for by NSTAR as an acquisition of
COM/Energy by BEC under the purchase method of accounting.
Goodwill 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. A majority of
costs to achieve the merger have been for 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 expected
to be offset by ongoing future cost savings from streamlined
operations and avoidance of costs that would have otherwise been
incurred by BEC and COM/Energy.
As a result of the merger, cost savings have been realized due to
reduced staffing levels and operating efficiencies.
Generating Assets Divestiture
On October 26, 2000, the MDTE approved the filing made by
Cambridge Electric and ComElectric (together, "the Companies")
for the partial buydown of their contract with Canal Electric for
power from the Seabrook nuclear generating facility (Seabrook
Contract). The buydown transaction was effected by means of an
amendment to the Seabrook Contract. On November 8, 2000, $120.5
million of funds held by an affiliate, Energy Investment
Services, Inc. (EIS), were transferred to ComElectric and
Cambridge Electric in the amount of $113.4 million and $7.1
million, respectively. EIS was established as the vehicle to
invest the net proceeds from the sale of the generation assets.
The Companies, in turn, have reduced their respective future
stranded costs to be recovered from customers. In addition,
Cambridge Electric also made a $21.1 million payment to Canal
Electric as a further buydown of its share of the Seabrook
Contract with after-tax proceeds received from the sale of
Cambridge Electric's Kendall Station in December 1998. Approval
of a November 1, 2000 buydown amount is pending at the MDTE.
The impact of these transactions is reflected on the accompanying
Consolidated Balance Sheets at December 31, 2000 as reductions in
Restricted cash and Regulatory assets.
Canal Electric also made a filing with the Federal Energy
Regulatory Commission (FERC) to amend the Seabrook Contract to
reflect the buydown effective November 1, 2000. Action by the
FERC on this filing is pending.
In 1998, Boston Edison completed the sale of all of its fossil
generating assets. The amount received above net book value on
the sale of these assets is being returned to retail customers
over approximately 11 years.
To complete its divestiture of generating assets, Boston Edison
sold its Pilgrim Nuclear Generating Station (Pilgrim) in July
1999 for $81 million to Entergy Nuclear Generating Company
(Entergy). As part of the sale, Boston Edison, the first company
in the nation to successfully sell a nuclear facility,
transferred approximately $228 million in decommissioning funds
to Entergy. Entergy, by contract, assumed all future liability
related to the ultimate decommissioning of the plant. The
difference between the total proceeds from the sale and the net
book value of the Pilgrim assets, plus the net amount to fully
fund the decommissioning trust, is included in Regulatory assets
on the accompanying Consolidated Balance Sheets as such amounts
are currently being collected from customers.
Also in 1998, COM/Energy sold substantially all of its fossil
generating assets. As part of an agreement with the MDTE,
COM/Energy established EIS. Both the principal amount and income
earned were used to reduce the stranded costs that would
otherwise be billed to customers of the Companies. The net
proceeds were classified as Restricted cash on the accompanying
Consolidated Balance Sheets for 2000 and 1999.
Securitization of Boston Edison's Transition Charge
On July 27, 1999, BEC Funding LLC, a wholly owned special-purpose
subsidiary of Boston Edison, closed the sale of $725 million of
notes to a special purpose trust created by two Massachusetts
state agencies. The trust then concurrently closed the sale of
$725 million of electric rate reduction certificates in a public
offering. The certificates are secured by a portion of the
transition charge assessed on Boston Edison's retail customers as
permitted under the Restructuring Act and authorized by the MDTE.
These certificates are non-recourse to Boston Edison.
Retail Electric Rates
As a result of the Restructuring Act, standard offer customers of
the retail electric subsidiaries of NSTAR currently pay rates
that are 15% lower, on an inflation-adjusted basis, than rates in
effect prior to March 1, 1998, the retail access date.
All distribution customers must pay a transition charge as a
component of their rate. The purpose of the transition charge is
to allow for the collection of generation-related costs that
would not be collected in the competitive energy supply market.
The plant and regulatory asset balances that will be recovered
through the transition charge until 2009 were approved by the
MDTE.
The Restructuring Act requires electric distribution companies to
obtain and resell power to retail customers that choose not to
buy energy from a competitive energy supplier. This is 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 previously existing customers that are no
longer eligible for the standard offer service and have not
chosen to receive service from a competitive supplier are
provided "default service." The price of default service is
intended to reflect the average competitive market price for
power. NSTAR Electric has existing long-term power purchase
contracts. These long-term contracts will supply approximately
90%-95% of its standard offer service obligations. NSTAR Electric
has entered into six-month and shorter term agreements to meet
the remaining standard offer service obligation and continues to
evaluate further proposals. In November 2000, NSTAR Electric
entered into power purchase agreements to meet all of its default
service supply obligation for the period January through June of
2001. NSTAR Electric expects to continue periodic market
solicitations for default service power supply consistent with
provisions of the Restructuring Act and MDTE orders. The cost of
providing standard offer and default service, which includes
purchased power costs, is recovered from customers on a fully
reconciling basis.
NSTAR Electric's accumulated cost to provide default and standard
offer service is in excess of the revenues it has been allowed to
bill as of December 31, 2000. As a result, NSTAR has recorded, at
December 31, 2000, a regulatory asset of approximately $242.7
million that is reflected as a component of Current assets on the
accompanying Consolidated Balance Sheets. At December 31, 1999,
costs incurred in excess of revenues collected amounted to $95.7
million and were reflected as a non-current Regulatory asset.
Under applicable restructuring plans or settlements approved by
the MDTE, NSTAR Electric must, on an annual basis, file proposed
adjustments to its rates for the upcoming year along with a
proposed reconciliation of prior year revenues and costs for its
standard offer, default service, transmission and transition
charges. NSTAR Electric made such a filing with the MDTE in the
Fall of 1999. The MDTE subsequently approved proposed rate
adjustments effective January 1, 2000, and conducted further
hearings for the purpose of reconciling prior year's costs and
revenues related to NSTAR Electric's transition and transmission
charges and the charges for standard offer and default service.
In each such proceeding, certain cost allocations and other
related issues have been contested; however, the MDTE has not yet
rendered a final decision. In November 2000, NSTAR Electric made
a similar filing containing proposed rate adjustments for 2001,
including a reconciliation of costs and revenues through 1999.
The MDTE has approved rate adjustments effective January 1, 2001,
but it has not yet ruled on the reconciliation component of NSTAR
Electric's filings. Management is unable to determine the outcome
of the MDTE proceedings. However, if an unfavorable outcome were
to occur, there could be a material adverse impact on NSTAR's
consolidated financial position, results of operations and cash
flows in the near term.
In addition to the annual rate filings referenced above, NSTAR
Electric has also made separate filings with the MDTE concerning
charges for standard offer and default service. NSTAR Electric
has filed with the MDTE a request for approval to increase its
standard offer service rates for 2001 based on a fuel adjustment
formula contained in its standard offer tariffs that reflects the
prices of natural gas and oil. On December 11, 2000, the MDTE
approved an increase in standard offer rates of 1.321 cents per
kWh for NSTAR Electric. The MDTE ruled that these fuel
adjustments did not have to meet the 15% rate reduction
requirement under the Restructuring Act. The MDTE will re-examine
these rates in July 2001. On October 19, 2000, the MDTE approved
NSTAR Electric's request to increase the price of default service
to 6.28 cents per kWh, effective December 1, 2000. On November 9,
2000, NSTAR Electric filed a request with the MDTE for an
additional increase for default service to reflect market costs
for the period January 1, 2001 through June 30, 2001. On December
4, 2000, the MDTE approved market-based default service rates
covering this period. These and future prices for default service
are based upon market solicitations for power supply for default
service consistent with provisions of the Restructuring Act and
MDTE orders.
Under its restructuring settlement agreement, Boston Edison's
distribution business was subject to an annual minimum and
maximum return on average common equity (ROE) through December
31, 2000. The ROE was subject to a floor of 6% and a ceiling of
11.75%. If the ROE was below 6%, Boston Edison was authorized to
add a surcharge to distribution rates in order to achieve the 6%
floor. If the ROE was above 11%, it was required to adjust
distribution rates by an amount necessary to reduce the
calculated ROE between 11% and 12.5% by 50%, and a return above
12.5% by 100%. No adjustment was made if the ROE was between 6%
and 11%. In addition, distribution rates continue to be subject
to adjustment for any changes in tax laws or accounting
principles that result in a change in costs of more than $1
million. No adjustments have been made to Boston Edison's
distribution rates due to either one of these mechanisms.
Natural Gas Industry Restructuring and Rates
In late 1998, the MDTE issued an order establishing rules and
regulations governing the unbundling of retail gas service to all
customers in Massachusetts. Prior to this, only commercial and
industrial customers were able to obtain competitive gas supply
service from a source other than the local distribution company
(LDC) such as NSTAR Gas. These regulations are similar to those
adopted by the MDTE governing electric restructuring. 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. In addition, the MDTE has standardized the
eligibility requirements for low-income rates for all LDCs that
are identical to previously established requirements for electric
customers. In February 1999, the MDTE issued an order 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. In January
2000, the MDTE approved the Model Terms and Conditions submitted
by the LDCs that provided the framework for implementing the
regulations. In October 2000, the MDTE approved compliance Terms
and Conditions submitted by NSTAR Gas and other LDCs that
implement the unbundling of retail gas services to all customers.
With the issuance of these orders and regulations, the MDTE moved
the date for full customer choice to November 1, 2000. NSTAR Gas
has modified its billing, customer and gas supply systems to
accommodate full retail choice. As a result of these orders, gas
restructuring is likely to have no significant financial impact
on LDCs.
Results of Operations
2000 versus 1999
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.
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 in earnings per share. 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 the most
recent common share repurchase plan.
Operating Revenues
Operating revenues increased 46% from 1999 as follows:
(in thousands)
Retail revenues $ 514,627
Wholesale revenues (30,691)
Other revenues 94,214
Gas revenues 269,929
Increase in operating revenues $ 848,079
===========
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 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 service 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 $108.5 million in 1999, a decrease of $30.6 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.
Other revenues were $178.2 million in 2000 compared to $84
million in 1999, an increase of $94.2 million, or 112%. 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.
Gas revenues were $378 million in 2000 compared to $108.1 million
in 1999, an increase of $269.9 million, or 250%. The increase
represents NSTAR Gas operations for a full year. In addition, on
a comparable basis, the fourth quarter firm and transportation
sales were higher by 25% due to colder weather. Heating degree
days for the fourth quarter totaled 2,369, 19% above the same
period last year and 6% greater than the normal level of 2,242.
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%.
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 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.
NSTAR Gas' sales are positively impacted by colder weather
because a substantial portion of its customer base uses natural
gas for space heating purposes.
In December 2000 and in a revised filing in January 2001, NSTAR
Gas filed for interim increases to its CGAC charges 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 or a significant portion of
incurred costs in order to avoid the accumulation of significant
under-recoveries that would impair NSTAR Gas' ability to serve
its customers. NSTAR Gas estimated that without this adjustment,
it would under-collect approximately $50 million of gas supply
costs by the end of the current winter heating season. On January
31, 2001, the MDTE approved an adjustment to increase the cost of
gas to $1.1123 per therm from the prior charge of $0.7608 per
therm. Subsequently, on February 28, 2001, as a result of a
recent decline in wholesale natural gas prices, NSTAR Gas
received approval from the MDTE to reduce the rate per therm to
$0.94 effective March 1, 2001.
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, fuel and cost of gas sold expense was $1,390.7
million in 2000, compared to $794.7 million in 1999, an increase
of $596 million, or 75%. 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 fuel and
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 $414.3 million in 2000
compared to $353.8 million in 1999, an increase of $60.5 million,
or 17%. 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 have been 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 $223.5 million in 2000
compared to $210.3 million in 1999, an increase of $13.2 million,
or 6%. 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.
Demand side management (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. In accordance with the
restructuring legislation and the settlement agreement, these
costs are collected from customers on a fully reconciling basis.
Therefore, the increase has no impact on earnings.
Property and other taxes were $78.7 million in 2000 compared to
$77.8 million in 1999, an increase of $0.9 million, or 1%. 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 (Expense), net
Other expense, net of taxes was $3.7 million in 2000 compared to
income of $8.1 million in 1999, a net decline in income of $11.8
million, or 146%. The decline in income in 2000 reflects the
absence of $20.8 million related to the 1999 recognition of
previously deferred investment tax credits associated with the
Pilgrim station that was sold in 1999. In 2000, the change in
other income consisted primarily of lower NSTAR Communications,
Inc. (NSTAR Com) joint venture losses amounting to $5.6 million
as a result of NSTAR Com's decreased ownership interest compared
to an equity loss of $16.2 million in 1999. In addition, the
change 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.
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% bonds 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
following retirements: $65 million of 6.80% debentures in
February 2000, $34 million of 9.875% debentures in June 2000 and
$100 million of 6.05% debentures in August 2000.
Interest on short-term 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 in the
unrecovered cost of standard offer and default service during
2000 of approximately $147 million. 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.
1999 versus 1998
Due to the application of the purchase method of accounting, the
results for 1999 reflect eight months of BEC and four months of
NSTAR. Results for 1998 only reflect BEC.
Basic and diluted earnings per common share were $2.77 and $2.76,
respectively, in 1999 compared to $2.76 and $2.75, respectively,
in 1998, a 0.4% increase in earnings per share.
Operating Revenues
Operating revenues increased 14% from 1998 as follows:
(in thousands)
Retail electric revenues $ 175,708
Wholesale revenues (33,480)
Other revenues (21,433)
Gas revenues 108,117
Increase in operating revenues $ 228,912
=======
Retail electric revenues were $1,550.8 million in 1999 compared
to $1,375.1 million in 1998, an increase of $175.7 million, or
13%. The change in 1999 reflects an increase of $163.3 million
representing four months of revenues from the former COM/Energy
retail electric subsidiaries from the date of the merger. Without
the impact of the merger, retail revenues would have been
$1,387.5 million in 1999, an increase from 1998 of $12.4 million,
or 1%. This change reflects greater retail kWh electric sales
that were partially offset by a decrease in retail revenues
reflecting the impact of the 10% reduction in retail rates
mandated by the Restructuring Act initially implemented in March
1998, and an additional 5% rate reduction effective September 1,
1999.
Retail kWh sales increased 18% in 1999. This increase includes an
increase of 12% representing four months of sales by the former
COM/Energy subsidiaries from the date of the merger. Without the
impact of the merger, 1999 kWh sales would have increased 5% from
1998. This increase in retail kWh sales was primarily due to
weather conditions that favored electric sales as well as a
continued strong local economy and an increase in the number of
customers. The commercial sector represents approximately 50% of
electric operating revenues. The commercial sales increase was
partially the result of economic growth as indicated by a 2%
increase in the Massachusetts employment rate and increased hotel
occupancy rates in the Boston area.
Wholesale electric revenues were $108.5 million in 1999 compared
to $142 million in 1998, a decrease of $33.5 million, or 24%.
Offsetting this decrease in 1999 was an increase of $6.1 million
representing four months of revenues from the former COM/Energy
subsidiaries from the date of the merger. Without the impact of
the merger, wholesale revenues would have been $102.4 million, a
decrease from 1998 of $39.6 million, or 28%. This decline was
primarily the result of a decrease of $37 million reflecting the
absence of sales to Pilgrim contract customers due to a scheduled
1999 refueling and maintenance outage and subsequent sale of the
Pilgrim station in July 1999.
Other revenues were $84 million in 1999 compared to $105.4
million in 1998, a decrease of $21.4 million, or 20%. 1999
reflects an increase of $31.4 million representing four months of
revenues from the former COM/Energy subsidiaries from the date of
the merger. Without the impact of the merger, short-term and
other revenues would have been $52.6 million in 1999, a decrease
from 1998 of $52.8 million, or 50%. The decrease reflects $20
million of revenue received in 1998 as a result of support of
standard offer service by Boston Edison's fossil generating
stations prior to divestiture. The decline in short-term sales
revenue of $35 million was consistent with the decrease in short-
term kWh sales. Under agreements with Select Energy, a subsidiary
of Northeast Utilities, NSTAR Electric is only purchasing enough
power to meet obligations to its retail and wholesale customers.
Gas revenues were $108.1 million in 1999, representing four
months of revenues from NSTAR Gas from the date of the merger.
Operating Expenses
Operating expenses include the additional expenses associated
with the merger of COM/Energy for four months in 1999. 1998
reflects expenses of only BEC.
Purchased power, fuel and cost of gas sold expense was $794.7
million in 1999 compared to $567.8 million in 1998, an increase
of $226.9 million, or 40%. 1999 reflects an increase of $151.2
million representing four months of expenses from the former
COM/Energy subsidiaries from the date of the merger. Without the
impact of the merger, purchased power, fuel and cost of gas sold
would have been $643.5 million in 1999, an increase from 1998 of
$75.7 million, or 13%. Purchased power expense increased $91
million reflecting the increase in Boston Edison's purchased
power requirements due to the 1999 Pilgrim refueling outage and
its sale. NSTAR Electric adjusts its rates to collect the costs
related to fuel and purchased power from customers on a fully
reconciling basis. Boston Edison's fuel and purchased power
expense reflects a reduction of $56 million in 1999 and $128
million in 1998 related to these rate recovery mechanisms. Due to
rate adjustment mechanisms, changes in the amount of fuel and
purchased power expense have no impact on earnings. The fuel
expense related to Boston Edison's fossil generation units
decreased $66 million reflecting the divestiture of those units
in May 1998. Fuel expense related to Pilgrim decreased $17
million due to the 1999 refueling outage and the sale of the
plant in July 1999.
Operations and maintenance expense was $353.8 million in 1999
compared to $382.4 million in 1998, a decrease of $28.6 million,
or 7%. 1999 reflects an increase of $73.7 million representing
four months of expenses from the former COM/Energy subsidiaries
from the date of the merger. Without the impact of the merger,
operations and maintenance expense would have been $280.1 million
in 1999, a decrease from 1998 of $102.3 million, or 27%. This
reflects a decrease of $70 million of nuclear power production
expenses due to the deferral of costs related to the 1999
refueling outage and the ultimate sale of the Pilgrim plant in
July 1999, and a decrease of $22 million in fossil-fuel related
power production expenses due to the fossil generation
divestiture in May 1998. In addition, 1999 reflects a decrease of
$9 million in expenses reflecting the discontinued operations of
two unregulated subsidiaries.
Depreciation and amortization expense was $210.3 million in 1999
compared to $195.6 million in 1998, an increase of $14.7 million,
or 8%. 1999 reflects an increase of $18.7 million representing
four months of expenses from the former COM/Energy subsidiaries
from the date of the merger. Without this impact, depreciation
and amortization would have been $191.6 million in 1999, a
decrease from 1998 of $4 million, or 2%. This decrease reflects
the amortization of the gain on the sale of the fossil plants
that began in June 1998. These decreases are partially offset by
an increase of $8 million resulting from the amortization of
goodwill and costs to achieve related to the merger and an
increase of $11 million reflecting a reduction in the carrying
amount of non-utility property.
DSM and renewable energy programs expense was $63.4 million in
1999 compared to $51.8 million in 1998, an increase of $11.6
million, or 22%. 1999 reflects an increase of $6 million
representing four months of expenses from the former COM/Energy
subsidiaries from the date of the merger. Without the impact of
the merger, DSM and renewable energy programs expense would have
been $57.4 million, an increase from 1998 of $5.6 million, or
11%.
Property and other taxes were $77.8 million in 1999 compared to
$84.1 million in 1998, a decrease of $6.3 million, or 7%. 1999
reflects an increase of $8.9 million representing four months of
expenses from the former COM/Energy subsidiaries from the date of
the merger. Without the impact of the merger, property and other
taxes would have been $68.9 million, a decrease from 1998 of
$15.2 million, or 18%. This decrease reflects lower municipal
property taxes resulting from the divestiture of the fossil and
nuclear generating facilities.
Other Income (Expense), net
Other income, net of taxes was $8.1 million in 1999 compared to
other expense, net of $11.8 million in 1998, a net increase in
income of $19.9 million. Prior to the consideration of tax
benefits, other expense was $17.7 million in 1999 compared to
$35.9 million in 1998. 1999 reflects an increase of $1.4 million
reflecting four months of expense from the former COM/Energy
subsidiaries from the date of the merger. Without the impact of
the merger, other expense would have been $16.3 million in 1999.
NSTAR's equity loss in the RCN joint venture was $16.2 million in
1999, compared to its total equity losses from both the RCN and
EnergyVision joint ventures in 1998 of $19.7 million. 1999
reflects $7 million of anticipated non-recoverable expenses
related to the Pilgrim plant divestiture. 1998 reflects $23.2
million of costs related to the fossil plants' divestiture. 1998
also reflects an additional $3.5 million of costs related to
discontinued operations of a Boston Energy Technology Group
subsidiary, Coneco Corporation, and $2.6 million of costs
associated with opposition to a referendum that sought to repeal
the Restructuring Act. These amounts were offset by $5.6 million
of interest income in 1999 compared to $7.6 million in 1998, a
decrease of $2 million, reflecting the higher level of cash on
hand in 1998 as a result of the proceeds from the fossil plant
divestiture. Other miscellaneous income was $0.4 million in 1999
compared to $5.5 million in 1998. Income tax benefits related to
other income (expense), net were $27.6 million in 1999 and $24.1
million in 1998. The income tax benefit includes $20.8 million
in 1999 and $10.9 million in 1998 related to the recognition of
previously deferred investment tax credits associated with the
Pilgrim nuclear plant divested in 1999 and the fossil generating
stations divested in 1998.
Interest Charges
Interest on long-term debt and transition property securitization
certificates was $104.6 million in 1999 compared to $83 million
in 1998, an increase of $21.6 million, or 26%. 1999 reflects an
increase of $13 million representing four months of expenses from
the former COM/Energy subsidiaries from the date of the merger.
Without the impact of the merger, interest on long-term debt and
transition property securitization certificates were $91.6
million in 1999, an increase from 1998 of $8.6 million or 10%.
The increase reflects approximately $20 million related to
securitization. This increase is partially offset by a reduction
of approximately $6 million due to the retirement of $19 million
of 7.80% debentures due March 15, 2023, $66 million of 9.875%
debentures and $91 million of 9.375% debentures during the third
quarter of 1999. The increase is additionally offset by
reductions of approximately $2 million due to the maturity of
$100 million, 5.95% debentures in March 1998 and the cessation of
amortization of the associated discounts and premiums, as well as
a reduction of approximately $3 million due to the redemption of
a $100 million 6.662% bank loan in June 1998.
Interest on short-term debt and other obligations was $22.9
million in 1999 compared to $8.8 million in 1998, an increase of
$14.1 million, or 160%. 1999 reflects an increase of $9.2 million
representing four months of expenses from the former COM/Energy
subsidiaries from the date of the merger. The remaining increase
primarily reflects increased borrowings from the revolving line
of credit agreements to finance common shares repurchased in
connection with the merger, the common share repurchase program
and investments in non-utility subsidiaries.
Preferred Stock Dividends and Redemptions
Preferred dividends of Boston Edison were approximately $6
million in both 2000 and 1999 and $8.8 million in 1998. The
decrease in 1999 was due to the redemption of 400,000 shares of
7.75% series cumulative preferred stock and the remaining 320,000
shares of 7.27% series in July 1998. 500,000 shares of 8% series
cumulative preferred stock is subject to mandatory redemption in
December 2001.
Liquidity and Capital Resources
During 2000, 1999 and 1998 internal generation of cash provided
181%, 174% and 97%, 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 2001 is $295 million,
which includes amounts for utility plant and the capital
requirements of non-utility ventures. The capital spending level
over the next four years is forecasted to aggregate approximately
$670 million. In addition to capital expenditures, long-term debt
principal (including securitized debt) and preferred stock
redemption requirements will be approximately $123 million in
2001, $109 million in 2002, $241 million in 2003, $79 million in
2004 and $78 million in 2005.
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 $199 million in long-term debt retirements, consisting of
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. As of December 31,
2000, there was no amount outstanding and at December 31, 1999,
there was $350 million outstanding under this revolving credit
agreement. Also, NSTAR has a $450 million commercial paper
program. At December 31, 2000 and 1999, NSTAR had $252 million
outstanding and no amount outstanding, respectively, under its
commercial paper program. The primary purpose of the revolving
credit agreement is to provide back-up liquidity for NSTAR's
commercial paper program.
Boston Edison has approval from the FERC to issue up to $350
million of short-term debt. Boston Edison has a $200 million
revolving credit agreement with a group of banks effective
through December 2001. In addition, it also has a $100 million
line of credit. Both of these arrangements serve as back-up to
Boston Edison's $300 million commercial paper program. As of
December 31, 2000 and 1999, there were no amounts outstanding
under this revolving credit agreement. As of December 31, 2000,
there was $97 million outstanding under its commercial paper
program. There was no amount outstanding under this program as of
December 31, 1999.
In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $185 million available under several lines of
credit. Approximately $120 million and $108 million was
outstanding under these lines of credit as of December 31, 2000
and 1999, respectively.
Boston Edison's Financing Application with the MDTE was approved
in October 2000 for authorization to issue from time to time up
to $500 million of debt securities through 2002. Proceeds from
such issuances covered under this approved financing will be used
for repayment or refinancing of certain outstanding equity
securities, long-term indebtedness, and for other corporate
purposes. On February 20, 2001, Boston Edison filed a
registration statement on Form S-3 with the Securities and
Exchange Commission (SEC), using a shelf registration process, to
issue up to $500 million in debt securities. The registration
statement was declared effective by the SEC 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.
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. In October 1999, this program was completed by NSTAR. Four
million shares were repurchased at a total cost of approximately
$157 million. NSTAR subsequently announced a 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 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.
New Accounting Principles
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting
for Derivative Instruments and Hedging Activities" (SFAS 133) and
as amended by Statements of Financial Accounting Standards No.
137 and 138, collectively referred to as SFAS 133. SFAS 133
established accounting and reporting standards requiring that
every derivative instrument (including certain derivative
instruments embedded in other contracts possibly including fixed-
price fuel supply and power contracts) be recorded on the
Consolidated Balance Sheets as either an asset or liability
measured at its fair value. SFAS 133 is effective for fiscal
years beginning after June 15, 2000.
NSTAR will adopt SFAS 133 as of January 1, 2001. The impact of
this adoption has been assessed by the management of NSTAR. 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 has performed extensive reviews of critical
operating areas of NSTAR and has documented its procedures in
applying the requirements of SFAS 133 to NSTAR's contractual
arrangements in effect on January 1, 2001. Based on NSTAR's
assessment to date, the adoption of SFAS 133 will not have a
material adverse effect on its results of operations, cash flows,
or financial position as of January 1, 2001.
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 accounts for its Class A 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. During 1998, NSTAR Com
exercised its option to convert a portion of its interest. In the
first quarter of 1999, NSTAR Com received 1.1 million RCN common
shares in exchange for a portion of its joint venture interest
that had a net book value of $7.8 million. In May 1999, NSTAR Com
notified RCN of its intention to exercise its option to convert
an additional portion of its joint venture interest that had a
net book value of $72.3 million at that time. In March 2000,
NSTAR Com received approximately three million shares of RCN
associated with this second exchange.
The RCN shares received are included in Other investments on the
accompanying Consolidated Balance Sheets at their fair value of
approximately $25.9 million at December 31, 2000. This fair value
may increase or decrease, at any time, as a result of changes in
the market price of RCN common shares. The unrealized gain or
loss due to the changes in fair value on these shares during each
period is reflected, net of associated income taxes, as
Comprehensive (loss) income on the accompanying Consolidated
Statements of Comprehensive Income. The cumulative increase or
decrease in fair value of these shares as of December 31, 2000
and 1999 is reflected as Accumulated other comprehensive (loss)
income, net on the accompanying Consolidated Balance Sheets.
Management continues to evaluate the carrying value of its
investment in RCN. As a result of the current decline in the
market value of RCN shares, it is reasonably possible that an
adjustment may result. Management is unable at this time to
estimate the amount, if any, of a potential adjustment.
On April 6, 2000, NSTAR Com issued its third and final notice to
exchange substantially all of its remaining interest in the joint
venture with a net book value of approximately $129 million into
common shares of RCN that is reflected on the accompanying
Consolidated Balance Sheets in Equity investments. Effective with
the third notice, NSTAR Com's profit and loss sharing ratio was
reduced to zero and therefore NSTAR Com no longer recognized any
results of operations from its interest in the joint venture.
Through April 6, 2000, NSTAR Com recognized $5.6 million in
equity losses from the joint venture and for the year ended
December 31, 1999, it recognized $16.2 million in losses.
On October 18, 2000, NSTAR Com and RCN signed an agreement in
principle to amend the Joint Venture Agreement. Among other
items, this proposal would settle the number of shares to be
exchanged associated with the third conversion of NSTAR Com's
Class A Equity at 7.5 million shares. This amendment also offers
NSTAR Com the option to continue to invest in the joint venture
through a new "Class B Preferred Equity" guaranteed by RCN. This
Class B Equity has no voting rights and no sharing of profits or
losses. NSTAR Com has an option to invest up to $100 million in
such security.
NSTAR Com, at its election, may choose to designate the amounts
it contributes under future capital calls as either Class A
Equity or Class B Equity in the joint venture. Future investments
by NSTAR Com will not be convertible into RCN common shares. In
addition, under the agreement in principle, the joint venture and
NSTAR Com would amend certain of their agreements to incorporate
an incentive and penalty provision for construction activities
and expand the relevant market in which the joint venture
operates. No final agreement has been reached relating to the
October 18, 2000 agreement in principle. Management expects to
have a final amended Joint Venture Agreement in place during the
first half of 2001.
At December 31, 2000 and 1999, NSTAR Com had $47.9 million and
$26.6 million, respectively, in accounts receivable due from RCN.
Other Matters
Environmental
The subsidiaries of NSTAR are involved in approximately 30 state-
regulated properties where oil or other hazardous materials were
spilled or released. The companies are required to clean up these
properties in accordance with specific state regulations. There
are uncertainties associated with these costs due to the
complexities of cleanup technology, regulatory requirements and
the particular characteristics of the different sites. NSTAR
subsidiaries also face possible liability as a potentially
responsible party (PRP) in the cleanup of six multi-party
hazardous waste sites in Massachusetts and other states where it
is alleged to have generated, transported or disposed of
hazardous waste at the sites. NSTAR generally expects to have
only a small percentage of the total potential liability for
these sites. Approximately $7 million is included as a liability
on the accompanying Consolidated Balance Sheets related to the
non-recoverable portion of these cleanup liabilities. Management
is unable to fully determine a range of reasonably possible
cleanup costs in excess of the accrued amount. Based on its
assessments of the specific site circumstances, management does
not believe that it is probable that any such additional costs
will have a material impact on NSTAR's consolidated financial
position. However, it is reasonably possible that additional
provisions for cleanup costs that may result from a change in
estimates could have a material impact on the results of
operations for a reporting period in the near term.
NSTAR Gas is participating in the assessment of a number of
former manufactured gas plant (MGP) sites and alleged MGP waste
disposal locations to determine if and to what extent such sites
have been contaminated and whether NSTAR Gas may be responsible
for remedial action. The MDTE has approved recovery of costs
associated with MGP sites. As of December 31, 2000, NSTAR Gas has
recorded a liability of $2.6 million as an estimate for site
cleanup costs for several MGP sites for which NSTAR Gas was
previously cited as a PRP.
Estimates related to environmental remediation costs are reviewed
and adjusted periodically as further investigation and assignment
of responsibility occurs. NSTAR is unable to estimate its
ultimate liability for future environmental remediation costs.
However, in view of NSTAR's current assessment of its
environmental responsibilities, existing legal requirements and
regulatory policies, management does not believe that these
matters will have a material adverse effect on NSTAR's
consolidated financial position or results of operations for a
reporting period.
Industry and corporate restructuring legal proceedings
The 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 or results of
operations for a reporting period.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE,
the Massachusetts Attorney General contested cost allocations
related to Boston Edison's wholesale customers since 1998.
Management is unable to determine the outcome of the MDTE
proceedings. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on business operations,
the consolidated financial position, results of operations and
cash flows in the near term.
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 and authorized Boston
Edison to invest up to $45 million in non-utility activities.
Hearings were completed during 1999. Management is currently
unable to determine the timing of and 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 results of
operations for a reporting period.
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, management does not believe that it is
probable that any such additional costs will have a material
impact on its consolidated financial position. However, it is
reasonably possible that additional legal costs that may result
from a change in estimates could have a material impact on the
results of a reporting period.
Employees
As of December 31, 2000, NSTAR's subsidiaries had approximately
3,300 full-time employees, including approximately 2,300 or 70%
of employees represented by nine collective bargaining units
covered by separate contracts. In 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 and Gas employees and one five-year contract expiring
May 15, 2005 that will replace seven separate and widely diverse
agreements. The other remaining collective bargaining unit
contract expires March 31, 2002. Management believes it has
satisfactory employee relations.
Interest rate risk
NSTAR is exposed to changes in interest rates primarily based on
levels of short-term debt outstanding. The weighted average
interest rates for mandatory redeemable cumulative preferred
stock and long-term indebtedness were 8.0% and 7.5%,
respectively, for 2000 and 8.0% and 7.25%, respectively, for
1999. Carrying amounts and fair values of mandatory redeemable
cumulative preferred stock and indebtedness (excluding notes
payable) as of December 31, 2000 and 1999 were as follows:
2000 1999
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Mandatory redeemable
cumulative preferred
stock $ 49,519 $ 50,890 $ 49,279 $ 52,250
Indebtedness $2,070,180 $2,090,290 $1,854,794 $1,842,373
Safe Harbor Cautionary Statement
NSTAR occasionally makes forward-looking statements such as
forecasts and projections of expected future performance or
statements of its plans and objectives. These forward-looking
statements may be contained in filings with the SEC, press
releases and oral statements. 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 preceding sections include certain forward-looking statements
about operating results and environmental and legal issues.
The impact of continued cost control procedures on operating
results could differ from current expectations. The effects of
changes in economic conditions, tax rates, interest rates,
technology, prices and availability of operating supplies could
materially affect the projected operating results.
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 cleanup technology could affect the estimated
cleanup liabilities. The impacts of changes in available
information and circumstances regarding legal issues could affect
the estimated litigation costs.
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk
Although NSTAR has material commodity purchase contracts and
financial instruments (debt), these instruments are not subject
to market risk. NSTAR's electric and gas distribution
subsidiaries have rate making mechanisms that allow for the
recovery of fuel costs from customers. The fuel adjustment
mechanisms allow NSTAR's subsidiaries to pass all costs related
to the purchase of commodities to the customer, thereby
insulating NSTAR from market risk.
Similarly, any change in the fair market value of NSTAR's
prudently incurred debt obligations realized by NSTAR would be
borne by customers through future rates.
Item 8. Financial Statements and Supplementary Financial
Information
NSTAR
Consolidated Statements of Income
Years ended December 31,
2000 1999 1998
(in thousands, except earnings per share)
Operating revenues $2,699,506 $1,851,427 $1,622,515
Operating expenses:
Fuel, purchased power and cost of gas sold 1,390,740 794,748 567,806
Operations and maintenance 414,270 353,768 382,434
Depreciation and amortization 223,491 210,306 195,607
Demand side management and renewable energy
programs 78,774 63,425 51,839
Taxes-property and other 78,694 77,761 84,091
Income taxes 123,467 87,721 97,798
Total operating expenses 2,309,436 1,587,729 1,379,575
Operating income 390,070 263,698 242,940
Other income (expense), net (3,715) 8,078 (11,811)
Operating and other income 386,355 271,776 231,129
Interest charges:
Long-term debt 109,299 84,196 82,951
Transition property securitization
certificates 45,505 20,408 -
Other 55,182 22,873 8,800
Allowance for borrowed funds used during
construction (AFUDC) (4,593) (2,164) (1,668)
Total interest charges 205,393 125,313 90,083
Net income 180,962 146,463 141,046
Preferred stock dividends of subsidiary 5,960 5,960 8,765
Earnings available for common shareholders $ 175,002 $ 140,503 $ 132,281
========= ========= ==========
Weighted average common shares
outstanding:
Basic 54,887 50,796 47,973
Diluted 55,045 50,921 48,149
Earnings per common share:
Basic $ 3.19 $ 2.77 $ 2.76
Diluted $ 3.18 $ 2.76 $ 2.75
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Statements of Comprehensive Income
Years ended December 31,
2000 1999 1998
(in thousands)
Net income $180,962 $146,463 $141,046
Comprehensive (loss) income, net:
Unrealized (loss) gain on investments (53,255) 20,115 -
Excess non-qualified benefit obligation (1,004) - -
Comprehensive income $126,703 $166,578 $141,046
======== ======== ========
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Statements of Retained Earnings
Years ended December 31,
2000 1999 1998
(in thousands)
Balance at the beginning of the year $ 389,989 $ 360,509 $ 328,802
Add:
Net income 180,962 146,463 141,046
Subtotal 570,951 506,972 469,848
Deduct:
Dividends declared:
Common shares 109,315 103,099 90,610
Preferred stock 5,960 5,960 8,765
Subtotal 115,275 109,059 99,375
Deduct:
Provision for preferred stock
redemption and issuance costs 239 239 7,833
Common share repurchase programs 8,850 7,685 2,131
Balance at the end of the year $ 446,587 $ 389,989 $ 360,509
========= ========= =========
2284:
The accompanying notes are an integral part of the consolidated
financial statements
.
NSTAR
Consolidated Balance Sheets
December 31,
(in thousands)
2000 1999
Assets
Utility Plant in service, at
original cost $3,724,754 $3,652,257
Less: Accumulated depreciation 1,249,685 $2,475,069 1,239,201 $2,413,056
Construction work in progress 48,524 64,644
Net utility plant 2,523,593 2,477,700
Non-utility property 105,827 93,887
Goodwill 475,877 485,990
Equity investments 155,457 173,290
Other investments 41,163 69,942
Current assets:
Cash and cash equivalents 23,198 168,599
Restricted cash 20,827 147,941
Accounts receivable, net of
allowance of $28,309 and
$23,836 in 2000 and 1999
respectively 454,499 389,702
Regulatory assets 242,663 -
Accrued unbilled revenues 101,732 42,112
Fuel, materials and supplies,
at average cost 44,659 48,756
Prepaid pension expense 149,890 104,900
Other 54,246 1,091,714 42,569 944,579
Deferred debits:
Regulatory assets 1,029,341 1,045,925
Other 146,542 174,830
Total assets $5,569,514 $5,466,143
========= =========
Capitalization and Liabilities
Common equity $1,376,369 $1,523,532
Accumulated other comprehensive
(loss) income, net (34,144) 20,115
Cumulative preferred stock of subsidiary 43,000 92,279
Long-term debt 1,440,431 986,843
Transition property securitization certificates 584,130 646,559
Current liabilities:
Long-term debt and preferred
stock due within one year $ 58,695 $ 170,470
Transition property securitization
certificates, due within one year 36,443 50,922
Notes payable 468,347 458,000
Accounts payable 275,778 193,937
Accrued interest 44,220 21,830
Dividends payable 28,305 29,871
Other 323,672 1,235,460 338,745 1,263,775
Deferred credits:
Accumulated deferred income taxes 666,544 608,587
Accumulated deferred investment
tax credits 39,960 41,946
Power contracts 25,868 100,741
Other 191,896 181,766
Commitments and contingencies
Total capitalization and liabilities $5,569,514 $5,466,143
========= =========
The accompanying notes are an integral part of the consolidated
financial statements.
NSTAR
Consolidated Statements of Cash Flows
2360:
December 31,
(in thousands)
2000 1999 1998
Operating activities:
Net income $180,962 $146,463 $141,046
Adjustments to reconcile net income to
net cash provided by operating
activities:
Depreciation and amortization 225,459 212,880 229,668
Deferred income taxes and investment
tax credits 54,835 88,174 (152,798)
Allowance for borrowed funds used
during construction (3,057) (2,164) (1,668)
Power contract buy out (11,679) (65,781) -
Net changes (net of effect of
acquisition) in:
Accounts receivable and accrued
unbilled revenues (124,417) (96,909) 20,544
Fuel, materials and supplies, at
average cost 4,097 (2,192) 29,565
Accounts payable 93,520 19,469 13,316
Other current assets and liabilities (195,158) (87,032) (33,535)
Other, net (53,587) (29,548) 18,851
Net cash provided by operating activities 170,975 183,360 264,989
Investing activities:
Plant expenditures (excluding AFUDC) (182,709) (159,295) (120,202)
Costs of nuclear divestiture, net - (87,248) -
Proceeds from sale of fossil generating
assets - - 533,633
Nuclear fuel expenditures (1,597) (16,117) (26,182)
Investments (53,843) (82,403) (81,589)
Payment for cost of acquisition, net of
cash acquired - (296,262) -
Net cash (used in) provided by investing
activities (238,149) (641,325) 305,660
Financing activities:
Proceeds from transition property
securitization - 725,000 -
Issuances/(repurchases):
Common shares (212,611) (189,715) (53,285)
Long-term debt 500,000 20,000 -
Redemptions:
Preferred stock - - (71,519)
Long-term debt (257,853) (255,361) (201,600)
Financing costs (2,100) - -
Net change in short-term notes 10,347 340,550 (59,013)
Dividends paid (116,010) (103,036) (100,246)
Net cash (used in) provided by financing
activities (78,227) 537,438 (485,663)
Net (decrease) increase in cash and cash
equivalents (145,401) 79,473 84,986
Cash and cash equivalents at the
beginning of the year 168,599 89,126 4,140
Cash and cash equivalents at the end of $ 23,198 $168,599 $ 89,126
the year ========= ======= ========
Supplemental disclosure of cash flow
information: 2000 1999 1998
Cash paid during the year for:
Interest, net of amounts capitalized $ 166,072 $125,840 $ 89,720
Income taxes $ (11,441) $ 36,092 $230,260
Supplemental disclosure of investing
activity:
Common shares issued for acquisition
of COM/Energy - 20,251 -
2433:
The accompanying notes are an integral part of the consolidated
financial statements.
2437:
Notes to Consolidated Financial Statements
2439:
Note A. Summary of Significant Accounting Policies
2441:
1. About NSTAR
NSTAR is an energy delivery company serving approximately 1.3
million customers in Massachusetts including more than one
million electric customers in 81 communities and 244,000 gas
customers in 51 communities. NSTAR also supplies electricity at
wholesale for resale to municipalities. NSTAR was created through
the merger of BEC Energy (BEC) and Commonwealth Energy System
(COM/Energy) on August 25, 1999 and is 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) and its wholesale
electric subsidiary is Canal Electric Company (Canal Electric).
Effective November 1, 2000, NSTAR's three retail electric
companies began to 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 liquefied natural gas services (Hopkinton LNG
Corp.).
NSTAR is focusing its utility operations on the transmission and
distribution of energy. The 1997 Massachusetts Electric
Restructuring Act (Restructuring Act) required all electric
utilities to divest their generating assets and leave the retail
power supply business in exchange for the right to recover all
non-mitigable stranded costs associated with the creation of
customer choice and competition.
2. Basis of Consolidation and Accounting
The accompanying consolidated financial statements reflect the
results of operations, comprehensive income, financial position
and cash flows of NSTAR and its subsidiaries. All significant
intercompany transactions have been eliminated. Certain
reclassifications have been made to the prior year data to
conform with the current year's presentation.
NSTAR's utility subsidiaries follow accounting policies
prescribed by the Federal Energy Regulatory Commission (FERC) and
the Massachusetts Department of Telecommunications and Energy
(MDTE). In addition, NSTAR and its subsidiaries are subject to
the accounting and reporting requirements of the Securities and
Exchange Commission (SEC). The accompanying consolidated
financial statements conform with Generally Accepted Accounting
Principles (GAAP). The utility subsidiaries are subject to
Statement of Financial Accounting Standards No. 71, "Accounting
for the Effects of Certain Types of Regulation" (SFAS 71). The
application of SFAS 71 results in differences in the timing of
recognition of certain expenses from that of other businesses and
industries. The distribution business remains subject to rate-
regulation and continues to meet the criteria for application of
SFAS 71. Refer to Note D to these Consolidated Financial
Statements for more information on the accounting implications of
the electric utility industry restructuring.
The preparation of financial statements in conformity with GAAP
requires management of NSTAR and its subsidiaries to make
estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosures of contingent assets and
liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from these estimates.
3. Revenues
Utility revenues are based on authorized rates approved by the
FERC and the MDTE. Estimates of transmission and distribution
revenues for electricity and natural gas used by customers but
not yet billed are accrued at the end of each accounting period.
NSTAR Electric also recognizes unbilled revenue related to
transition charges similar to transmission and distribution.
Revenues for NSTAR's non-utility subsidiaries are recognized when
services are rendered or when the energy is delivered.
4. Utility Plant
Utility plant is stated at original cost of construction. The
costs of replacements of property units are capitalized.
Maintenance and repairs and replacements of minor items are
expensed as incurred. The original cost of property retired, net
of salvage value, and the related costs of removal are charged to
accumulated depreciation. Non-utility property is stated at cost
or its net realizable value.
5. Depreciation
Depreciation of utility plant is computed on a straight-line
basis using composite rates based on the estimated useful lives
of the various classes of property. The overall composite
depreciation rates were 3.20%, 3.31% and 3.28% in 2000, 1999 and
1998, respectively. Depreciation of non-utility property is
computed on a straight-line basis over the estimated life of the
asset.
6. Costs Associated with Issuance and Redemption of Debt and
Preferred Stock
Consistent with the recovery in utility rates, discounts,
redemption premiums and related costs associated with the
issuance and redemption of long-term debt and preferred stock are
deferred. The costs related to long-term debt are recognized as
an addition to interest expense over the life of the original or
replacement debt. Consistent with an accounting order received
from the FERC, costs related to preferred stock issuances and
redemptions are reflected as a direct reduction to retained
earnings upon redemption or over the average life of the
replacement preferred stock series as applicable.
7. Allowance for Borrowed Funds Used During Construction (AFUDC)
AFUDC represents the estimated costs to finance utility plant
construction. In accordance with regulatory accounting, AFUDC is
included as a cost of utility plant and a reduction of current
interest charges. Although AFUDC is not a current source of cash
income, the costs are recovered from customers over the service
life of the related plant in the form of increased revenues
collected as a result of higher depreciation expense. Average
AFUDC rates in 2000, 1999 and 1998 were 6.16%, 5.82% and 5.88%,
respectively, and represented only the cost of short-term debt.
AFUDC also includes capitalized interest on non-utility plant.
8. Cash and Cash Equivalents
Cash and cash equivalents are comprised of liquid securities with
maturities of 90 days or less when purchased. Restricted cash
represents the net proceeds from the sale of Canal Electric's
generation assets that are required to be used to reduce the
transition costs that otherwise would be billed to customers.
9. Equity Method of Accounting
NSTAR uses the equity method of accounting for investments in
corporate joint ventures in which it does not have a controlling
interest. Under this method, it records as income or loss the
proportionate share of the net earnings or losses of the joint
ventures with a corresponding increase or decrease in the
carrying value of the investment. The investment is reduced as
cash dividends are received.
10. Amortization of Goodwill and Costs to Achieve
The merger of BEC and COM/Energy was accounted for as an
acquisition of COM/Energy by BEC using the purchase method of
accounting. Under this method, the accompanying consolidated
financial statements of NSTAR for 2000 include the results of
operations, comprehensive income, financial position and cash
flows of NSTAR for the entire period presented. However, the
accompanying consolidated financial statements of NSTAR for the
year 1999 reflect the results of BEC consolidated with those of
COM/Energy from the date of the merger (August 25, 1999).
Goodwill amounted to approximately $490 million, while the
original estimate of transaction and integration costs to achieve
the merger was $111 million. Goodwill is being amortized over 40
years and will amount to approximately $12.2 million annually,
while the cost to achieve is being amortized over 10 years and
will initially be approximately $11.1 million annually. The
ultimate amortization of the costs to achieve will reflect the
total actual costs.
11. Regulatory Assets
Regulatory assets represent costs incurred that are expected to
be collected from customers through future charges in accordance
with agreements with regulators. These costs are expensed when
the corresponding revenues are received in order to appropriately
match revenues and expenses.
Regulatory assets consisted of the following:
December 31,
(in thousands) 2000 1999
Generation-related regulatory assets, net $ 694,902 $ 631,639
Purchased power costs - 95,654
Cost to achieve 119,519 79,681
Power contract 61,131 96,911
Income taxes, net 55,887 71,057
Postretirement benefits costs 26,692 24,887
Redemption premiums 14,403 16,014
Other 56,807 30,082
1,029,341 1,045,925
Current Assets
Purchased power costs 242,663 -
Total regulatory assets $1,272,004 $1,045,925
========= =========
The current purchased power costs shown in the table above as of
December 31, 2000 is based on a recent MDTE approval of standard
offer and default service rates and it is anticipated that this
amount will be collected from customers during 2001.
Note B. Earnings Per Common Share
Basic earnings per common share (EPS) is calculated by dividing
net income, after deductions for preferred dividends, by the
weighted average common shares outstanding during the year.
Statement of Financial Accounting Standards No. 128, "Earnings
per Share," requires the disclosure of diluted EPS. Diluted EPS
is similar to the computation of basic EPS except that the
weighted average common shares is increased to include the number
of dilutive potential common shares. Diluted EPS reflects the
impact on shares outstanding of the deferred (nonvested) shares
and stock options granted under the NSTAR Stock Incentive Plan.
The following table summarizes the reconciling amounts between
basic and diluted EPS:
(in thousands, except per share amounts) 2000 1999 1998
Earnings available for common shareholders $175,002 $140,503 $132,281
Basic EPS $3.19 $2.77 $2.76
Diluted EPS $3.18 $2.76 $2.75
Weighted average common shares
outstanding for basic EPS 54,887 50,796 47,973
Effect of dilutive shares:
Weighted average dilutive potential
common shares 158 125 176
Weighted average common shares
outstanding for diluted EPS 55,045 50,921 48,149
Note C. 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 accounts for its Class A 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. During 1998, NSTAR Com
exercised its option to convert a portion of its interest. In the
first quarter of 1999, NSTAR Com received 1.1 million RCN common
shares in exchange for a portion of its joint venture interest
that had a net book value of $7.8 million. In May 1999, NSTAR Com
notified RCN of its intention to exercise its option to convert
an additional portion of its joint venture interest that had a
net book value of $72.3 million at that time. In March 2000,
NSTAR Com received approximately three million shares of RCN
associated with this second exchange.
The RCN shares received are included in Other investments on the
accompanying Consolidated Balance Sheets at their fair value of
approximately $25.9 million at December 31, 2000. This fair value
may increase or decrease, at any time, as a result of changes in
the market price of RCN common shares. The unrealized gain or
loss due to the changes in fair value on these shares during each
period is reflected, net of associated income taxes, as
Comprehensive (loss) income on the accompanying Consolidated
Statements of Comprehensive Income. The cumulative increase or
decrease in fair value of these shares as of December 31, 2000
and 1999 is reflected as Accumulated other comprehensive (loss)
income, net on the accompanying Consolidated Balance Sheets.
Management continues to evaluate the carrying value of its
investment in RCN. As a result of the current decline in the
market value of RCN shares, it is reasonably possible that an
adjustment may result. Management is unable at this time to
estimate the amount, if any, of a potential adjustment.
On April 6, 2000, NSTAR Com issued its third and final notice to
exchange substantially all of its remaining interest in the joint
venture with a net book value of approximately $129 million into
common shares of RCN that is reflected on the accompanying
Consolidated Balance Sheets in Equity investments. Effective with
the third notice, NSTAR Com's profit and loss sharing ratio was
reduced to zero and therefore NSTAR Com no longer recognized any
results of operations from its interest in the joint venture.
Through April 6, 2000, NSTAR Com recognized $5.6 million in
equity losses from the joint venture and for the year ended
December 31, 1999, it recognized $16.2 million in losses.
On October 18, 2000, NSTAR Com and RCN signed an agreement in
principle to amend the Joint Venture Agreement. Among other
items, this proposal would settle the number of shares to be
exchanged associated with the third conversion of NSTAR Com's
Class A Equity at 7.5 million shares. This amendment also offers
NSTAR Com the option to continue to invest in the joint venture
through a new "Class B Preferred Equity" guaranteed by RCN. This
Class B Equity has no voting rights and no sharing of profits or
losses. NSTAR Com has an option to invest up to $100 million in
such security.
NSTAR Com, at its election, may choose to designate the amounts
it contributes under future capital calls as either Class A
Equity or Class B Equity in the joint venture. Future investments
by NSTAR Com will not be convertible into RCN common shares. In
addition, under the agreement in principle, the joint venture and
NSTAR Com would amend certain of their agreements to incorporate
an incentive and penalty provision for construction activities
and expand the relevant market in which the joint venture
operates. No final agreement has been reached relating to the
October 18, 2000 agreement in principle. Management expects to
have a final amended Joint Venture Agreement in place during the
first half of 2001.
At December 31, 2000 and 1999, NSTAR Com had $47.9 million and
$26.6 million, respectively, in accounts receivable due from RCN.
Note D. Electric Utility Industry Restructuring
1. Accounting Implications
Under the traditional revenue requirements model, electric rates
are based on the cost of providing electric service. Under this
model, NSTAR Electric is subject to certain accounting standards
that are not applicable to other businesses and industries in
general. The application of SFAS 71 requires companies to defer
the recognition of certain costs when incurred if future rate
recovery of these costs is expected. NSTAR's remaining generation
business, Canal Electric's 3.52% joint ownership interest in the
Seabrook Nuclear Power Station is subject to the provisions of
SFAS 71.
The implementation of electric utility industry restructuring has
certain accounting implications. The highlights of these include:
a. Generation-related plant and other regulatory assets
Plant and other regulatory assets related to the generation
business are recovered through the transition charge. This
recovery occurs over a 12-year period for Boston Edison and over
an 11-year period for ComElectric and Cambridge Electric,
beginning on March 1, 1998, the retail access date in
Massachusetts.
b. Fuel and purchased power charge
The fuel and purchased power charge ceased as of the retail
access date. The net remaining over-collection of fuel and
purchased power costs were returned to customers through March
31, 2000. These over-recovered costs are included as an offset to
the settlement recovery mechanisms and were included in
Regulatory assets on the accompanying Consolidated Balance
Sheets.
c. Standard offer and default service charges
Customers have the option of continuing to buy power from the
retail electric distribution businesses at standard offer prices
as of the retail access date 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 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.
d. Distribution and transmission charges
An integral part of the merger is the rate plan of the retail
utility subsidiaries of NSTAR that was approved by the MDTE on
July 27, 1999. Significant elements of the rate plan include a
four-year distribution rate freeze, recovery of the acquisition
premium (goodwill) over 40 years and recovery of transaction and
integration costs (costs to achieve) over 10 years.
Boston Edison distribution rates were subject to a minimum and
maximum return on average common equity (ROE) from its
distribution business through December 31, 2000. The ROE was
subject to a floor of 6% and a ceiling of 11.75%. If the ROE was
below 6%, Boston Edison was authorized to add a surcharge to
distribution rates in order to achieve the 6% floor. If the ROE
was above 11%, it was required to adjust distribution rates by an
amount necessary to reduce the calculated ROE between 11% and
12.5% by 50%, and a return above 12.5% by 100%. No adjustment was
made if the ROE was between 6% and 11%. In addition, distribution
rates continue to be subject to adjustment for any changes in tax
laws or accounting principles that result in a change in costs of
more than $1 million. No adjustments have been made to Boston
Edison's distribution rates due to either one of these rate
mechanisms.
The cost of providing transmission service to all NSTAR Electric
distribution customers is recovered on a fully reconciling basis.
2. Generating Assets Divestiture
On July 13, 1999, Boston Edison completed the sale of the Pilgrim
Nuclear Generating Station to Entergy Nuclear Generating Company
(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. Approximately $5 million remains to be
collected under these termination agreements at December 31,
2000. This compares to $80 million at December 31, 1999. As part
of the sale, Boston Edison, the first company in the nation to
successfully sell a nuclear facility, 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 IRS tax ruling,
Boston Edison received $43 million from Entergy reflecting a
reduction in the required decommissioning funding. The difference
between the total proceeds received and the net book value of the
Pilgrim assets sold plus the net amount to fully fund the
decommissioning trust is included in Regulatory assets on the
accompanying Consolidated Balance Sheets as such amounts are
currently being collected from customers under Boston Edison's
settlement agreement. The final amounts to be collected from
customers related to Pilgrim are subject to regulatory review.
Completion of the sale of Boston Edison's fossil generating
assets took place in May 1998. Boston Edison received proceeds
from the sale of $674 million, including $121 million for a six-
month transitional power purchase contract. The amount received
above net book value on the sale of these assets is being
returned to Boston Edison's customers over the settlement period.
On July 27, 1999, BEC Funding LLC, a wholly owned special-purpose
subsidiary of Boston Edison, closed the sale of $725 million of
notes to a special purpose trust created by two Massachusetts
state agencies. The trust then concurrently closed the sale of
$725 million of electric rate reduction certificates to the
public. The certificates are secured by a portion of the
transition charge assessed on Boston Edison's retail customers as
permitted under the Restructuring Act and authorized by the MDTE.
These certificates are non-recourse to Boston Edison.
COM/Energy completed the sale of substantially all of its
investment in electric generation assets in 1998. Proceeds from
the sale of these assets, after construction-related adjustments
at the closing that occurred on December 30, 1998, amounted to
approximately $453.9 million, or 6.1 times their book value of
approximately $74.2 million. The proceeds from the sale, net of
book value, transaction costs and certain other adjustments,
amounted to $358.6 million and are being used to reduce stranded
costs related to electric industry restructuring that otherwise
would have been collected from customers.
COM/Energy established Energy Investment Services, Inc. (EIS) as
the vehicle to invest the net proceeds from the sale of Canal
Electric generation assets. These proceeds were invested in a
portfolio of securities that are designed to maintain principal
and earn a reasonable return. Both the principal amount and
income earned were used to reduce the future stranded costs that
would otherwise have been billed to customers of Cambridge
Electric and ComElectric. The net proceeds were classified as
Restricted cash on the accompanying Consolidated Balance Sheets
for 2000 and 1999.
On October 26, 2000, the MDTE approved the filing made by
Cambridge Electric and ComElectric (together, "the Companies")
for the partial buydown of their contract with Canal Electric for
power from the Seabrook nuclear generating facility (Seabrook
Contract). The buydown transaction is effected by means of an
amendment to the Seabrook Contract. On November 8, 2000, $120.5
million of funds held by EIS, was transferred to ComElectric and
Cambridge Electric in the amount of $113.4 million and $7.1
million, respectively. EIS was established as the vehicle to
invest the net proceeds from the sale of these assets. The
Companies, in turn, have reduced their respective future stranded
costs to be recovered from customers. In addition, Cambridge
Electric also made a $21.1 million payment to Canal Electric as a
further buydown of its share of the Seabrook Contract with after-
tax proceeds received from the sale of Cambridge Electric's
Kendall Station in December 1998. Approval of a November 1, 2000
buydown amount is pending at the MDTE.
The impact of these transactions is shown on the accompanying
Consolidated Balance Sheets at December 31, 2000 as reductions in
Restricted cash and Regulatory assets.
Canal Electric also made a filing with the FERC to amend the
Seabrook Contract to reflect the buydown effective November 1,
2000. Action by the FERC on this filing is pending.
Note E. Income Taxes
Income taxes are accounted for in accordance with Statement of
Financial Accounting Standards No. 109, "Accounting for Income
Taxes" (SFAS 109). SFAS 109 requires the recognition of deferred
tax assets and liabilities for the future tax effects of
temporary differences between the carrying amounts and the tax
basis of assets and liabilities. In accordance with SFAS 109, net
regulatory assets of $55.9 million and $71.1 million and
corresponding net increases in accumulated deferred income taxes
were recorded as of December 31, 2000 and 1999, respectively. The
regulatory assets represent the additional future revenues to be
collected from customers for deferred income taxes.
Accumulated deferred income taxes consisted of the following:
December 31,
(in thousands) 2000 1999
Deferred tax liabilities:
Plant-related $487,714 $484,021
Other 490,079 424,128
977,793 908,149
Deferred tax assets:
Plant-related 82,898 78,587
Investment tax credits 25,791 29,013
Other 202,560 191,962
311,249 299,562
Net accumulated deferred income taxes $666,544 $608,587
======== ========
No valuation allowances for deferred tax assets are deemed
necessary.
Previously deferred investment tax credits are amortized over the
estimated remaining lives of the property giving rise to the
credits.
Components of income tax expense were as follows:
(in thousands) 2000 1999 1998
Current income tax expense $ 68,944 $(33,121) $239,717
(benefit)
Deferred income tax expense 56,508 123,393 (137,992)
(benefit)
Investment tax credit (1,985) (2,551) (3,927)
amortization
Income taxes charged to 123,467 87,721 97,798
operations
Tax benefit on other expense, 5,433 (27,580) (24,116)
net
Total income tax expense $128,900 $ 60,141 $ 73,682
======== ======== ========
The effective income tax rates reflected in the consolidated
financial statements and the reasons for their differences from
the statutory federal income tax rate were as follows:
2000 1999 1998
Statutory tax rate 35.0% 35.0% 35.0%
State income tax, net of federal income tax benefit 5.1 5.5 5.2
Investment tax credit (0.6) (11.3) (6.9)
Other 2.1 (0.1) 1.0
Effective tax rate 41.6% 29.1% 34.3%
===== ===== =====
Income tax expense is reflected net of $20.8 million in 1999 and
$10.9 million in 1998, representing investment tax credits
recognized as a result of generation asset divestitures.
Excluding this shareholder benefit, the effective tax rate would
have been approximately 39% in each year.
Note F. Pensions and Other Postretirement Benefits
1. Pensions
NSTAR sponsors a defined benefit funded retirement plan that
covers substantially all employees. NSTAR also maintains unfunded
supplemental retirement plans for certain management employees.
Effective January 1, 2001, the defined benefit plan was amended
to reflect the impact of the transition of all NSTAR union locals
to the pension benefits provided under the Local 369 formula.
This amendment is reflected in the December 31, 2000 benefit
obligation.
Effective January 1, 2000, the defined benefit plan was amended
to provide management employees lump sum benefits under a final
average pay pension equity formula. Prior to January 1, 2000,
these pension benefits were provided under a traditional final
average pay formula. This amendment is reflected in the December
31, 1999 benefit obligation.
The changes in benefit obligation and plan assets were as
follows:
December 31,
(in thousands) 2000 1999
Change in benefit obligation:
Benefit obligation, beginning of the year $800,084 $497,988
COM/Energy obligation - 405,868
Service cost 14,636 14,741
Interest cost 59,798 42,426
Plan participants' contributions 81 170
Plan amendments (4,387) (12,697)
Actuarial loss/(gain) 59,815 (62,464)
Curtailment loss - 18,424
Special termination benefit - 13,582
Settlement payments (77,256) (92,484)
Benefits paid (48,413) (25,470)
Benefit obligation, end of the year $804,358 $800,084
======== ========
(in thousands)
Change in plan assets: 2000 1999
Fair value of plan assets, beginning of the year $955,498 $474,552
COM/Energy plan assets - 395,783
Actual (loss)/return on plan assets, net (28,041) 143,116
Employer contribution 44,338 59,831
Plan participants' contributions 81 170
Settlement payments (77,256) (92,484)
Benefits paid (48,413) (25,470)
Fair value of plan assets, end of the year $846,207 $955,498
======== ========
The plan's funded status was as follows:
December 31,
(in thousands)
2000 1999
Funded status $ 41,849 $155,414
Unrecognized actuarial net loss/(gain) 104,817 (59,254)
Unrecognized transition obligation 2,182 2,783
Unrecognized prior service cost (3,340) 1,495
Net amount recognized $145,508 $100,438
======== ========
Amount recognized in the Consolidated Balance Sheets consisted
of:
(in thousands) 2000 1999
Prepaid retirement cost $149,890 $104,900
Accrued supplemental retirement (13,306) (10,148)
liability
Intangible asset 7,285 5,686
Accumulated other comprehensive income 1,639 -
Net amount recognized $145,508 $100,438
======== ========
The projected benefit obligation, accumulated benefit obligation
and fair value of plan assets for the supplemental retirement
plan with accumulated benefit obligations in excess of plan
assets were $14,067,000, $13,306,000 and $0, respectively, as of
December 31, 2000, and $14,291,000, $10,148,000 and $0,
respectively, as of December 31, 1999.
Weighted average assumptions were as follows:
2000 1999 1998
Discount rate at the end of the year 7.5% 8.0% 6.5%
Expected return on plan assets for the
year (net of investment expenses) 9.3% 9.0% 9.0%
Rate of compensation increase at the end
of the year 4.0% 4.0% 4.0%
Components of net periodic benefit cost were as follows:
December 31,
(in thousands) 2000 1999 1998
Service cost $ 14,636 $ 14,741 $ 13,645
Interest cost 59,798 42,426 31,981
Expected return on plan assets (85,884) (53,059) (39,140)
Amortization of prior service cost 448 1,610 1,847
Amortization of transition obligation 601 664 860
Recognized actuarial loss - 3,594 808
Net periodic benefit/(income)cost $ (10,401) $ 9,976 $ 10,001
========= ======== ========
Primarily as a result of merger-related separation agreements and
nuclear divestiture, amounts recognized for curtailment,
settlement and special termination benefit costs were
$19,823,000, $930,000 and $13,582,000, respectively, for 1999. In
addition, $9,623,000 was recognized as a result of pension
settlements in 2000. The majority of these charges will be
recovered from customers and is a component of Regulatory assets
on the accompanying Consolidated Balance Sheets. The amounts
resulting from the merger-related separation agreements and
generation divestitures are recoverable as part of the approved
rate plans of the retail utility subsidiaries of NSTAR.
NSTAR also provides defined contribution 401(k) plans for
substantially all employees. Matching contributions (which are
equal to 50% of the employees' deferral up to 8% of compensation)
included in the accompanying Consolidated Statements of Income
amounted to $7 million in 2000, $9 million in 1999 and $8 million
in 1998.
2. Other Postretirement Benefits
In addition to pension benefits, NSTAR also provides health care
and other benefits to retired employees who meet certain age and
years of service eligibility requirements. These benefits include
health and life insurance coverage and reimbursement of certain
Medicare premiums. Under certain circumstances, eligible
employees are required to make contributions for postretirement
benefits.
Effective January 1, 2001, amendments were added to reflect
negotiated changes to Local 369 as well as the impact of the
transition of all NSTAR union locals to the benefits provided
under the Local 369 formula. These amendments are reflected in
the December 31, 2000 benefit obligation. Effective January 1,
2000, an amendment was added to include certain new managed care
features. This amendment is reflected in the December 31, 1999
benefit obligation.
The changes in benefit obligation and plan assets were as
follows:
December 31,
(in thousands) 2000 1999
Change in benefit obligation:
Benefit obligation, beginning of the year $ 370,914 $ 258,756
COM/Energy obligation - 146,741
Service cost 3,563 4,505
Interest cost 29,574 21,896
Plan participants' contributions 926 37
Plan amendments 2,807 (14,062)
Actuarial loss/(gain) 44,939 (24,186)
Curtailment loss - 1,408
Settlement payments - (5,810)
Benefits paid (24,382) (18,371)
Benefit obligation, end of the year $ 428,341 $ 370,914
======== ========
(in thousands)
Change in plan assets:
Fair value of plan assets, beginning of the year $ 201,053 $ 113,818
COM/Energy plan assets - 73,558
Actual (loss)/return on plan assets (16,411) 23,337
Employer contribution 63,465 14,484
Plan participants' contributions 926 37
Settlement payments - (5,810)
Benefits paid (24,382) (18,371)
Fair value of plan assets, end of the year $ 224,651 $ 201,053
======== ========
The plans' funded status and amounts recognized in the
accompanying Consolidated Balance Sheets were as follows:
December 31,
(in thousands) 2000 1999
Funded status $(203,690) $(169,861)
Unrecognized actuarial net loss/(gain) 70,836 (9,524)
Unrecognized transition obligation 67,400 73,016
Unrecognized prior service cost (17,644) (22,154)
Net amount recognized $ (83,098) $(128,523)
======== ========
Weighted average assumptions were as follows:
2000 1999 1998
Discount rate at the end of the year 7.5% 8.0% 6.5%
Expected return on plan assets for the year 9.0% 9.0% 9.0%
For measurement purposes an 11% weighted annual rate of increase
in per capita cost of covered medical claims was assumed for
2001. This rate is assumed to decrease gradually to 5% in 2012
and remain at that level thereafter. Dental claims and Medicare
premiums are assumed to increase at a weighted annual rate of 4%
and 5%, respectively.
A 1% change in the assumed health care cost trend rate would have
the following effects:
One-Percentage-Point
(in thousands) Increase Decrease
Effect on total of service and interest
costs components for 2000 $ 4,672 $ (3,477)
Effect on December 31, 2000 postretirement
benefit obligation $57,499 $(44,494)
Components of net periodic benefit cost were as follows:
years ended December 31,
(in thousands) 2000 1999 1998
Service cost $ 3,563 $ 4,505 $ 3,892
Interest cost 29,574 21,896 16,895
Expected return on plan assets (19,010) (12,329) (8,563)
Amortization of prior service cost (1,703) (683) (942)
Amortization of transition obligation 5,616 6,162 8,474
Recognized actuarial loss - 957 662
Net periodic benefit cost $18,040 $20,508 $20,418
======= ======= =======
As a result of merger-related separation agreements and nuclear
divestiture, amounts recognized for curtailment and settlement
costs were $8,114,000 and $172,000, respectively, for 1999. As a
result of the nuclear divestiture, amounts recognized for
curtailment and special termination benefit costs were
$21,187,000 and $79,000, respectively, for 1998. The amounts
resulting from the merger-related separation packages are
recoverable as part of the approved rate plans of the retail
utility subsidiaries of NSTAR. The amounts resulting from the
nuclear divestiture are recoverable under the Boston Edison
settlement agreement.
Note G. Stock-Based Compensation
NSTAR maintains a Stock Incentive Plan (the Plan) that permits a
variety of stock and stock-based awards, including stock options
and deferred (non-vested) stock to be granted to certain key
employees. The Plan limits the terms of awards to ten years.
Subject to adjustment for stock-splits and similar events, the
aggregate number of common shares that may be awarded under the
Plan is 2,000,000, including shares issued in lieu of or upon
reinvestment of dividends arising from awards. During 2000,
69,750 deferred shares and 316,700 ten-year non-qualified stock
options were granted. During 1999, 58,500 deferred shares and
248,000 ten-year non-qualified stock options were granted. During
1998, 19,150 deferred shares and 419,200 ten-year non-qualified
stock options were granted under the Plan. The weighted average
grant date fair value of the deferred stock issued during 2000,
1999 and 1998 was $44.375, $41.73 and $39.75, respectively. The
options were granted at the full market price of the common
shares on the date of the grant. All the awards vest ratably over
a three-year period.
Compensation cost for stock-based awards is computed by measuring
the quoted stock market price at the measurement date less the
amount, if any, an employee is required to pay. The fair value
disclosures were as follows:
(in thousands, except per share amounts) 2000 1999 1998
Net income
Actual $180,962 $146,463 $141,046
Pro forma $180,237 $145,955 $140,661
Basic earnings per common share
Actual $ 3.19 $ 2.77 $ 2.76
Pro forma $ 3.18 $ 2.76 $ 2.75
Diluted earnings per common share
Actual $ 3.18 $ 2.76 $ 2.75
Pro forma $ 3.17 $ 2.75 $ 2.74
Stock option activity of the Plan was as follows:
2000 1999 1998
Options outstanding at January 1 814,267 666,600 273,000
Options granted 316,700 248,000 419,200
Options exercised (125,432) (4,400) (3,800)
Options forfeited (87,400) (95,933) (21,800)
Options outstanding at December 31 918,135 814,267 666,600
======= ======= =======
Summarized information regarding stock options outstanding at
December 31, 2000:
Options Outstanding Options Exercisable
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Numbers Exercise
Exercise Prices Outstanding (Years) Price Outstanding Price
$25.75-$26.00 162,400 6.45 $25.90 162,400 $25.90
$39.75-$41.375 467,402 7.26 $40.36 242,576 $40.14
$44.375 288,333 9.40 $44.375 - -
There were 404,976, 298,333 and 87,200 stock options exercisable
on December 31, 2000, 1999 and 1998, respectively.
The stock options granted during 2000, 1999 and 1998 have a
weighted average grant date fair value of $7.00, $4.86 and $4.61,
respectively. The fair value was estimated using the Black-
Scholes option pricing model with the following weighted average
assumptions:
2000 1999 1998
Expected life (years) 4.0 4.0 4.0
Risk-free interest rate 6.48% 5.31% 5.66%
Volatility 20% 17% 16%
Dividends 4.64% 4.86% 4.88%
Compensation cost recognized in the accompanying Consolidated
Statements of Income for stock-based compensation awards in 2000,
1999 and 1998 was $1,717,000, $1,044,000 and $850,000,
respectively.
Note H. Capital Stock
Common Shares
December 31,
(in thousands, except per share amounts) 2000 1999
Common equity:
Common shares, par value $1 per share,
100,000,000 shares authorized;
53,032,546 and 58,059,646 shares
issued and outstanding $ 53,033 $ 58,060
Premium on common shares 876,749 1,075,483
Retained earnings 446,587 389,989
Total common equity $1,376,369 $1,523,532
========= =========
Dividends declared per common share were $2.015, $1.955 and
$1.895 in 2000, 1999 and 1998, respectively.
Cumulative Preferred Stock
(in thousands, except per share amounts)
Par value $100 per share, 2,890,000 shares authorized; issued and
outstanding:
Current
Series Shares Redemption December 31,
Outstanding Price/Share 2000 1999
4.25% 180,000 $103.625 $18,000 $18,000
4.78% 250,000 $102.80 25,000 25,000
Total non-mandatory redeemable series 43,000 43,000
Mandatory redeemable series:
Current Redemption
Series Shares Price/Share
Outstanding
8.00% 500,000 $100.00 50,000 50,000
Less redemption and issuance costs 481 721
Total mandatory redeemable series 49,519 49,279
92,519 92,279
Less amount due within one year 49,519 -
Total cumulative preferred stock
of subsidiary $43,000 $92,279
====== ======
1. Common Shares
Common share issuances and repurchases in 1998 through 2000 were
as follows:
Number of Total Premium on
(in thousands) Shares Par Value Common Shares
Balance at December 31, 1997 48,515 $ 48,515 $ 696,137
Common share repurchase program (1,331) (1,331) (49,823)
Stock incentive plan - - (2,109)
Balance at December 31, 1998 47,184 47,184 644,205
Common share repurchase program (4,839) (4,839) (179,593)
Stock incentive plan - - (3,189)
Shares issued to COM/Energy
shareholders 20,251 20,251 809,524
BEC Energy shares repurchase
under mergeragreement (4,536) (4,536) (195,464)
Balance at December 31, 1999 58,060 58,060 1,075,483
Common share repurchase program (5,027) (5,027) (198,113)
Stock incentive plan - - (621)
Balance at December 31, 2000 53,033 $ 53,033 $ 876,749
======= ======= ========
2. Cumulative Mandatory Redeemable Preferred Stock
Boston Edison is not able to redeem any part of the 500,000
shares of 8% series cumulative preferred stock prior to December
2001. The entire series is subject to mandatory redemption in
December 2001 at $100 per share plus accrued dividends.
Note I. Indebtedness
1. Long-term debt
NSTAR's long-term debt consisted of the following:
December 31,
(in thousands) 2000 1999
Mortgage Bonds, collateralized by
property of operating subsidiaries:
8.99%, due December 2001 $ 3,500 $ 7,150
6.54%, due September 2007 10,000 10,000
7.04%, due September 2017 25,000 25,000
9.95%, due December 2020 25,000 25,000
7.11%, due December 2033 35,000 35,000
Notes:
7.75%, due June 2002 2,200 2,301
9.30%, due January 2002 29,989 29,978
7.43%, due March 2003 15,000 15,000
9.50%, due December 2004 4,000 5,000
7.62%, due November 2006 20,000 20,000
8.70%, due March 2007 5,000 5,000
9.55%, due December 2007 10,000 10,000
7.70%, due March 2008 10,000 10,000
8.0%, due February 2010 498,008 -
9.37%, due January 2012 12,632 13,684
7.98%, due March 2013 25,000 25,000
9.53%, due December 2014 10,000 10,000
9.60%, due December 2019 10,000 10,000
6.924%, due June 2021 105,994 105,250
8.47%, due March 2023 15,000 15,000
Debentures:
6.80%, due February 2000 - 65,000
6.05%, due August 2000 - 100,000
6.80%, due March 2003 150,000 150,000
7.80%, due May 2010 125,000 125,000
9.875%, due June 2020 - 34,035
9.375%, due August 2021 24,270 24,270
8.25%, due September 2022 60,000 60,000
7.80%, due March 2023 181,000 181,000
Sewage facility revenue bonds, due 23,014 24,645
through 2015
Massachusetts Industrial Finance Agency
(MIFA) bonds:
5.75%, due February 2014 15,000 15,000
Transition Property Securitization
Certificates:
5.99%, due March 2003 4,073 80,981
6.45%, due September 2005 170,610 170,610
6.62%, due March 2007 103,390 103,390
6.91%, due September 2009 170,876 170,876
7.03%, due March 2012 171,624 171,624
2,070,180 1,854,794
Amounts due within one year (45,619) (221,392)
Total long-term debt $2,024,561 $1,633,402
========= =========
The 9.375% series due 2021 are first redeemable in August 2001 at
104.612%, the 8.25% series due 2022 are first redeemable in
September 2002 at 103.780% and the 7.80% series due 2023 are
first redeemable in March 2003 at 103.730%. None of the other
series are redeemable prior to maturity. There is no sinking fund
requirement for any series of debentures.
Sewage facility revenue bonds are tax-exempt, subject to annual
mandatory sinking fund redemption requirements and mature through
2015. Scheduled redemptions of $1.6 million were made in 2000,
1999 and 1998. The weighted average interest rate of the bonds
was 7.3%.
The 5.75% tax-exempt unsecured MIFA bonds due 2014 are redeemable
beginning in February 2004 at a redemption price of 102%. The
redemption price decreases to 101% in February 2005 and to par in
February 2006.
Boston Edison's Financing Application with the MDTE was approved
in October 2000 for authorization to issue from time to time up
to $500 million of debt securities through 2002. Proceeds from
such issuances covered under this approved financing will be used
for repayment or refinancing of certain outstanding equity
securities, long-term indebtedness, and for other corporate
purposes. 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 registration statement was declared effective by
the SEC 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.
The aggregate principal amounts of NSTAR long-term debt
(including securitization certificates and sinking fund
requirements) due for the five years subsequent to 2000 are
approximately $72 million in 2001, $109 million in 2002, $241
million in 2003, $79 million in 2004 and $78 million in 2005.
In 1999, BEC Funding LLC, a wholly owned subsidiary of Boston
Edison, issued notes in the principal amount of $725 million to a
special purpose trust created by two Massachusetts state
agencies, in exchange for the net proceeds from the sale of $725
million of Rate Reduction Certificates issued by the trust on
July 29, 1999.
2. Short-term Debt
NSTAR has a $450 million revolving credit agreement with a group
of banks effective through November 2002. As of December 31,
2000, there were no amounts outstanding and as of December 31,
1999 there was $350 million outstanding under its revolving
credit agreement. Also, NSTAR has a $450 million commercial paper
program. At December 31, 2000 and 1999, NSTAR had $252 million
outstanding and no amount outstanding, respectively, under its
commercial paper program. The primary purpose of its revolving
agreement is to provide back-up liquidity for the NSTAR
commercial paper program. Under the terms of this agreement,
NSTAR is required to maintain a consolidated common equity ratio
of not less than 35% at all times and to maintain a ratio of
consolidated earnings before interest and taxes to consolidated
total interest expense of not less than 2 to 1 for each period of
four consecutive fiscal quarters. Commitment fees must be paid on
the total agreement amount.
Boston Edison has regulatory approval to issue up to $350 million
of short-term debt. Boston Edison also has a $200 million
revolving credit agreement with a group of banks effective
through December 31, 2001. In addition, it has a $100 million
line of credit. Both of these arrangements serve as back-up to
Boston Edison's $300 million commercial paper program. As of
December 31, 2000, there was $97 million outstanding under its
commercial paper program. There was no amount outstanding under
this program as of December 31, 1999. Under the terms of this
agreement, Boston Edison is required to maintain a common equity
ratio of not less than 30% at all times. Commitment fees must be
paid on the total agreement amount.
In addition, ComElectric, Cambridge Electric and NSTAR Gas,
collectively, have $185 million available under several lines of
credit that will expire at varying intervals in 2001. These lines
are normally renewed upon expiration and require annual fees of
approximately .1875%. Approximately $120 million and $108 million
were outstanding under these lines of credit as of December 31,
2000 and 1999, respectively.
Interest rates on the outstanding borrowings generally are money
market rates and averaged 6.65% and 5.81% in 2000 and 1999,
respectively. Notes payable to banks totaled $468.3 million and
$458 million at December 31, 2000 and 1999, respectively.
Note J. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the
fair value of each class of securities for which it is
practicable to estimate the value:
1. Cash and cash equivalents
The carrying amounts of $23.2 million and $168.8 million for 2000
and 1999, respectively, approximates fair value due to the short-
term nature of these securities.
2. Mandatory redeemable cumulative preferred stock and
indebtedness (excluding notes payable)
The fair values of these securities are based upon the quoted
market prices of similar issues. Carrying amounts and fair values
as of December 31, 2000 and 1999 were as follows:
2000 1999
Carrying Fair Carrying Fair
(in thousands) Amount Value Amount Value
Mandatory redeemable
cumulative preferred stock $49,519 $50,890 $ 49,279 $52,250
Long-term indebtedness $2,070,180 $2,090,290 $1,854,794 $1,842,373
Note K. Segment and Related Information
For the purpose of providing segment information, NSTAR's
principal operating segments, or its traditional core businesses,
are the electric and natural gas utilities that provide energy
delivery services in over 100 cities and towns in Massachusetts.
NSTAR subsidiaries also supply electricity at wholesale for
resale to municipalities. The unregulated operating segments
engage in non-utility business activities. Such activities
include telecommunications, district heating and cooling
operations, and liquefied natural gas services. Financial data
for the operating segments were as follows:
(in thousands) 2000 1999(b) 1998
Operating revenues
Electric utility operations $2,237,939 $1,710,576 $1,622,435
Gas utility operations 370,416 108,117 -
Unregulated non-utility operations 91,151 32,734 80
Consolidated total $2,699,506 $1,851,427 $1,622,515
========== ========== ==========
Depreciation and amortization
Electric utility operations $ 202,209 $ 190,560 $ 192,644
Gas utility operations 15,573 5,566 -
Unregulated non-utility operations 5,709 14,180 2,963
Consolidated total $ 223,491 $ 210,306 $ 195,607
========= ========== =========
Operating income tax expense (benefit)
Electric utility operations $ 125,597 $ 98,125 $ 101,492
Gas utility operations 16,570 4,208 -
Unregulated non-utility operations (18,700) (14,612) (3,694)
Consolidated total $ 123,467 $ 87,721 $ 97,798
========= ========== ==========
Equity income (loss) in investments
accounted for by the equity method (a)
Electric utility operations $ 4,241 $ 999 $ 1,725
Unregulated non-utility operations (5,467) (10,505) (11,967)
Consolidated total $ (1,226) $ (9,506) $ (10,242)
========= ========== ==========
Interest charges
Electric utility operations $ 134,767 $ 106,878 $ 88,516
Gas utility operations 10,828 3,742 -
Unregulated non-utility operations 59,798 14,693 1,567
Consolidated total $ 205,393 $ 125,313 $ 90,083
========== ========== ==========
Segment net income (loss)
Electric utility operations $ 187,646 $ 165,626 $ 170,374
Gas utility operations 24,238 5,379 -
Unregulated non-utility operations (30,922) (24,542) (29,328)
Consolidated total $ 180,962 $ 146,463 $ 141,046
========== ========== ==========
Equity Investments
Electric utility operations $ 43,230 $ 32,995 $ 20,769
Gas utility operations 1,097 9 -
Unregulated non-utility operations 111,130 140,286 64,001
Consolidated total $ 155,457 $ 173,290 $ 84,770
========== ========== ==========
Expenditures for property
Electric utility operations $ 141,400 $ 134,906 $ 108,344
Gas utility operations 19,500 7,669 -
Unregulated non-utility operations 21,809 16,720 11,858
Consolidated total $ 182,709 $ 159,295 $ 120,202
========== ========== ==========
=Segment assets
Electric utility operations $4,529,379 $4,409,630 $3,073,058
Gas utility operations 534,430 459,887 -
Unregulated non-utility operations 505,705 596,626 130,978
Consolidated total $5,569,514 $5,466,143 $3,204,036
========== ========== ==========
(a) The net equity income (loss) from equity investments is
included in other income (expense), net on the accompanying
Consolidated Statements of Income.
(b) Financial data for 1999 includes eight months of BEC Energy
and four months of NSTAR.
Note L. Commitments and Contingencies
1. Contractual Commitments
At December 31, 2000, NSTAR and its subsidiaries had estimated
contractual obligations for plant and equipment of approximately
$295 million.
NSTAR also has leases for certain facilities and equipment. The
estimated minimum rental commitments under both transmission
agreements and non-cancellable operating leases for the years
after 2000 are as follows:
(in thousands)
2001 $ 28,905
2002 26,720
2003 21,174
2004 19,920
2005 17,787
Years thereafter 75,686
Total $ 190,192
=========
The total expense for both lease rentals and transmission
agreements was $45.3 million in 2000, $38.7 million in 1999 and
$29.6 million in 1998, net of capitalized expenses of $1.7
million in 2000, $1.5 million in 1999 and $1.6 million in 1998.
Total rent expense for all operating leases, except those with
terms of a month or less, amounted to $8.7 million in 2000, $10.8
million in 1999 and $11.5 million in 1998.
2. Electric Equity Investments and Joint Ownership Interest
NSTAR Electric has an equity investment of approximately 14.5% in
two companies that own and operate transmission facilities to
import electricity from the Hydro-Quebec system in Canada. As an
equity participant, NSTAR Electric is required to guarantee, in
addition to each companies' own share, the total obligations of
those participants who do not meet certain credit criteria. At
December 31, 2000, NSTAR Electric's portion of these guarantees
amounted to $18 million.
Canal Electric owns a 3.52% joint ownership interest in the
Seabrook Nuclear Power Station, and sells its entitlement to
Seabrook energy and capacity to ComElectric and Cambridge
Electric. The estimate of NSTAR's share of the Seabrook
investment and costs of decommissioning was approximately $4.5
million as of December 31, 2000. These estimates were recorded on
the accompanying Consolidated Balance Sheets as a Power contract
liability and an offsetting asset in Other investments.
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 $451.9 million in current
dollars. NSTAR Electric's share of this liability is
approximately $11.3 million, less its share of the market value
of the assets held in a decommissioning trust of approximately $7
million, is approximately $4.3 million at December 31, 2000.
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, but this transaction was disapproved on February
14, 2001 by Vermont's regulatory authority.
NSTAR Electric has a 14% equity investment in Yankee Atomic
Electric Company (Yankee Atomic). In 1992, the board of directors
of Yankee Atomic voted to discontinue operations of the Yankee
Atomic nuclear generating station permanently and decommission
the facility. Yankee Atomic received approval from the FERC to
continue to collect its investment and decommissioning costs
through July 9, 2000, the expiration date of the unit's power
contracts. Also, as of that date, the equity owners of the unit
completed the recovery of closure (decommissioning) costs and net
unrecovered assets. Subsequently, Yankee Atomic initiated a stock
buy-back program, approved by the SEC, to redeem 95% of the
outstanding stock of Yankee Atomic. Through December 31, 2000,
50% of the 95% of shares outstanding, or 72,866 shares, were
redeemed. NSTAR Electric's reduction of its equity ownership
resulting from the buy-back of 10,201 shares was approximately $1
million.
NSTAR Electric also has a 14% equity investment in the
Connecticut Yankee Atomic Power Company (CYAPC) unit that has
been retired. NSTAR Electric's share of Connecticut Yankee's
remaining investment and estimated costs of decommissioning is
approximately $38 million as of December 31, 2000. This estimate
was recorded on the accompanying Consolidated Balance Sheets as a
Power contract liability and an offsetting Regulatory asset.
In December 1996, CYAPC filed for rate relief at the FERC seeking
to recover certain post-operating costs, including
decommissioning. In August 1998, the FERC Administrative Law
Judge (ALJ) released an initial decision regarding CYAPC's
filing. This decision called for the disallowance of the common
equity return on the CYAPC investment subsequent to the shutdown.
The decision also stated that decommissioning collections should
continue to be based on a previously approved estimate, with an
adjustment for inflation, until a more reliable estimate is
developed. In October 1998, both CYAPC and Northeast Utilities, a
49% equity investor in CYAPC, filed briefs on exceptions to the
ALJ decision. The case is still pending before the FERC. If the
initial decision is upheld by the FERC, CYAPC could be required
to write off a portion of its investment in the generating unit
and refund a portion of the previously collected return on
investment to ratepayers. Management is currently unable to
determine the ultimate outcome of this proceeding. However, the
estimate of the effect of the ALJ's initial decision does not
have a material impact on NSTAR's consolidated financial
position, the results of operations or its cash flows.
NSTAR Electric has a 4% equity investment in the Maine Yankee
Atomic Power Company (Maine Yankee). In 1997, the board of
directors of Maine Yankee voted to discontinue operations of the
Maine Yankee nuclear generating station permanently and
decommission the facility.
NSTAR Electric's share of Maine Yankee's remaining
decommissioning is approximately $23 million as of December 31,
2000. This estimate was recorded on the accompanying Consolidated
Balance Sheets as a Power contract liability and an offsetting
Regulatory asset.
3. Nuclear Insurance
Under the Price-Anderson Act (the Act), owners of nuclear power
plants have the benefit of approximately $9.5 billion of public
liability coverage that would compensate the public for covered
bodily injury and property loss in the event of an accident at a
commercial nuclear power plant. The first $200 million of nuclear
liability is covered by commercial insurance. Additional nuclear
liability insurance up to $9.3 billion is provided by a
retrospective assessment of up to $88.1 million per incident
levied on each of the 106 nuclear generating units currently
licensed to operate in the United States, with a maximum
assessment of $10 million per incident per year.
NSTAR has an equity ownership interest in four nuclear generating
facilities and a 3.52% joint ownership interest in Seabrook 1.
The operators of these units maintain nuclear insurance coverage
(on behalf of the owners of the facilities) with either Nuclear
Electric Insurance Limited (NEIL), a combination of NEIL and the
American Nuclear Insurers (ANI) or ANI only depending on the
limit of insurance required to be maintained. NEIL provides $2.25
billion of property, boiler, machinery and decontamination
insurance coverage, including accidental premature
decommissioning insurance. All companies insured with NEIL are
subject to retroactive assessments. ANI provides $500 million of
"all risk" property damage, boiler, machinery and decontamination
insurance. Three of the four units in which NSTAR has an equity
ownership interest have permanently ceased operations. The
Nuclear Regulatory Commission has approved each of these units'
requests to withdraw from participation in the financial
protection insurance program of the Act and reduce their limits
of property insurance.
Based on its equity ownership interests in nuclear generating
facilities and its joint ownership interest in Seabrook 1,
NSTAR's retrospective premium could be $600,000 annually or a
cumulative total of $5.3 million under the Act.
4. Environmental Matters
The subsidiaries of NSTAR are involved in approximately 30 state-
regulated properties where oil or other hazardous materials were
previously spilled or released. The companies are required to
clean up these properties in accordance with specific state
regulations. There are uncertainties associated with these costs
due to the complexities of cleanup technology, regulatory
requirements and the particular characteristics of the different
sites. NSTAR subsidiaries also face possible liability as a
potentially responsible party (PRP) in the cleanup of six multi-
party hazardous waste sites in Massachusetts and other states
where it is alleged to have generated, transported or disposed of
hazardous waste at the sites. NSTAR generally expects to have
only a small percentage of the total potential liability for
these sites. Approximately $7 million is included as a liability
in the accompanying December 31, 2000 Consolidated Balance Sheets
related to the non-recoverable portion of these cleanup
liabilities. Management is unable to fully determine a range of
reasonably possible cleanup costs in excess of the accrued
amount. Based on its assessments of the specific site
circumstances, management does not believe that it is probable
that any such additional costs will have a material impact on
NSTAR's consolidated financial position. However, it is
reasonably possible that additional provisions for cleanup costs
that may result from a change in estimates could have a material
impact on the results of a reporting period in the near term.
NSTAR Gas is participating in the assessment of a number of
former manufactured gas plant (MGP) sites and alleged MGP waste
disposal locations to determine if and to what extent such sites
have been contaminated and whether NSTAR Gas may be responsible
for remedial action. The MDTE has approved recovery of costs
associated with MGP sites. As of December 31, 2000, NSTAR Gas has
recorded a liability of $2.6 million as an estimate for site
cleanup costs for several MGP sites for which NSTAR Gas was
previously cited as a PRP.
Estimates related to environmental remediation costs are reviewed
and adjusted periodically as further investigation and assignment
of responsibility occurs. NSTAR is unable to estimate its
ultimate liability for future environmental remediation costs.
However, in view of NSTAR's current assessment of its
environmental responsibilities, existing legal requirements and
regulatory policies, management does not believe that these
matters will have a material adverse effect on NSTAR's
consolidated financial position or results of operations for a
reporting period.
5. Generating Unit Performance Program
The MDTE's generating unit performance programs ceased March 1,
1998. Under these programs the recovery of incremental purchased
power costs resulting from generating unit outages occurring
through the retail access date was subject to review by the MDTE.
Comprehensive settlements relative to generating unit performance
including the review of replacement power costs associated with
the shutdown of the Connecticut Yankee nuclear electric
generating unit that is discussed in item 2, was approved by the
MDTE on August 1, 2000. The approved MDTE settlements did not
have a material impact on NSTAR's consolidated financial
position, cash flows, or results of operations.
6. Legal Proceedings
Industry and corporate restructuring legal proceedings
The 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.
Regulatory proceedings
In the Boston Edison 1999 reconciliation filing with the MDTE,
the Massachusetts Attorney General contested cost allocations
related to Boston Edison's wholesale customers since 1998.
Management is unable to determine the outcome of the MDTE
proceedings. However, if an unfavorable outcome were to occur,
there could be a material adverse impact on Boston Edison's
consolidated financial position, results of operations and cash
flows in the near term.
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 and authorized Boston
Edison to invest up to $45 million in non-utility activities.
Hearings were completed during 1999. Management is currently
unable to determine the timing of and 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 results of
operations for a reporting period.
Other litigation
In October 1998, the town of Plymouth, Massachusetts, the site of
Pilgrim Station, filed suit against Boston Edison. The town
claimed that Boston Edison had wrongfully failed to execute an
agreement with the town for payments in addition to or in lieu of
taxes due to the town under the Restructuring Act. Boston Edison
and the town of Plymouth settled the suit and agreed in March
1999 on a 15-year $141 million payment as required by the
Restructuring Act. Payments in each of the first four years are
approximately $15 million after which payments gradually decline.
All payments under this agreement will be recovered from
customers through the transition charge.
In the normal course of its business, NSTAR and its subsidiaries
are also involved in certain other legal matters. Management is
unable to fully determine a range of reasonably possible legal
costs in excess of amounts accrued. Based on the information
currently available, it does not believe that it is probable that
any such additional costs will have a material impact on its
consolidated financial position. However, it is reasonably
possible that additional legal costs that may result from a
change in estimates could have a material impact on the results
of a reporting period in the near term.
Note M. Long-Term Contracts for the Purchase of Energy
1. NSTAR Electric Agreements
NSTAR Electric entered into various six-month agreements during
2000 to transfer substantially all of the unit output
entitlements in long-term power purchase contracts to certain
suppliers, who in turn provided full energy service to meet NSTAR
Electric's standard offer and default service load requirements.
Capacity costs reflect NSTAR Electric's proportionate share of
capital and fixed operating costs of certain generating units.
Energy costs are paid to generators based on a price per kWh
actually received into NSTAR Electric's distribution system and
are included in the total cost. In 2000, these costs were
attributed to 1,121.4 MW of capacity purchased.
Information related to long-term power contracts as of December
31, 2000 was as follows:
proportionate share (in thousands)
Range of Capacity Charge
Contract Units of 2000 2000 Obligation
Fuel Type of Expiration Capacity Capacity Total Through Contract
Generating Unit Dates Purchased Cost Cost Expiration Date
% MW
Natural Gas 2008-2017 11.1-100 28.8-135 $132,963 $361,969 $1,519,211
Nuclear 2004-2026 2.3-89 11.9-747.1 35,204 223,437 497,894
Refuse 2015 100 76.9 - 54,006 -
Hydro 2014-2023 100 1.3-20 - 11,126 -
Oil 2002-2019 50-100 34-282 18,511 69,888 80,555
Total $186,678 $720,426 $2,097,660
======= ======= =========
NSTAR Electric entered into a six-month agreement effective
January 1, 2001 through June 30, 2001 with a supplier to provide
full default service energy and ancillary service requirements at
contract rates substantially similar to MDTE-approved tariff
rates. A default service request for proposal, applicable to the
second half of 2001, will be issued in early 2001. NSTAR
Electric's existing portfolio of power purchase contracts is
supplying the majority of its standard offer (including
wholesale) energy requirements, supplemented with long-term and
daily purchases/sales in the bilateral and spot markets. In
addition, NSTAR Electric is managing its Independent System
Operator-New England Power capability responsibilities,
congestion and uplift costs associated with default service and
standard offer load throughout 2001.
NSTAR Electric's total capacity and/or energy costs associated
with these contracts in 2000, 1999 and 1998 were approximately
$720 million, $410 million and $267 million, respectively. NSTAR
Electric's capacity charge obligation under these contracts for
the years after 2000 are as follows:
Capacity
Charge
(in thousands) Obligation
2001 $ 158,899
2002 158,286
2003 146,036
2004 146,255
2005 150,196
Years thereafter 1,337,988
$2,097,660
=========
2. NSTAR Gas Contracts
NSTAR Gas has various contractual agreements covering the
transportation of natural gas, underground storage facilities and
the purchase of natural gas, which are recoverable under NSTAR
Gas' CGAC. These contracts expire at various times from 2003 to
2013.
Report of Independent Accountants
To the Shareholders and Trustees of NSTAR:
In our opinion, the consolidated financial statements listed
in the index appearing under Item 14(a)(1) on page 68 present
fairly, in all material respects, the financial position of NSTAR
and its subsidiaries at December 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the
three years in the period ended December 31, 2000 in conformity
with accounting principles generally accepted in the United
States of America. In addition, in our opinion, the financial
statement schedule listed in the index appearing under Item
14(a)(2) on page 68, respectively, presents fairly, in all
material respects, the information set forth therein when read in
conjunction with the related consolidated financial statements.
These financial statements and the financial statement schedule are
the responsibility of the Company's management; our
responsibility is to express an opinion on these financial
statements and financial statement schedule based on our audits.
We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of
America, which require that we plan and perform the audit to
obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our
opinion.
/s/ PRICEWATERHOUSECOOPERS LLP
PricewaterhouseCoopers LLP
Boston, Massachusetts
January 26, 2001
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
No event that would be described in response to this Item 9 has
occurred with respect to NSTAR or its subsidiaries.
Part III
Item 10. Trustees and Executive Officers of the Registrant
(a) Identification of Trustees
Information required by this item is incorporated herein by
reference to the 2001 Proxy Statement dated March 23, 2001.
Pages 3-5
(b) Identification of Officers
Information required by this item is included in Item 4.A.
Item 11. Executive Compensation
Information required by this item is incorporated herein by
reference to the 2001 Proxy Statement dated March 23, 2001.
Pages 7-14
Item 12. Security Ownership of Certain Beneficial Owners and
Management
Information required by this item is incorporated herein by
reference to the 2001 Proxy Statement dated March 23, 2001.
Pages 1 and 6
Item 13. Certain Relationships and Related Transactions
Information required by this item is incorporated herein by
reference to the 2001 Proxy Statement dated March 23, 2001. Page
12
Part IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K
(a) The following documents are filed as part of this Form 10-K:
1. Financial Statements:
Page
Consolidated Statements of Income for the years ended
December 31, 2000, 1999 and 1998 34
Consolidated Statements of Comprehensive Income for the
years ended December 31, 2000, 1999 and 1998 35
Consolidated Statements of Retained Earnings for the
years ended December 31, 2000, 1999 and 1998 35
Consolidated Balance Sheets as of December 31, 2000 and 36
1999
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998. 37-38
Notes to Consolidated Financial Statements. 39
Selected Consolidated Quarterly Financial Data 15
(Unaudited)
Report of Independent Accountants 65
2. Financial Statement Schedules:
Schedule II-Valuation and Qualifying accounts-years ended
December 31, 2000, 1999 and 1998. 82
3. Exhibits:
Refer to the exhibits listing beginning on the following page.
(b) Reports on Form 8-K:
None
Filed herewith:
Exhibit 21.1 Subsidiaries of the Registrant
Consent of PricewaterhouseCoopers LLP
Exhibit 23.1
NSTAR (Registrant)
Incorporated by reference:
Exhibit 2 Plan of Acquisition, Reorganization, Arrangement,
Liquidation or Seccession
2.1 Amended and Restated Agreement and Plan of Merger, dated
as of December 5, 1998, amended and restated as of May
4, 1999, by and among BEC Energy, Commonwealth Energy
System, NSTAR, BEC Acquisition LLC and CES Acquisition
LLC (Incorporated by reference to Annex A to the Joint
Proxy Statement/Prospectus, Registration Statement on
Form S-4 of NSTAR (No. 333-78285)).
Exhibit 3 Articles of Incorporation and By-Laws
3.1 Declaration of Trust of NSTAR (incorporated by reference
to Annex D to the Joint Proxy Statement/Prospectus,
which forms part of the Registration Statement on Form S-
4 of NSTAR (No. 333-78285)).
3.2 Bylaws of NSTAR (Incorporated by reference to Annex E to
the Joint Proxy Statement/Prospectus, which forms part
of the Registration Statement on Form S-4 of NSTAR (No.
333-78285)).
Exhibit 4 Instruments Defining the Rights of Security Holders,
Including Indentures
4.0 Management agrees to furnish to the Securities and
Exchange Commission, upon request, a copy of any other
agreements or instruments of the Registrant and its
subsidiaries defining the rights of holders of any long-
term debt whose authorization does not exceed 10% of
total assets.
4.1 Registration of NSTAR shares in connection with the
Employees Savings Plan of Commonwealth Energy System and
Subsidiary Companies (Form S-8 Registration Statement,
dated August 19, 1999, File No. 333-85559).
4.2 Indenture dated as of January 12, 2000 between NSTAR and
Bank One Trust Company N.A. (Incorporated by reference,
Exhibit 4.1 to NSTAR Registration Statement on Form S-3,
File No. 333-94735).
Exhibit 10 Material Contracts
10.1 NSTAR Excess Benefit Plan, effective August 25, 1999
(NSTAR Form 10-K/A for the year ended December 31, 1999,
File No. 1-14768).
10.2 NSTAR Supplemental Executive Retirement Plan, effective
August 25, 1999 (NSTAR Form 10-K/A for the year ended
December 31, 1999, File No. 1-14768).
10.3 Special Supplemental Executive Retirement Agreement
between Boston Edison Company and Thomas J. May dated
March 13, 1999, regarding Key Executive Benefit Plan and
Supplemental Executive Retirement Plan (NSTAR Form 10-
K/A for the year ended December 31, 1999, File No. 1-
14768).
10.4 Key Executive Benefit Plan Agreement dated as of October
1, 1983 between Boston Edison Company and Thomas J. May
(NSTAR Form 10-K/A for the year ended December 31, 1999,
File No. 1-14768).
10.5 Key Executive Benefit Plan Agreement dated September 1,
1989 between Boston Edison Company and Ronald A. Ledgett
(NSTAR Form 10-K/A for the year ended December 31, 1999,
File No. 1-14768).
10.6 Employment Agreement between Thomas J. May and NSTAR
dated May 11, 1999 (Incorporated by reference to Annex A
to the Joint Proxy Statement/Prospectus in Part I of the
Registration Statement of NSTAR on Form S-4, File No.
333-78285).
10.7 Employment Agreement between Russell D. Wright and NSTAR
dated May 11, 1999 (Incorporated by reference to Annex A
to the Joint Proxy Statement/Prospectus in Part I of the
Registration Statement of NSTAR on Form S-4, File No.
333-78285).
10.8 Employment Agreement between Boston Edison Company and
Ronald A. Ledgett dated April 30, 1987 (Boston Edison
Company Form 10-K for the year ended December 31, 1994,
File No. 1-2301).
10.9 Change in Control Agreement between NSTAR and Thomas J.
May dated May 11, 1999 (NSTAR Form 10-K/A for the year
ended December 31, 1999, File No. 1-14768).
10.10 Change in Control Agreement between NSTAR and Russell D.
Wright dated May 11, 1999 (NSTAR Form 10-K/A for the
year ended December 31, 1999, File No. 1-14768).
10.11 NSTAR Deferred Compensation Plan (Restated Effective
August 25, 1999) (NSTAR Form 10-K/A for the year ended
December 31, 1999, File No. 1-14768).
10.12 NSTAR 1997 Share Incentive Plan, as amended June 30,
1999 and assumed by NSTAR effective August 28, 2000
(NSTAR Form 10-Q for the quarter ended September 30,
2000, File No. 1-14768).
10.13 Waiver and Employment Agreement among Commonwealth
Energy System and certain of its Subsidiaries, Deborah
A. McLaughlin and NSTAR, dated September 21, 2000 (NSTAR
Form 10-Q for the quarter ended September 30, 2000, File
No. 1-14768).
10.14 Change in Control Agreement between James J. Judge and
NSTAR, dated August 28, 2000 (NSTAR Form 10-Q for the
quarter ended September 30, 2000, File No. 1-14768).
10.15 Change in Control Agreement between Deborah A.
McLaughlin and NSTAR, dated September 21, 2000 (NSTAR
Form 10-Q for the quarter ended September 30, 2000, File
No. 1-14768).
10.16 NSTAR Trustees' Deferred Plan (Restated Effective August
25, 1999), dated October 20, 2000 (NSTAR Form 10-Q for
the quarter ended September 30, 2000, File No. 1-14768).
10.17 Master Trust Agreement between NSTAR and State Street
Bank and Trust Company (Rabbi Trust), dated August 25,
1999 (NSTAR Form 10-Q for the quarter ended September
30, 2000, File No. 1-14768).
BEC Energy and Subsidiaries
Exhibit 3 Articles of Incorporation and By-Laws
3.1 Boston Edison Restated Articles of Organization (Form 10-
Q for the quarter ended June 30, 1994, File No. 1-2301).
3.2 Boston Edison Company Bylaws April 19, 1977, as amended
January 22, 1987, January 28, 1988, May 28, 1988, and
November 22, 1989 (Form 10-Q for the quarter ended June
30, 1990, File No. 1-2301).
Exhibit 4 Instruments Defining the Rights of Security Holders,
Including Indentures
4.1 Medium-Term Notes Series A-Indenture dated September 1,
1988, between Boston Edison Company and Bank of Montreal
Trust Company (Form 10-Q for the quarter ended September
30, 1988, File No. 1-2301).
4.1.1 First Supplemental Indenture dated June 1, 1990 to
Indenture dated September 1, 1988 with Bank of Montreal
Trust Company 97/8% debentures due June 1, 2020. (Form 8-
K dated June 28, 1990, File No. 1-2301).
4.10 Debt Securities to be issued on a delayed or continuous
basis under an Indenture between Boston Edison Company
and The Bank of New York (as successor to Bank of
Montreal Trust company) (Form S-3 Registration
Statement, dated February 20, 2001, File No. 333-55890).
4.11 Debt Securities issued under an Indenture between Boston Edison
Company and The Bank of New York (as successor to Bank of
Montreal Trust Company) (Form S-3 Registration Statement, filed
February 3, 1993, File No. 33-57840).
4.26 Indenture of Trust and Agreement among the City of
Boston, Massachusetts (acting by and through its
Industrial Development Financing Authority) and Harbor
Electric Energy Company and Shawmut Bank, N.A., as
Trustee, dated November 1, 1991 (Form 10-K for the year
end December 31, 1991, File No. 1-2301).
4.27 Votes of the Pricing Committee of the Board of Directors
of Boston Edison Company taken August 5, 1991 re 93/8%
debentures due August 15, 2021 (Form 10-K for the year
ended December 31, 1991, File No. 1-2301)
4.25 Votes of the Pricing Committee of the Board of Directors
of Boston Edison Company taken September 10, 1992 re
8.25% debentures due September 15, 2022 (Form 10-K for
the year ended December 31, 1997, File No. 1-2301).
4.28 Votes of the Pricing Committee of the Board of Directors
of Boston Edison Company taken March 5, 1993 re 6.80%
Debentures due March 15, 2003 and 7.80% debentures due
March 15, 2023 (Form 10-K for the year ended December
31, 1992, File No. 1-2301).
4.9 Votes of the Pricing Committee of the Board of Directors
of Boston Edison Company taken May 10, 1995 re 7.80%
debentures due May 15, 2010 (Form 10-K for the year
ended December 31, 1995, File No. 1-2301).
Exhibit 10 Material Contracts
10.11 Boston Edison Company Deferred Fee Plan dated January
14, 1993 (Form 10-K for year ended December 31, 1992,
File No. 1-2301).
10.10 Deferred Compensation Trust between Boston Edison
Company and State Street Bank and Trust Company dated
February 2, 1993 (Form 10-K for the year ended December
31, 1992, File No. 1-2301).
10.5.1 Amendment No. 1 to Deferred Compensation Trust dated
March 31, 1994 (Form 10-K for the year ended December
31, 1994).
10.10 Employment Agreement Applicable to Ronald A. Ledgett
dated April 30, 1987 (Form 10-K for the year ended
December 31, 1994, File No. 1-2301).
10.12 Boston Edison Company Restructuring Settlement Agreement
dated July 1997 (Form 10-K for the year ended December
31, 1997, File No. 1-2301).
10.1 Boston Edison Company and Sithe Energies, Inc. Purchase
and Sale and Transition Agreements dated December 10,
1997 (Form 10-Q for the quarter ended March 31, 1998,
File No. 1-2301).
10.11 Boston Edison Company Directors' Deferred Fee Plan
Restatement effective October 1, 1998 (Form 10-K for the
year ended December 31, 1999, File No. 1-2301).
10.12 Boston Edison Company and Entergy Nuclear Generation
Company Purchase and Sale Agreement dated November 18,
1998 (Form 10-K for the year ended December 31, 1999,
File No. 1-2301).
10.13 License Agreement Between Boston Edison Company and
Becocom, Inc., dated July 17, 1997 (Form 10-K for the
year ended December 31, 1999, File No. 1-14768).
10.14 Chilled Water Service Agreement between Northwind Boston
LLC and Prucenter Acquisition LLC, March 23, 1999.
(Form 10-K for the year ended December 31, 1999, File
No. 1-14768).
Exhibit 99 Additional Exhibits
99.1 Settlement Agreement between Boston Edison Company and
Commonwealth Electric Company, Montaup Electric Company
and the Municipal Light Department of the Town of
Reading, Massachusetts, dated January 5, 1990 (Form 8-K
dated December 21, 1989, File No. 1-2301).
99.2 Settlement Agreement between Boston Edison Company and
City of Holyoke Gas and City of Holyoke Gas and Electric
Department et. al., dated April 26, 1990 (Form 10-Q for
the quarter ended March 31, 1990, File No. 1-2301).
99.3 Information required by SEC Form 11-K for certain
employee benefit plans for the years ended December 31,
1997, 1996 and 1995 (Form 10-K/A Amendments to Form 10-K
for the years December 31, 1997, 1996 and 1995 dated
June 25, 1998, June 26, 1997 and June 27, 1996
respectively.
Commonwealth Energy System
Exhibit 10 Power Contract
10.1.1 Power contracts between CEC (Unit 1) and NBGEL and CEL
dated December 1, 1965 (Exhibit 13(a)(1-4) to the CEC
Form S-1, File No. 2-30057).
10.1.2 Power contract between Yankee Atomic Electric Company
(YAEC) and CEL dated June 30, 1959, as amended April 1,
1975 (Refiled as Exhibit 1 to the 1991 CEL Form 10-K,
File No. 2-7909).
10.1.2.1 Second, Third and Fourth Amendments to 10.1.2 as amended
October 1, 1980, April 1, 1985 and May 6, 1988,
respectively (Exhibit 2 to the CEL Form 10-Q (June
1988), File No. 2-7909).
10.1.2.2 Fifth and Sixth Amendments to 10.1.2 as amended June 26,
1989 and July 1, 1989, respectively (Exhibit 1 to the
CEL Form 10-Q (September 1989), File No. 2-7909).
10.1.3 Power Contract between YAEC and NBGEL dated June 30,
1959, as amended April 1, 1975 (Refiled as Exhibit 2 to
the 1991 CE Form 10-K, File No. 2-7749).
10.1.3.1 Second, Third and Fourth Amendments to 10.1.3 as amended
October 1, 1980, April 1, 1985 and May 6, 1988,
respectively (Exhibit 1 to the CE Form 10-Q (June 1988),
File No. 2-7749).
10.1.3.2 Fifth and Sixth Amendments to 10.1.3 as amended June 26,
1989 and July 1, 1989, respectively (Exhibit 3 to the CE
Form 10-Q (September 1989), File No. 2-7749).
10.1.4 Power Contract between Connecticut Yankee Atomic Power
Company (CYAPC) and CEL dated July 1, 1964 (Exhibit 13-
K1 to the Parent's Form S-1, (April 1967) File No. 2-
25597).
10.1.4.1 Additional Power Contract providing for extension on
contract term between CYAPC and CEL dated April 30, 1984
(Exhibit 5 to the CEL Form 10-Q (June 1984), File No. 2-
7909).
10.1.4.2 Second Supplementary Power Contract providing for
decommissioning financing between CYAPC and CEL dated
April 30, 1984 (Exhibit 6 to the CEL Form 10-Q (June
1984), File No. 2-7909).
10.1.5 Power contract between Vermont Yankee Nuclear Power
Corporation (VYNPC) and CEL dated February 1, 1968
(Exhibit 3 to the CEL 1984 Form 10-K, File No. 2-7909).
10.1.5.1 First Amendment dated June 1, 1972 (Section 7) and
Second Amendment dated April 15, 1983 (decommissioning
financing) to 10.1.5 (Exhibits 1 and 2, respectively, to
the CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.5.2 Third Amendment dated April 1, 1985 and Fourth Amendment
dated June 1, 1985 to 10.1.5 (Exhibits 1 and 2,
respectively, to the CEL Form 10-Q (June 1986), File No.
2-7909).
10.1.5.3 Fifth and Sixth Amendments to 10.1.5 dated February 1,
1968, both as amended May 6, 1988 (Exhibit 1 to the CEL
Form 10-Q (June 1988), File No. 2-7909).
10.1.5.4 Seventh Amendment to 10.1.5 dated February 1, 1968, as
amended June 15, 1989 (Exhibit 2 to the CEL Form 10-Q
(September 1989), File No. 2-7909).
10.1.5.5 Additional Power Contract dated February 1, 1984 between
CEL and VYNPC providing for decommissioning financing
and contract extension (Refiled as Exhibit 1 to CEL 1993
Form 10-K, File No. 2-7909).
10.1.6 Power contract between Maine Yankee Atomic Power Company
(MYAPC) and CEL dated May 20, 1968 (Exhibit 5 to the
Parent's Form S-7, File No. 2-38372).
10.1.6.1 First Amendment dated March 1, 1984 (decommissioning
financing) and Second Amendment dated January 1, 1984
(supplementary payments) to 10.1.6 (Exhibits 3 and 4 to
the CEL Form 10-Q (June 1984), File No. 2-7909).
10.1.6.2 Third Amendment to 10.1.6 dated October 1, 1984 (Exhibit
1 to the CEL Form 10-Q (September 1984), File No. 2-
7909).
10.1.7 Agreement between NBGEL and Boston Edison Company (BECO)
for the purchase of electricity from BECO's Pilgrim Unit
No. 1 dated August 1, 1972 (Exhibit 7 to the CE 1984
Form 10-K, File No. 2-7749).
10.1.7.1 Service Agreement between NBGEL and BECO for purchase of
stand-by power for BECO's Pilgrim Station dated August
16, 1978 (Exhibit 1 to the CE 1988 Form 10-K, File No. 2-
7749).
10.1.7.2 System Power Sales Agreement by and between CE and BECO
dated July 12, 1984 (Exhibit 1 to the CE Form 10-Q
(September 1984), File No. 2-7749).
10.1.7.3 Power Exchange Agreement by and between BECO and CE
dated December 1, 1984 (Exhibit 16 to the CE 1984 Form
10-K, File No. 2-7749).
10.1.7.4 Service Agreement for Non-Firm Transmission Service
between BECO and CEL dated July 5, 1984 (Exhibit 4 to
the CEL 1984 Form 10-K, File No. 2-7909).
10.1.8 Agreement for Joint-Ownership, Construction and
Operation of New Hampshire Nuclear Units (Seabrook)
dated May 1, 1973 (Exhibit 13(N) to the NBGEL Form S-1
dated October 1973, File No. 2-49013 and as amended
below:
10.1.8.1 First through Fifth Amendments to 10.1.8 as amended May
24, 1974, June 21, 1974, September 25, 1974, October 25,
1974 and January 31, 1975, respectively (Exhibit 13(m)
to the NBGEL Form S-1 (November 7, 1975), File No. 2-
54995).
10.1.8.2 Sixth through Eleventh Amendments to 10.1.8 as amended
April 18, 1979, April 25, 1979, June 8, 1979, October
11, 1979 and December 15, 1979, respectively (Refiled as
Exhibit 1 to the CEC 1989 Form 10-K, File No. 2-30057).
10.1.8.3 Twelfth through Fourteenth Amendments to 10.1.8 as
amended May 16, 1980, December 31, 1980 and June 1,
1982, respectively (Filed as Exhibits 1, 2, and 3 to the
CE 1992 Form 10-K, File No. 2-7749).
10.1.8.4 Fifteenth and Sixteenth Amendments to 10.1.8 as amended
April 27, 1984 and June 15, 1984, respectively (Exhibit
1 to the CEC Form 10-Q (June 1984), File No. 2-30057).
10.1.8.5 Seventeenth Amendment to 10.1.8 as amended March 8, 1985
(Exhibit 1 to the CEC Form 10-Q (March 1985), File No. 2-
30057).
10.1.8.6 Eighteenth Amendment to 10.1.8 as amended March 14, 1986
(Exhibit 1 to the CEC Form 10-Q (March 1986), File No. 2-
30057).
10.1.8.7 Nineteenth Amendment to 10.1.8 as amended May 1, 1986
(Exhibit 1 to the CEC Form 10-Q (June 1986), File No. 2-
30057).
10.1.8.8 Twentieth Amendment to 10.1.8 as amended September 19,
1986 (Exhibit 1 to the CEC 1986 Form 10-K, File No. 2-
30057).
10.1.8.9 Twenty-First Amendment to 10.1.8 as amended November 12,
1987 (Exhibit 1 to the CEC 1987 Form 10-K, File No. 2-
30057).
10.1.8.10 Settlement Agreement and Twenty-Second Amendment to
10.1.8, both dated January 13, 1989 (Exhibit 4 to the
CEC 1988 Form 10-K, File No. 2-30057).
10.1.9 Purchase and Sale Agreement together with an
implementing Addendum dated December 31, 1981, between
CE and CEC, for the purchase and sale of the CE 3.52%
joint-ownership interest in the Seabrook units, dated
January 2, 1981 (Refiled as Exhibit 4 to the CE 1992
Form 10-K, File No. 2-7749).
10.1.10 Agreement to transfer ownership, construction and
operational interest in the Seabrook Units 1 and 2 from
CE to CEC dated January 2, 1981 (Refiled as Exhibit 3 to
the 1991 CE Form 10-K, File No. 2-7749).
10.1.11 Power Contract, as amended to February 28, 1990,
superseding the Power Contract dated September 1, 1986
and amendment dated June 1, 1988, between CEC (seller)
and CE and CEL (purchasers) for seller's entire share of
the Net Unit Capability of Seabrook 1 and related energy
(Exhibit 1 to the CEC Form 10-Q (March 1990), File No. 2-
30057).
10.1.12 Capacity Acquisition Agreement between CEC, CEL and CE
dated September 25, 1980 (Refiled as Exhibit 1 to the
1991 CEC Form 10-K, File No. 2-30057).
10.1.12.1 Amendment to 10.1.12 as amended and restated June 1,
1993, henceforth referred to as the Capacity Acquisition
and Disposition Agreement, whereby Canal Electric
Company, as agent, in addition to acquiring power may
also sell bulk electric power which Cambridge Electric
Light Company and/or Commonwealth Electric Company owns
or otherwise has the right to sell (Exhibit 1 to Canal
Electric's Form 10-Q (September 1993), File No. 2-
30057).
10.1.13 Phase 1 Vermont Transmission Line Support Agreement and
Amendment No. 1 thereto between Vermont Electric
Transmission Company, Inc. and certain other New England
utilities, dated December 1, 1981 and June 1, 1982,
respectively (Exhibits 5 and 6 to the CE 1992 Form 10-K,
File No. 2-7749).
10.1.13.1 Amendment No. 2 to 10.1.13 as amended November 1, 1982
(Exhibit 5 to the CE Form 10-Q (June 1984), File No. 2-
7749).
10.1.13.2 Amendment No. 3 to 10.1.13 as amended January 1, 1986
(Exhibit 2 to the CE 1986 Form 10-K, File No. 2-7749).
10.1.14 Power Purchase Agreement between Pioneer Hydropower,
Inc. and CE for the purchase of available hydro-electric
energy produced by a facility located in Ware,
Massachusetts, dated September 1, 1983 (Refiled as
Exhibit 1 to the CE 1993 Form 10-K, File No. 2-7749).
10.1.15 Power Purchase Agreement between Corporation
Investments, Inc. (CI), and CE for the purchase of
available hydro-electric energy produced by a facility
located in Lowell, Massachusetts, dated January 10, 1983
(Refiled as Exhibit 2 to the CE 1993 Form 10-K, File No.
2-7749).
10.1.15.1 Amendment to 10.1.15 between CI and Boott Hydropower,
Inc., an assignee there from, and CE, as amended March
6, 1985 (Exhibit 8 to the CE 1984 Form 10-K, File No. 2-
7749).
10.1.16 Phase 1 Terminal Facility Support Agreement dated
December 1, 1981, Amendment No. 1 dated June 1, 1982 and
Amendment No. 2 dated November 1, 1982, between New
England Electric Transmission Corporation (NEET), other
New England utilities and CE (Exhibit 1 to the CE Form
10-Q (June 1984), File No. 2-7749).
10.1.16.1 Amendment No. 3 to 10.1.16 (Exhibit 2 to the CE Form 10-
Q (June 1986), File No. 2-7749).
10.1.17 Preliminary Quebec Interconnection Support Agreement
dated May 1, 1981, Amendment No. 1 dated September 1,
1981, Amendment No. 2 dated June 1, 1982, Amendment No.
3 dated November 1, 1982, Amendment No. 4 dated March 1,
1983 and Amendment No. 5 dated June 1, 1983 among
certain New England Power Pool (NEPOOL) utilities
(Exhibit 2 to the CE Form 10-Q (June 1984), File No. 2-
7749).
10.1.18 Agreement with Respect to Use of Quebec Interconnection
dated December 1, 1981, Amendment No. 1 dated May 1,
1982 and Amendment No. 2 dated November 1, 1982 among
certain NEPOOL utilities (Exhibit 3 to the CE Form 10-Q
(June 1984), File No. 2-7749).
10.1.18.1 Amendatory Agreement No. 3 to 10.1.18 as amended June 1,
1990, among certain NEPOOL utilities (Exhibit 1 to the
CEC Form 10-Q (September 1990), File No. 2-30057).
10.1.19 Phase I New Hampshire Transmission Line Support
Agreement between NEET and certain other New England
Utilities dated December 1, 1981 (Exhibit 4 to the CE
Form 10-Q (June 1984), File No. 2-7749).
10.1.20 Agreement, dated September 1, 1985, with Respect To
Amendment of Agreement With Respect To Use Of Quebec
Interconnection, dated December 1, 1981, among certain
NEPOOL utilities to include Phase II facilities in the
definition of ''Project'' (Exhibit 1 to the CEC Form 10-
Q (September 1985), File No. 2-30057).
10.1.21 Agreement to Preliminary Quebec Interconnection Support
Agreement-Phase II among Public Service Company of New
Hampshire (PSNH), New England Power Co. (NEP), BECO and
CEC whereby PSNH assigns a portion of its interests
under the original Agreement to the other three parties,
dated October 1, 1987 (Exhibit 2 to the CEC 1987 Form 10-
K, File No. 2-30057).
10.1.22 Preliminary Quebec Interconnection Support
Agreement-Phase II among certain New England electric
utilities dated June 1, 1984 (Exhibit 6 to the CE Form
10-Q (June 1984), File No. 2-7749).
10.1.22.1 First, Second and Third Amendments to 10.1.22 as amended
March 1, 1985, January 1, 1986 and March 1, 1987,
respectively (Exhibit 1 to the CEC Form 10-Q (March
1987), File No. 2-30057).
10.1.22.2 Fifth, Sixth and Seventh Amendments to 10.1.22 as
amended October 15, 1987, December 15, 1987 and March 1,
1988, respectively (Exhibit 1 to the CEC Form 10-Q (June
1988), File No. 2-30057).
10.1.22.3 Fourth and Eighth Amendments to 10.1.22 as amended July
1, 1987 and August 1, 1988, respectively (Exhibit 3 to
the CEC Form 10-Q (September 1988), File No. 2-30057).
10.1.22.4 Ninth and Tenth Amendments to 10.1.22 as amended
November 1, 1988 and January 15, 1989, respectively
(Exhibit 2 to the CEC 1988 Form 10-K, File No. 2-30057).
10.1.22.5 Eleventh Amendment to 10.1.22 as amended November 1,
1989 (Exhibit 4 to the CEC 1989 Form 10-K, File No. 2-
30057).
10.1.22.6 Twelfth Amendment to 10.1.22 as amended April 1, 1990
(Exhibit 1 to the CEC Form 10-Q (June 1990), File No. 2-
30057).
10.1.23 Phase II Equity Funding Agreement for New England Hydro-
Transmission Electric Company, Inc. (New England Hydro)
(Massachusetts), dated June 1, 1985, between New England
Hydro and certain NEPOOL utilities (Exhibit 2 to the CEC
Form 10-Q (September 1985), File No. 2-30057).
10.1.24 Phase II Massachusetts Transmission Facilities Support
Agreement dated June 1, 1985, refiled as a single
agreement incorporating Amendments 1 through 7 dated May
1, 1986 through January 1, 1989, respectively, between
New England Hydro and certain NEPOOL utilities (Exhibit
2 to the CEC Form 10-Q (September 1990), File No. 2-
30057).
10.1.25 Phase II New Hampshire Transmission Facilities Support
Agreement dated June 1, 1985, refiled as a single
agreement incorporating Amendments 1 through 8 dated May
1, 1986 through January 1, 1990, respectively, between
New England Hydro-Transmission Corporation (New
Hampshire Hydro) and certain NEPOOL utilities (Exhibit 3
to the CEC Form 10-Q (September 1990), File No. 2-
30057).
10.1.26 Phase II Equity Funding Agreement for New Hampshire
Hydro, dated June 1, 1985, between New Hampshire Hydro
and certain NEPOOL utilities (Exhibit 3 to the CEC Form
10-Q (September 1985), File No. 2-30057).
10.1.26.1 Amendment No. 1 to 10.1.26 dated May 1, 1986 (Exhibit 6
to the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.26.2 Amendment No. 2 to 10.1.26 as amended September 1, 1987
(Exhibit 3 to the CEC Form 10-Q (September 1987), File
No. 2-30057).
10.1.27 Phase II New England Power AC Facilities Support
Agreement, dated June 1, 1985, between NEP and certain
NEPOOL utilities (Exhibit 6 to the CEC Form 10-Q
(September 1985), File No. 2-30057).
10.1.27.1 Amendments Nos. 1 and 2 to 10.1.27 as amended May 1,
1986 and February 1, 1987, respectively (Exhibit 5 to
the CEC Form 10-Q (March 1987), File No. 2-30057).
10.1.27.2 Amendments Nos. 3 and 4 to 10.1.27 as amended June 1,
1987 and September 1, 1987, respectively (Exhibit 5 to
the CEC Form 10-Q (September 1987), File No. 2-30057).
10.1.28 Agreement Authorizing Execution of Phase II Firm Energy
Contract, dated September 1, 1985, among certain NEPOOL
utilities in regard to participation in the purchase of
power from Hydro-Quebec (Exhibit 8 to the CEC Form 10-Q
(September 1985), File No. 2-30057).
10.1.29 Agreements by and between Swift River Company and CE for
the purchase of available hydro-electric energy to be
produced by units located in Chicopee and North
Willbraham, Massachusetts, both dated September 1, 1983
(Exhibits 11 and 12 to the CE 1984 Form 10-K, File No. 2-
7749).
10.1.30 Power Purchase Agreement by and between SEMASS
Partnership, as seller, to construct, operate and own a
solid waste disposal facility at its site in Rochester,
Massachusetts and CE, as buyer of electric energy and
capacity, dated September 8, 1981 (Exhibit 17 to the CE
1984 Form 10-K, File No. 2-7749).
10.1.30.1 Power Sales Agreement to 10.1.30 for all capacity and
related energy produced, dated October 31, 1985 (Exhibit
2 to the CE 1985 Form 10-K, File No. 2-7749).
10.1.30.2 Amendment to 10.1.30 for all additional electric
capacity and related energy to be produced by an
addition to the Original Unit, dated March 14, 1990
(Exhibit 1 to the CE Form 10-Q (June 1990), File No. 2-
7749).
10.1.30.3 Amendment to 10.1.30 for all additional electric
capacity and related energy to be produced by an
addition to the Original Unit, dated May 24, 1991
(Exhibit 1 to CE Form 10-Q (June 1991), File No. 2-
7749).
10.1.31 Power Sale Agreement by and between CE (buyer) and
Northeast Energy Associated, Ltd. (NEA) (seller) of
electric energy and capacity, dated November 26, 1986
(Exhibit 1 to the CE Form 10-Q (March 1987), File No. 2-
7749).
10.1.31.1 First Amendment to 10.1.31 as amended August 15, 1988
(Exhibit 1 to the CE Form 10-Q (September 1988), File
No. 2-7749).
10.1.31.2 Second Amendment to 10.1.31 as amended January 1, 1989
(Exhibit 2 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.31.3 Power Sale Agreement dated August 15, 1988 between NEA
and CE for the purchase of 21 MW of electricity (Exhibit
2 to the CE Form 10-Q (September 1988), File No. 2-
7749).
10.1.31.4 Amendment to 10.1.31.3 as amended January 1, 1989
(Exhibit 3 to the CE 1988 Form 10-K, File No. 2-7749).
10.1.32 Power Purchase Agreement and First Amendment, dated
September 5, 1989 and August 3, 1990, respectively, by
and between Commonwealth Electric (buyer) and Dartmouth
Power Associates Limited Partnership (seller), whereby
buyer will purchase all of the energy (67.6 MW) produced
by a single gas turbine unit (Exhibit 1 to the CE Form
10-Q (June 1992), File No. 2-7749).
10.1.32.1 Second Amendment, dated June 23, 1994, to 10.1.50 by and
between Commonwealth Electric Company and Dartmouth
Power Associates, L.P. dated September 5, 1989 (Exhibit
4 to the CE Form 10-Q (June 1995), File No. 2-7749).
10.1.33 Power Purchase Agreement by and between Masspower
(seller) and Commonwealth Electric Company (buyer) for a
11.11% entitlement to the electric capacity and related
energy of a 240 MW gas-fired cogeneration facility,
dated February 14, 1992 (Exhibit 1 to Commonwealth
Electric's Form 10-Q (September 1993), File No. 2-7749).
10.1.34 Power Sale Agreement by and between Altresco Pittsfield,
L.P. (seller) and Commonwealth Electric Company (buyer)
for a 17.2% entitlement to the electric capacity and
related energy of a 160 MW gas-fired cogeneration
facility, dated February 20, 1992 (Exhibit 2 to
Commonwealth Electric's Form 10-Q (September 1993), File
No. 2-7749).
10.1.34.1 System Exchange Agreement by and among Altresco
Pittsfield, L.P., Cambridge Electric Light Company,
Commonwealth Electric Company and New England Power
Company, dated July 2, 1993 (Exhibit 3 to Commonwealth
Electric's Form 10-Q (September 1993), File No 2-7749).
10.1.34.2 Power Sale Agreement by and between Altresco Pittsfield,
L. P. (seller) and Cambridge Electric Light Company
(Cambridge Electric) (buyer) for a 17.2% entitlement to
the electric capacity and related energy of a 160 MW gas-
fired cogeneration facility, dated February 20, 1992
(Exhibit 1 to Cambridge Electric's Form 10-Q (September
1993), File No. 2-7909).
10.1.34.3 First Amendment, dated November 7, 1994, to 10.1.34 by
and between Commonwealth Electric Company and Altresco
Pittsfield, L.P. dated February 20, 1992 (Filed as
Exhibit 3 to Commonwealth Electric Company's Form 10-Q
(June 1995), File 2-7749).
10.1.34.4 First Amendment, dated November 7, 1994, to 10.1.34.2 by
and between Cambridge Electric Light Company and
Altresco Pittsfield, L.P. dated February 20, 1992 (Filed
as Exhibit 2 to Cambridge Electric Light Company's Form
10-Q (June 1995), File 2-7909).
10.2.1 Transportation Agreement between CNG and CG to provide
for transportation of natural gas on a daily basis from
Steuben Gas Storage Company to TGP (Exhibit 10 to the CG
1991 Form 10-K, File No. 2-1647).
10.3.1 Employees Savings Plan of Commonwealth Energy System and
Subsidiary Companies as amended and restated January 1,
1993 (Exhibit 2 to CES Form 10-Q (September 1993), File
No. 1-7316).
10.3.1.1 First Amendment to 10.3.1, effective October 1, 1994.
(Exhibit 1 to CES Form S-8 (January 1995), File No. 1-
7316).
10.3.1.2 Second Amendment to 10.3.1, effective April 1, 1996
(Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 30,
1996), File No. 1-7316).
10.3.1.3 Third Amendment to 10.3.1, effective January 1, 1997
(Exhibit 1 to CES Form 10-K/A Amendment No. 1 (April 29,
1997), File No. 1-7316).
10.3.2 New England Power Pool Agreement (NEPOOL) dated
September 1, 1971 as amended through August 1, 1977,
between NEGEA Service Corporation, as agent for CEL,
CEC, NBGEL, and various other electric utilities
operating in New England together with amendments dated
August 15, 1978, January 31, 1979 and February 1, 1980.
(Exhibit 5(c)13 to New England Gas and Electric
Association's Form S-16 (April 1980), File No. 2-64731).
10.3.2.1 Thirteenth Amendment to 10.3.2 as amended September 1,
1981 (Refiled as Exhibit 3 to the Parent's 1991 Form 10-
K, File No. 1-7316).
10.3.2.2 Fourteenth through Twentieth Amendments to 10.3.2 as
amended December 1, 1981, June 1, 1982, June 15, 1983,
October 1, 1983, August 1, 1985, August 15, 1985 and
September 1, 1985, respectively (Exhibit 4 to the CES
Form 10-Q (September 1985), File No. 1-7316).
10.3.2.3 Twenty-first Amendment to 10.3.2 as amended to January
1, 1986 (Exhibit 1 to the CES Form 10-Q (March 1986),
File No. 1-7316).
10.3.2.4 Twenty-second Amendment to 10.3.2 as amended to
September 1, 1986 (Exhibit 1 to the CES Form 10-Q
(September 1986), File No. 1-7316).
10.3.2.5 Twenty-third Amendment to 10.3.2 as amended to April 30,
1987 (Exhibit 1 to the CES Form 10-Q (June 1987), File
No. 1-7316).
10.3.2.6 Twenty-fourth Amendment to 10.3.2 as amended March 1,
1988 (Exhibit 1 to the CES Form 10-Q (March 1989), File
No. 1-7316).
10.3.2.7 Twenty-fifth Amendment to 10.3.2 as amended to May 1,
1988 (Exhibit 1 to the CES Form 10-Q (March 1988), File
No. 1-7316).
10.3.2.8 Twenty-sixth Agreement to 10.3.2 as amended March 15,
1989 (Exhibit 1 to the CES Form 10-Q (March 1989), File
No. 1-7316).
10.3.2.9 Twenty-seventh Agreement to 10.3.2 as amended October 1,
1990 (Exhibit 3 to the CES 1990 Form 10-K, File No. 1-
7316).
10.3.2.10 Twenty-eighth Agreement to 10.3.2 as amended September
15, 1992 (Exhibit 1 to the CES Form 10-Q (September
1994), File No. 1-7316).
10.3.2.11 Twenty-ninth Agreement to 10.3.2 as amended May 1, 1993
(Exhibit 2 to the CES Form 10-Q (September 1994), File
No. 1-7316).
Cambridge Electric Light Company
Exhibit 4 Instruments Defining the Rights of Security Holders,
Including Indentures
4.2.1 Original Indenture on Form S-1 (April, 1949) (Exhibit
7(a), File No. 2-7909).
4.2.2 Third Supplemental on Form 10-K (1984) (Exhibit 1, File
No. 2-7909).
4.2.3 Fourth Supplemental on Form 10-K (1984) (Exhibit 2, File
No. 2-7909).
4.2.4 Sixth Supplemental on Form 10-Q (June 1989) (Exhibit 1,
File No. 2-7909).
4.2.5 Seventh Supplemental on Form 10-Q (June 1992), (Exhibit
1, File No. 2-7909).
NSTAR Gas Company
Exhibit 4 Instruments Defining the Rights of Security Holders,
Including Indentures
4.4.1 Original Indenture on Form S-1 (Feb., 1949) (Exhibit
7(a), File No. 2-7820).
4.4.2 Sixteenth Supplemental on Form 10-K (1986) (Exhibit 1,
File No. 2-1647).
4.4.3 Seventeenth Supplemental on Form 10-K (1990) (Exhibit 2,
File No. 2-1647).
4.4.4 Eighteenth Supplemental on Form 10-Q (March 1994)
(Exhibit 1, File No. 2-1647).
4.4.5 Nineteenth Supplemental on Form 10-K (1997) (Exhibit 1,
File No. 2-1647).
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 and 1998
(Dollars in Thousands)
Additions Deductions
Balance at Provisions Balance
Beginning Charged to Accounts at End
Description of Year Operations Recoveries Written Off the Year
Year Ended December 31, 2000
Allowance for Doubtful Accounts $23,836 $ 18,920 $ 2,525 $ 16,972 $28,309
Year Ended December 31, 1999
Allowance for Doubtful Accounts $14,227(a) $ 24,437 $ 5,260 $ 20,088 $23,836
Year Ended December 31, 1998
Allowance for Doubtful Accounts $10,298 $ 9,555 $ 4,242 $ 14,959 $ 9,136
(a) The beginning balance includes $5,091,000 that relates to
COM/Energy's reserve balance at the merger date of August
25, 1999.
FORM 10-K NSTAR
DECEMBER 31, 2000
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned,
thereunto duly authorized.
NSTAR
Date: March 22, 2001 By: /s/ James J. Judge
James J. Judge
Senior Vice President,
Treasurer and Chief Financial
Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities indicated on
the 22nd day of March 2001.
Signature Title
/s/ Thomas J. May Chairman of the Board and
Chief Executive Officer
Thomas J. May
/s/ Robert J. Weafer, Jr. Vice President, Controller
and Chief Accounting
Officer
Robert J. Weafer, Jr.
/s/ Kevin C. Bryant Trustee
Kevin C. Bryant
/s/ Sheldon A. Buckler Trustee
Sheldon A. Buckler
/s/ Gary L. Countryman Trustee
Gary L. Countryman
/s/ Thomas G. Dignan, Jr. Trustee
Thomas G. Dignan, Jr.
/s/ Charles K. Gifford Trustee
Charles K. Gifford
/s/ Nelson S. Gifford Trustee
Nelson S. Gifford
/s/ Matina S. Horner Trustee
Matina S. Horner
/s/ Franklin M. Hundley Trustee
Franklin M. Hundley
/s/ Paul A. La Camera Trustee
Paul A. La Camera
/s/ Thomas J. May Trustee
Thomas J. May
/s/ Sherry H. Penney Trustee
Sherry H. Penney
/s/ Gerald L. Wilson Trustee
Gerald L. Wilson
/s/ Russell D. Wright Trustee
Russell D. Wright